10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM              TO             

Commission file number 1-3701

 

 

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)

 

 

 

Washington   91-0462470

(State or other jurisdiction of

incorporation or organization)

 

(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: http://www.avistacorp.com

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Class

 

Name of Each Exchange

on Which Registered

Common Stock, no par value, together with

Preferred Share Purchase Rights appurtenant thereto

  New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

 

Title of Class
Preferred Stock, Cumulative, Without Par Value

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act .    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:    Yes  x     No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  x    Accelerated filer                   ¨
Non-accelerated filer    ¨ (Do not check if a smaller reporting company)    Smaller reporting company  ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  ¨    No  x

The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,148,013,859 based on the last reported sale price thereof on the consolidated tape on June 30, 2008.

As of January 31, 2009, 54,629,586 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Documents Incorporated By Reference

 

Document

 

Part of Form 10-K into Which

Document is Incorporated

Proxy Statement to be filed in

connection with the annual meeting

of shareholders to be held May 7, 2009

 

Part III, Items 10, 11,

12, 13 and 14

 

 

 


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AVISTA CORPORATION

 

 

INDEX

Item No.

   Page No.
   Acronyms and Terms    iii
   Part I   
   Available Information    1
1.    Business    1
  

Company Overview

   1
  

Avista Utilities

   3
  

General

   3
  

Electric Operations

   3
  

Electric Requirements

   3
  

Electric Resources

   4
  

Hydroelectric Relicensing

   5
  

Future Resource Needs

   6
  

Natural Gas Operations

   7
  

Regulatory Issues

   8
  

Industry Developments

   9
  

Environmental Issues

   10
  

Avista Utilities Operating Statistics

   12
  

Advantage IQ

   14
  

Other Businesses

   14
1A.    Risk Factors    15
1B.    Unresolved Staff Comments    19
2.    Properties    20
  

Avista Utilities

   20
3.    Legal Proceedings    21
4.    Submission of Matters to a Vote of Security Holders    21
Part II   
5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    22
6.    Selected Financial Data    23
7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    24
  

Forward-Looking Statements

   24
  

Potential Holding Company Formation

   25
  

Business Segments

   25
  

Executive Level Summary

   26
  

Avista Utilities – Electric Resources

   29
  

Settlement with the Coeur d’Alene Tribe

   29
  

Avista Utilities – Regulatory Matters

   29
  

Results of Operations

   33
  

Avista Utilities

   35
  

Advantage IQ

   40
  

Other Businesses

   40
  

New Accounting Standards

   40
  

Critical Accounting Policies and Estimates

   42
  

Liquidity and Capital Resources

   45
  

Review of Cash Flow Statement

   45
  

Overall Liquidity

   46
  

Credit and Nonperformance Risk

   47
  

Capital Resources

   47
  

Off-Balance Sheet Arrangements

   49
  

Spokane Energy, LLC

   49
  

Credit Ratings

   50
  

Pension Plan

   50

 

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Dividends

   50  
  

Avista Utilities Operations

   51  
  

Advantage IQ Operations

   51  
  

Other Operations

   52  
  

Contractual Obligations

   52  
  

Competition

   53  
  

Business Risk

   53  
  

Risk Management

   57  
  

Economic and Utility Load Growth

   57  
  

Succession Planning

   58  
  

Environmental Issues and Other Contingencies

   58  

7A.

  

Quantitative and Qualitative Disclosures about Market Risk

   59  

8.

  

Financial Statements and Supplementary Data

   59  
  

Report of Independent Registered Public Accounting Firm

   60  
  

Financial Statements

   61-67  
  

Consolidated Statements of Income

   61  
  

Consolidated Statements of Comprehensive Income

   62  
  

Consolidated Balance Sheets

   63-64  
  

Consolidated Statements of Cash Flows

   65-66  
  

Consolidated Statements of Stockholders’ Equity

   67  
  

Notes to Consolidated Financial Statements

   68  

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   111 *

9A.

  

Controls and Procedures

   111  

9B.

  

Other Information

   113  
Part III   

10.

  

Directors, Executive Officers and Corporate Governance

   113  

11.

  

Executive Compensation

   115  

12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   115  

13.

  

Certain Relationships and Related Transactions, and Director Independence

   116  

14.

  

Principal Accounting Fees and Services

   116  
Part IV   

15.

  

Exhibits, Financial Statement Schedules

   116  
  

Signatures

   117  
  

Exhibit Index

   118  

 

* = not an applicable item in the 2008 calendar year for the Company

 

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ACRONYMS AND TERMS

(The following acronyms and terms are found in multiple locations within the document)

 

Acronym/Term

  

Meaning

aMW

  

-   Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time

AFUDC

  

-   Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period

AM&D

  

-   Advanced Manufacturing and Development, does business as METALfx

APB

  

-   Accounting Principles Board

Advantage IQ

  

-   Advantage IQ, Inc., provider of facility information and cost management services for multi-site customers throughout North America, subsidiary of Avista Capital

Avista Capital

  

-   Parent company to the Company’s non-utility businesses

Avista Corp.

  

-   Avista Corporation, the Company

Avista Energy

  

-   Avista Energy, Inc., an electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital

Avista Utilities

  

-   operating division of Avista Corp. comprising the regulated utility operations

BPA

  

-   Bonneville Power Administration

Capacity

  

-   the rate at which a particular generating source is capable of producing energy, measured in KW or MW

Cabinet Gorge

  

-   the Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho

Colstrip

  

-   the coal-fired Colstrip Generating Plant in southeastern Montana

Coyote Springs 2

  

-   the natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon

CT

  

-   Combustion turbine

Deadband or ERM deadband

  

-   the first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the Energy Recovery Mechanism in the state of Washington.

Dekatherm

  

-   Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy)

DOE

  

-   the state of Washington’s Department of Ecology

Energy

  

-   the amount of electricity produced or consumed over a period of time, measured in KWH or MWH

EITF

  

-   Emerging Issues Task Force

ERM

  

-   the Energy Recovery Mechanism in the state of Washington

 

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FASB

  

-   Financial Accounting Standards Board

FIN

  

-   Financial Accounting Standards Board Interpretation

FERC

  

-   Federal Energy Regulatory Commission

IPUC

  

-   Idaho Public Utilities Commission

Jackson Prairie

  

-   Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington

KV

  

-   Kilovolt or 1000 volts, a measure of capacity on transmission lines

KW, KWH

  

-   Kilowatt or 1000 watts a measure of generating output, kilowatt-hour or 1000 watt hours a measure of energy produced

Lancaster Plant

  

-   a natural gas-fired combined cycle combustion turbine plant located in Idaho

MW, MWH

  

-   Megawatt or 1000 KW, megawatt-hour or 1000 KWH

NERC

  

-   North American Electricity Reliability Council

Noxon Rapids

  

-   the Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana

OASIS

  

-   Open Access Same-Time Information System

OPUC

  

-   The Public Utility Commission of Oregon

PCA

  

-   the Power Cost Adjustment mechanism in the state of Idaho

PLP

  

-   Potentially liable party

PUD

  

-   Public Utility District

PURPA

  

-   the Public Utility Regulatory Policies Act of 1978

RTO

  

-   Regional Transmission Organization

SFAS

  

-   Statement of Financial Accounting Standards

Spokane River Project

  

-   the five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls)

Therm

  

-   Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)

Watt

  

-   Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt

WUTC

  

-   Washington Utilities and Transportation Commission

 

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PART I

Our Annual Report on Form 10-K contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements” on pages 24-25. Forward-looking statements are all statements except those of historical fact, including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. Forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.

Available Information

Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available at our Web site as soon as practicable after electronically filing these reports with the Securities and Exchange Commission. Information contained on our Web site is not part of this report.

Item  1. Business

Company Overview

Avista Corporation (Avista Corp. or the Company), incorporated in the state of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. As of December 31, 2008, we employed 1,482 people in our utility operations and 645 people in our subsidiary businesses. Our corporate headquarters are in Spokane, Washington, the hub of the Inland Northwest. Agriculture, mining and lumber were the primary industries in the Inland Northwest for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors are growing in importance.

We have two reportable business segments as follows:

 

 

Avista Utilities – an operating division of Avista Corp. comprising our regulated utility operations that started in 1889. Our utility generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

 

 

Advantage IQ – an indirect subsidiary of Avista Corp. that provides sustainable utility expense management solutions, partnering with multi-site companies across North America to assess and manage utility costs and usage. Primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills as well as strategic management services.

In prior periods, we had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy, Inc. (Avista Energy), an indirect subsidiary of Avista Corp. On June 30, 2007, Avista Energy and Avista Energy Canada, Ltd. completed the sale of substantially all of their contracts and ongoing operations to Shell Energy North America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho (Lancaster Plant). The Lancaster Plant is owned by an unrelated third-party and all of the output from the plant is contracted to Avista Energy through 2026. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, we expect these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

We have other businesses including sheet metal fabrication, venture fund investments and real estate investments. These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx. Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy.

 

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Advantage IQ, Avista Energy, and the various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital), which is wholly owned by Avista Corp. Our total common stockholders’ equity was $996.9 million as of December 31, 2008, of which $77.5 million represented our investment in Avista Capital.

Our organization is illustrated below:

LOGO

AVA Formation Corp. (AVA) is the company formed for purposes of completing the potential statutory share exchange and holding company implementation. AVA is currently a subsidiary of Avista Corporation. For further information, see “Note 28 of the Notes to Consolidated Financial Statements.”

See “Item 6. Selected Financial Data” and “Note 30 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).

 

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Avista Utilities

General

Through our regulated utility operations, we generate, transmit and distribute electricity and distribute natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. We also engage in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.

Our utility provides electric distribution and transmission, as well as natural gas distribution services in parts of eastern Washington and northern Idaho. We also provide natural gas distribution service in parts of northeast and southwest Oregon. At the end of 2008, we supplied retail electric service to 355,000 customers and retail natural gas service to 314,000 customers across our entire service territory. See “Item 2. Properties” for further information with respect to our utility assets.

Electric Operations

In addition to providing electric distribution and transmission services, we generate electricity from facilities that we own and we purchase capacity and energy and fuel for generation under long-term and short-term contracts. We also sell capacity and energy, including surplus fuel in the wholesale market in connection with our resource optimization activities as described below.

We engage in an ongoing process of resource optimization. This involves the economic selection from available energy resources to serve load obligations and using these resources to capture available economic value. We sell and purchase wholesale electric capacity and energy and fuel as part of the process of acquiring resources to serve our load obligations. These transactions range from terms of one hour up to multiple years. We make continuing projections of:

 

   

electric loads at various points in time (ranging from one hour to multiple years) based on, among other things, estimates of factors such as customer usage and weather as well as historical data and contract terms, and

 

   

resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms and experience.

On the basis of these projections, we make purchases and sales of energy to match expected resources to expected electric load requirements. Resource optimization involves our generating plant dispatch and scheduling available resources, and also includes transactions such as:

 

   

purchasing fuel for generation,

 

   

when economic, selling fuel and substituting wholesale purchases for the operation of our resources, and

 

   

other wholesale transactions to capture the value of generation and transmission resources.

The optimization process includes entering into hedging transactions to manage risks.

Our generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Our Open Access Same-Time Information System (OASIS) is part of the Joint Transmission Services Information Network that covers much of the United States. Transmission revenues were $9.5 million in 2008, $10.6 million in 2007 and $10.5 million in 2006.

Electric Requirements

Our peak electric native load requirement for 2008 occurred on December 16, 2008 at which time our total load was 2,383 MW consisting of:

 

   

native load of 1,821 MW,

 

   

long-term wholesale obligations of 270 MW, and

 

   

short-term wholesale obligations of 292 MW.

At that time our maximum resource capacity available was 2,480 MW, which included:

 

   

company-owned electric generation of 1,489 MW,

 

   

long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 132 MW,

 

   

other long-term wholesale contracts of 252 MW, and

 

   

short-term wholesale purchases of 607 MW.

 

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Electric Resources

We have a diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges.

At the end of 2008, our facilities had a total net capability of 1,768 MW, of which 56 percent was hydroelectric and 44 percent was thermal. See “Item 2. Properties” for detailed information with respect to generating facilities.

Hydroelectric Resources We own and operate six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is our lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 538 average megawatts (aMW) (or 4.7 million MWhs). Hydroelectric resources provided 535 aMW for 2008, 519 aMW for 2007 and 561 aMW for 2006.

The following table shows our hydroelectric generation (in thousands of MWhs) during the year ended December 31:

 

     2008    2007    2006

Noxon Rapids

   1,696    1,591    1,824

Cabinet Gorge

   1,081    1,088    1,146

Post Falls

   85    83    97

Upper Falls

   78    63    69

Monroe Street

   104    100    106

Nine Mile

   105    100    110

Long Lake

   497    471    553

Little Falls

   205    193    223
              

Total company-owned hydroelectric generation

   3,851    3,689    4,128

Long-term hydroelectric contracts with PUDs

   833    861    787
              

Total hydroelectric generation

   4,684    4,550    4,915
              

Thermal Resources We own:

 

   

the combined cycle combustion turbine (CT) natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon,

 

   

a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana,

 

   

a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington,

 

   

a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT),

 

   

a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and

 

   

two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT).

Coyote Springs 2, which is operated by Portland General Electric Corporation, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with unilateral renewal rights.

Colstrip, which is operated by PPL Montana, LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019.

The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. Natural gas may be used as an alternate fuel. A combination of long-term contracts and spot purchases has provided, and is expected to meet fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. We did not operate these generating units significantly in 2008, 2007 and 2006. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

 

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The following table shows our thermal generation (in thousands of MWhs) during the year ended December 31:

 

     2008    2007    2006

Coyote Springs 2

   1,696    1,623    1,459

Colstrip

   1,758    1,673    1,579

Kettle Falls GS

   201    299    354

Northeast CT and Rathdrum CT

   15    20    24

Boulder Park and Kettle Falls CT

   23    25    18
              

Total thermal generation

   3,693    3,640    3,434
              

Purchases, Exchanges and Sales We purchase and sell power under various long-term contracts. We also enter into short-term purchases and sales. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process.

Pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA), we are required to purchase generation from qualifying facilities, including small hydroelectric and cogeneration projects, at rates approved by the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC). These contracts expire at various times between 2015 and 2027. In February 2006, the PURPA was amended by the Federal Energy Regulatory Commission (FERC) as required by the Energy Policy Act of 2005 (Energy Policy Act). These amendments are not expected to have an effect on our PURPA-related contracts.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2008, 2007 and 2006.

Hydroelectric Relicensing

We are a licensee under the Federal Power Act as administered by the FERC, which includes regulation of hydroelectric generation resources. Except for the Little Falls Plant, all of our hydroelectric plants are regulated by the FERC through project licenses. The licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.

In March 2001, we received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids). The Clark Fork Settlement Agreement that was entered into during 1999 and incorporated into the FERC license preserved the projects’ economic peaking and load following operations. Also, as part of the Clark Fork Settlement Agreement, we initiated the implementation of protection, mitigation and enhancement measures in March 1999. Measures in the agreement address issues related to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion.

See “Clark Fork Settlement Agreement” in “Note 26 of the Notes to Consolidated Financial Statements” for disclosure of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway and our mitigation plans and efforts.

We own and operate six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 144.1 MW) are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Since the FERC was unable to issue new license orders prior to the August 1, 2007 (and subsequent August 1, 2008) expiration of the current license, an annual license was issued for all five plants, in effect extending the current license and its conditions until August 1, 2009. We have no reason to believe that Spokane River Project operations will be interrupted in any manner relative to the timing of the FERC’s actions.

We filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups lasted through July 2005, when we filed our new license applications with the FERC. We initially requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, separately from the other four hydroelectric plants due to the complexity of issues related to the Post Falls development. In the license applications, we proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River. FERC licenses are granted for terms of 30 to 50 years.

Since our July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages of processing the applications. In May 2006, the FERC issued a notice requesting other parties to provide terms and conditions regarding the two license applications. In response to that notice, a number of parties including the Coeur d’Alene Tribe (the Tribe), the state of Idaho, Washington state agencies, and the United States Department of Interior (DOI)) filed either recommended terms and conditions, pursuant to Sections 10(a) and 10(j) of the Federal Power Act

 

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(FPA), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e) of the FPA. In January 2007, the FERC issued a draft Environmental Impact Statement (EIS). After review of comments, the FERC issued a final EIS in July 2007. This was the last administrative step for the FERC before the issuance of license orders; however, the FERC was unable to move forward prior to Federal Clean Water Act 401 Water Quality Certifications (Certifications) being issued by the states of Idaho and Washington.

The states of Idaho and Washington issued Certifications for the Project on June 5, 2008 and June 10, 2008, respectively. The Idaho Certification was based on a Settlement Agreement between Avista Corp., Idaho Department of Environmental Quality and the Idaho Department of Fish and Game, and is final. The Washington Certification, which was issued by the Washington Department of Ecology (Ecology), however, was appealed by Avista Corp., Inland Empire Paper and the Sierra Club/Center for Environmental Law and Policy. All issues, with the exception of one appealed by the Sierra Club/Center for Environmental Law and Policy (aesthetic spills at the Upper Falls plant) were resolved through a four-party Settlement Agreement. We are continuing negotiations on the remaining issue. A hearing is scheduled before the Washington Pollution Control Hearing Board in August 2009 to address the remaining issue under appeal.

On December 16, 2008 Avista, the United States DOI, and the Tribe reached agreement resolving FPA Section 4(e) conditions, as well as the payment of annual charges under Section 10(e) of the FPA regarding Post Falls, which stores water on a portion of the Coeur d’Alene Indian Reservation. The three parties submitted a request to the FERC on January 29, 2009 to incorporate the agreed-upon terms and conditions in a new single 50-year license for all five Spokane River hydroelectric plants.

The United States Department of Fish and Wildlife concurred, via a letter to FERC on July 31, 2008, that the Spokane River Project is not likely to adversely affect any listed or threatened endangered species.

We can not determine exactly when the FERC will complete action on the applications. Once granted, a new license will describe the final conditions we will be responsible to implement, and the term for a new license.

Our estimate of the potential cost of the conditions proposed for the Spokane River Project, based on estimates of what it would cost to implement the recommendations and conditions included in the FERC’s final EIS and the numerous Settlement Agreements, total approximately $305 million over a 50-year period.

In addition, the December 16, 2008 settlement agreement between the Company and the Tribe resolved FPA Section 10(e), or storage payments related to the Post Falls hydroelectric facility. Under the agreement, we will pay the Coeur d’Alene Tribe $0.4 million annually for the first 20 years of a new FERC license and $0.7 million annually for the remainder of the license term for section 10(e) charges.

The WUTC approved, for future recovery, costs incurred in relicensing the Spokane River project, as well as the costs related to settlement with the Tribe. The WUTC approved deferred accounting treatment, with a carrying cost, until these costs are reflected in future retail rates. The IPUC approved similar deferred accounting treatment. Our general rate cases, filed in January 2009, reflect recovery of both the direct and deferred costs.

Future Resource Needs

We have operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed over hourly, daily, monthly and annual durations, which vary widely because of the factors that influence demand. The following is a forecast of our average annual energy requirements and resources for 2009, 2010, 2011 and 2012:

Forecasted Electric Energy Requirements and Resources

(aMW)

 

     2009    2010    2011    2012

Requirements:

           

System load

   1,119    1,148    1,171    1,189

Contracts for power sales

   140    139    139    139
                   

Total requirements

   1,259    1,287    1,310    1,328
                   

 

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     2009    2010    2011    2012

Resources:

           

Company-owned and contract hydro generation (1)

   555    537    520    508

Company-owned base load thermal generation (2)

   234    237    247    235

Company-owned other thermal generation (2)

   294    291    281    292

Contracts for power purchases

   367    604    521    487
                   

Total resources

   1,450    1,669    1,569    1,522
                   

Surplus resources

   191    382    259    194

Additional available energy (3)

   153    153    153    153
                   

Total surplus resources

   344    535    412    347
                   

 

(1) The forecast assumes near normal hydroelectric generation (decline is related to changes in contracts with PUDs).
(2) Excludes the Northeast CT and Rathdrum CT. We generally use these resources to meet electric load requirements due to either below normal hydroelectric generation or increased loads or outages at other generating facilities, and/or when operating costs are lower than short-term wholesale market prices.
(3) Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

In August 2007, we filed our 2007 Electric Integrated Resource Plan (IRP) with the WUTC and the IPUC. The IRP identifies a strategic resource portfolio that meets future electric load requirements, promotes environmental stewardship and meets our obligation to provide reliable electric service to customers at rates, terms and conditions that are fair, just, reasonable and sufficient. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Our preferred resource plan, which is part of the IRP, includes the addition of the following resources by 2017:

 

   

350 MW of natural gas generation,

 

   

300 MW of wind power,

 

   

87 MW of conservation,

 

   

38 MW of hydroelectric generation plant upgrades, and

 

   

35 MW of other renewable generation.

In response to new laws in the state of Washington regarding renewable resources and greenhouse gas emissions, the IRP excludes coal-based generation as a new resource. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

We are required to file an IRP every two years. We will file an IRP in 2009 and the Preferred Resource Strategy may change based upon market, legislative and regulatory changes.

All of the output from the Lancaster Plant is contracted to Avista Energy through 2026 under a power purchase agreement. Avista Energy assigned the majority of its rights and obligations under this agreement to Shell Energy through the end of 2009. Beginning in 2010, we expect that these rights and obligations will be transferred to our utility operations, subject to approval by the WUTC and the IPUC.

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of over $125 million with the majority of the costs expected to be incurred in 2013 and thereafter.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information with respect to existing laws, as well as potential legislation that could influence our future electric resource mix.

Natural Gas Operations

General We provide natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and parts of northeast and southwest Oregon.

Market prices for natural gas, like other commodities, continue to be volatile. To provide reliable supply and to manage the impact of volatile prices on our customers, we procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and over various time periods. We also use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years at multiple basins mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

 

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As part of the process of balancing natural gas retail load requirements to resources obtained through wholesale purchases, we engage in wholesale sales of natural gas. We also optimize natural gas resources by using excess resources and market opportunities to generate economic value that reduces retail rates. To the extent that our retail demand for natural gas is less than our available supply, or that we have under utilized interstate pipeline transportation capacity or excess storage capacity and there are price differentials that provide positive margins, we engage in wholesale sales of natural gas. These optimization activities increased significantly in 2008 as compared 2007. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system.

We make continuing projections of our natural gas loads and assess available natural gas resources. Forward natural gas contracts are typically for monthly delivery periods. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, we plan and execute a series of transactions to hedge a significant portion of our projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four years into the future with the highest volumes hedged for the current and most immediately upcoming gas operating year (November through October). We also purchase a significant portion of our gas supply requirements in short-term and spot markets. Natural gas resource optimization activities include:

 

   

wholesale market sales of surplus gas supplies,

 

   

purchases and sales of natural gas to use underutilized pipeline capacity, and

 

   

sales of excess natural gas storage capacity.

We also provide transportation service to certain large commercial and industrial natural gas customers who purchase natural gas through third party marketers. For these customers, we move their natural gas through our distribution system from the natural gas transmission pipeline delivery points to the customers’ premises. The total volume transported on behalf of our transportation customers for 2008, 2007 and 2006 was 148.7, 148.8 and 149.7 million therms. This represented 18 percent, 21 percent and 24 percent of total system deliveries.

Natural Gas Supply We purchase all of our natural gas in the wholesale market. We are connected to multiple supply basins in the western United States and western Canada through firm capacity delivery rights on five pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. We have interstate pipeline capacity to serve approximately 25 percent of natural gas supplies from domestic sources, with the remaining 75 percent from Canadian sources. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our source mix to vary.

Natural Gas Storage We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 239.5 million therms.

We also contract with Northwest Natural Gas for storage at the Mist Natural Gas storage facility. This contract is for 5 million therms of capacity and up to 150 million therms of deliverability. This contract expires on March 31, 2010.

Natural gas storage enables us to place natural gas into storage when prices are lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Avista Energy controls 30.3 million therms of our capacity at Jackson Prairie and in conjunction with the asset sales agreement has assigned this capacity to Shell Energy through April 30, 2011. After that date, it is our intent to transfer this capacity to Avista Utilities for use in utility operations subject to regulatory approval.

Regulatory Issues

General As a regulated public utility, we are subject to regulation by state utility commissions with respect to prices, accounting, the issuance of securities, and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the WUTC, the IPUC, the Public Utility Commission of Oregon (OPUC), and the Public Service Commission of the State of Montana (Montana Commission). Approval of the issuance of securities is not required from the Montana Commission. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission service and wholesale sales.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate

 

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base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. In general, a request of new rates is made on the basis of a “rate base” as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag between the time we incur costs and the time when we can start recovering the costs through rates.

Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Note 1 of Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes. See “Industry Developments” for additional information about deregulation, as well as changes with respect to transmission and wholesale electricity markets.

General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – General Rate Cases” for information on general rate case activity.

Power Cost Deferrals We defer the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the WUTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 1 – Power Cost Deferrals and Recovery Mechanisms of the Notes to Consolidated Financial Statements” for detailed information on power cost deferrals and recovery mechanisms in Washington and Idaho.

Purchased Gas Adjustment (PGA or Natural Gas Trackers) Under established regulatory practices in each respective state, we are allowed to adjust natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Purchased Gas Adjustments” and “Note 1 – Natural Gas Cost Deferrals and Recovery Mechanisms of the Notes to Consolidated Financial Statements” for detailed information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.

Industry Developments

Energy Policy Act of 2005 In August 2005, the Energy Policy Act was passed into law. The Energy Policy Act substantially affects the regulation of energy companies, including Avista Corp. Key provisions of the Energy Policy Act affecting us include, but are not limited to:

 

   

reform of the hydroelectric licensing process,

 

   

tax credits for incremental hydroelectric production placed into service before 2009,

 

   

implementation of mandatory reliability standards, and

 

   

authorization for the FERC to assess fines for non-compliance with FERC regulations and mandatory reliability standards.

The Energy Policy Act also has provisions related to the future operation and development of transmission systems and federal support for certain clean power initiatives and renewable energy technologies, including wind power generation. The Energy Policy Act repealed the Public Utility Holding Company Act of 1935 and, among other things:

 

   

granted the FERC and state utility commissions access to the books and records of holding company systems,

 

   

provides (upon request of a state commission or holding company system) for FERC review of allocations of costs of non-power goods and administrative services, and

 

   

modifies the jurisdiction of the FERC over certain mergers and acquisitions involving public utilities or holding companies.

The implementation of the Energy Policy Act requires proceedings at the state level and the development of regulations by the FERC, the Department of Energy and other federal agencies.

Federal Initiatives Related to Wholesale Competition Federal law promotes practices that open the electric wholesale energy market to competition. The FERC can require electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.

Public utilities operating under the Federal Power Act are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an OASIS to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC

 

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also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.

Regional Transmission Organizations FERC Order No. 2000 (issued in 2000) required all utilities subject to FERC regulation to file a proposal to form a Regional Transmission Organization (RTO), or a description of efforts to participate in an RTO, and any existing obstacles to RTO participation. While it has not formally withdrawn Order No. 2000, the FERC has issued orders and made public policy statements indicating its support for the development and formation of regional independently-governed transmission organizations developed by such regions, but that do not necessarily meet all of the RTO functions and characteristics outlined in Order No. 2000. These include FERC Order No. 890 (issued in 2007), which required transmission providers to implement a number of regional transmission planning coordination requirements.

We have participated in discussions with transmission providers and other stakeholders in the Pacific Northwest for several years regarding the possible formation of an RTO in the region. ColumbiaGrid, a Washington nonprofit membership corporation, was formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. ColumbiaGrid members, including Avista Corp., elected an independent slate of directors to a three-member board in August 2006. ColumbiaGrid’s responsibilities and related agreements with its members are currently being developed in a public process with broad participation. ColumbiaGrid’s transmission planning and expansion functional agreement was accepted by the FERC and has been signed by a number of Pacific Northwest parties, including Avista Corp. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid.

Reliability Standards As a result of a significant blackout in northeastern and midwestern United States in 2003, the North American Electric Reliability Council (NERC), in conjunction with the FERC, conducted a comprehensive investigation of the outage and issued certain reliability-related recommendations. These recommendations addressed compliance with existing national and regional standards and initiatives to prevent or mitigate future blackouts. In February 2005, the NERC Board of Trustees approved voluntary reliability standards with the goal of restating existing standards in a manner that is clear, unambiguous, measurable and enforceable.

In February 2006, the FERC issued its final rule on the certification rules for a single Electric Reliability Organization (ERO). The NERC has been approved as the ERO and now has the authority to establish and enforce reliability standards, and has the ability to delegate authority to regional entities for the purpose of establishing and enforcing reliability standards.

As of January 2009, the FERC has approved 102 NERC Reliability Standards, including eight western region standards, making up the set of legally enforceable standards for the United States’ bulk electric system. The first of these mandatory Reliability Standards became effective on June 18, 2007. We are required to self certify with regards to compliance with these mandatory standards. We are in compliance with these standards.

Global Climate Changes Rising concerns about long-term global climate changes could have a significant effect on our business. We continue to monitor and evaluate the possible adoption of national, regional, or state requirements with respect to global climate changes. These requirements could result in significant costs for us to comply with restrictions on carbon dioxide and other emissions. Such requirements could also preclude us from developing certain types of generating plants or entering into new contracts for the output from generating plants that do not meet these requirements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for further information.

Environmental Issues

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have an ownership interest are designed and operated in compliance with applicable environmental laws. Furthermore, we conduct periodic reviews of pertinent facilities and operations to insure compliance and to respond to or to anticipate emerging environmental issues. The Company’s Board of Directors has a committee to oversee environmental issues.

In addition to the information provided in this section, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for further information.

Fisheries A number of species of fish in the Northwest, including the Snake River sockeye salmon and fall chinook salmon, the Kootenai River white sturgeon, the upper Columbia River steelhead, the upper Columbia River spring chinook salmon and the bull trout, are listed as threatened or endangered under the Federal Endangered Species Act. Thus far, measures that were adopted and implemented to save the Snake River sockeye salmon and fall chinook salmon

 

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have not directly impacted generation levels at any of our hydroelectric facilities. We purchase power under long-term contracts with certain PUDs on the Columbia River that are directly impacted by ongoing mitigation measures for salmon and steelhead. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on our operations at this time. We cannot accurately predict the economic costs to us resulting from future actions. We received a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids in March 2001 that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, particularly bull trout, is a key part of the agreement. The result is a collaborative bull trout recovery program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. See “Hydroelectric Relicensing” on page 5 for further information.

Air Quality We must be in compliance with requirements under the Clean Air Act (CAA) and Clean Air Act Amendments (CAAA) in operating our thermal generating plants. We continue to monitor legislative developments at both the state and national level for potential further restrictions on sulfur dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercury emissions. Compliance with new and proposed requirements and possible additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities.

The most significant impacts on us, related to the CAA and the 1990 CAAA, pertain to Colstrip, which is a “Phase II” coal-fired plant for sulfur dioxide (SO2) under the CAAA. However, we do not expect Colstrip to be required to implement any additional SO2 mitigation in the foreseeable future in order to continue operations. Our other thermal projects are subject to various CAAA standards. Every five years each of the other thermal projects requires an updated operating permit (known as a Title V permit), which addresses, among other things, the compliance of the plant with the CAAA. The operating permit for the Rathdrum CT was renewed in 2006 (expires in 2011) and the operating permit for the Kettle Falls GS was renewed in 2007 (expires in 2012). Coyote Springs 2 was issued a renewed Title V permit in 2008 that expires in 2013. Boulder Park and the Northeast CT do not require a Title V permit based on their limited output and instead each has a synthetic minor permit that does not expire.

In 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants. The new rules set strict mercury emission limits by 2010, and put in place a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. The Company, along with the other owners of Colstrip, have completed the first phase of testing on two mercury control technologies. The joint owners of Colstrip were encouraged by preliminary results and believe that we will be able to comply with the Montana law without utilizing the temporary alternate emission limit provision. Preliminary estimates indicate that our share of installation capital costs will be $1.5 million and annual operating costs will increase by $2.9 million (beginning in late-2009). We will continue to seek recovery, through the ratemaking process, of the costs to comply with various air quality requirements.

Water Quality See “Clark Fork Settlement Agreement” in “Note 26 of the Notes to Consolidated Financial Statements” regarding dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge. See “Spokane River Relicensing” in “Note 26 of the Notes to Consolidated Financial Statements” for the Clean Water Act certifications for our relicensing of the Spokane River Project.

Other Environmental Issues See “Colstrip Generating Project Complaint,” and “Harbor Oil Inc. Site” in “Note 26 of the Notes to Consolidated Financial Statements” for information with respect to additional environmental issues.

 

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AVISTA UTILITIES OPERATING STATISTICS

 

     Years Ended December 31,  
     2008     2007     2006  

ELECTRIC OPERATIONS

      

ELECTRIC OPERATING REVENUES (Dollars in Thousands):

      

Residential

   $ 279,641     $ 251,357     $ 234,714  

Commercial

     247,714       224,179       221,193  

Industrial

     101,785       95,207       92,961  

Public street and highway lighting

     5,962       5,517       5,268  
                        

Total retail revenues

     635,102       576,260       554,136  

Wholesale revenues

     141,744       105,729       126,208  

Revenues from sales of fuel

     44,695       12,910       48,176  

Other revenues

     16,916       16,231       18,863  
                        

Total electric operating revenues

   $ 838,457     $ 711,130     $ 747,383  
                        

ELECTRIC ENERGY SALES (Thousands of MWhs):

      

Residential

     3,744       3,670       3,578  

Commercial

     3,188       3,132       3,110  

Industrial

     2,059       2,084       2,062  

Public street and highway lighting

     26       26       25  
                        

Total retail energy sales

     9,017       8,912       8,775  

Wholesale energy sales

     1,964       1,594       2,117  
                        

Total electric energy sales

     10,981       10,506       10,892  
                        

ELECTRIC ENERGY RESOURCES (Thousands of MWhs):

      

Hydro generation (from Company facilities)

     3,851       3,689       4,128  

Thermal generation (from Company facilities)

     3,693       3,640       3,434  

Purchased power - hydro generation from long-term contracts with PUDs

     833       861       787  

Purchased power - wholesale

     3,253       2,959       3,101  

Power exchanges

     (17 )     (18 )     35  
                        

Total power resources

     11,613       11,131       11,485  

Energy losses and Company use

     (632 )     (625 )     (593 )
                        

Total energy resources (net of losses)

     10,981       10,506       10,892  
                        

NUMBER OF ELECTRIC RETAIL CUSTOMERS (Average for Period):

      

Residential

     311,381       306,737       300,940  

Commercial

     39,075       38,488       37,912  

Industrial

     1,388       1,378       1,388  

Public street and highway lighting

     434       426       425  
                        

Total electric retail customers

     352,278       347,029       340,665  
                        

ELECTRIC RESIDENTIAL SERVICE AVERAGES:

      

Annual use per customer (KWh)

     12,023       11,965       11,888  

Revenue per KWh (in cents)

     7.47       6.85       6.56  

Annual revenue per customer

   $ 898.07     $ 819.45     $ 779.94  

ELECTRIC AVERAGE HOURLY LOAD (aMW)

     1,102       1,089       1,069  
                        

RESOURCE AVAILABILITY at time of system peak (MW):

      

Total requirements (winter):

      

Retail native load

     1,821       1,685       1,656  

Wholesale obligations

     562       367       431  
                        

Total requirements (winter)

     2,383       2,052       2,087  
                        

Total resource availability (winter)

     2,480       2,302       2,618  

Total requirements (summer):

      

Retail native load

     1,602       1,631       1,643  

Wholesale obligations

     431       381       588  
                        

Total requirements (summer)

     2,033       2,012       2,231  
                        

Total resource availability (summer)

     2,250       2,434       2,551  

COOLING DEGREE DAYS: (1)

      

Spokane, WA

      

Actual

     478       576       615  

30-year average

     394       394       394  

% of average

     121 %     146 %     156 %

 

(1) Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).

 

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AVISTA UTILITIES OPERATING STATISTICS

 

      Years Ended December 31,  
     2008     2007     2006  

NATURAL GAS OPERATIONS

      

NATURAL GAS OPERATING REVENUES (Dollars in Thousands):

      

Residential

   $ 276,386     $ 264,546     $ 257,753  

Commercial

     152,147       148,416       146,581  

Industrial and interruptible

     12,159       11,284       11,676  
                        

Total retail natural gas revenues

     440,692       424,246       416,010  

Wholesale revenues

     281,668       142,167       93,221  

Transportation revenues

     6,327       6,638       6,499  

Other revenues

     5,520       4,182       4,825  
                        

Total natural gas operating revenues

   $ 734,207     $ 577,233     $ 520,555  
                        

THERMS DELIVERED (Thousands of Therms):

      

Residential

     210,125       195,756       192,833  

Commercial

     128,224       121,557       120,989  

Industrial and interruptible

     12,196       10,833       11,040  
                        

Total retail

     350,545       328,146       324,862  

Wholesale

     345,916       223,084       154,884  

Transportation

     148,723       148,765       149,717  

Interdepartmental and Company use

     526       438       443  
                        

Total therms delivered

     845,710       700,433       629,906  
                        

SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):

      

Purchases

     710,137       561,277       483,038  

Storage - injections

     (76,491 )     (35,228 )     (17,892 )

Storage - withdrawals

     66,271       28,842       18,181  

Natural gas for transportation

     148,723       148,765       149,717  

Distribution system losses

     (2,930 )     (3,223 )     (3,138 )
                        

Total natural gas supply

     845,710       700,433       629,906  
                        

NUMBER OF NATURAL GAS RETAIL CUSTOMERS (Average for Period):

      

Residential

     277,892       273,415       267,345  

Commercial

     32,901       32,327       31,746  

Industrial and interruptible

     297       302       295  
                        

Total natural gas retail customers

     311,090       306,044       299,386  
                        

NATURAL GAS RESIDENTIAL SERVICE AVERAGES:

      

Annual use per customer (therms)

     756       716       721  

Revenue per therm (in dollars)

   $ 1.32     $ 1.35     $ 1.34  

Annual revenue per customer

   $ 994.58     $ 967.56     $ 964.12  

HEATING DEGREE DAYS: (1)

      

Spokane, WA

      

Actual

     7,052       6,539       6,332  

30-year average

     6,820       6,820       6,820  

% of average

     103 %     96 %     93 %

Medford, OR

      

Actual

     4,569       4,386       4,167  

30-year average

     4,533       4,533       4,533  

% of average

     101 %     97 %     92 %

 

(1) Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

 

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Advantage IQ

Our subsidiary, Advantage IQ provides sustainable utility expense management solutions to multi-site companies across North America to assess and manage utility costs and usage. Our invoice processing, auditing and payment services, coupled with energy procurement, comprehensive reporting and advanced analysis, provide the critical data clients need to balance the financial, social and environmental aspects of doing business.

As part of this process, Advantage IQ analyzes and audits invoices, then presents consolidated bills on-line, as well as processing payments for these expenses. Information gathered from invoices, providers and other customer-specific data allows Advantage IQ to provide its clients with in-depth analytical support, real-time reporting and consulting services.

Advantage IQ has secured five patents on its two critical business systems:

 

 

 

Facility IQ system, which provides operational information drawn from facility bills, and

 

 

 

AviTrack database, which processes and reports on information gathered from service providers to ensure that customers are receiving the most effective services at the proper price.

We are not aware of any claimed or threatened infringement on any of Advantage IQ’s patents issued to date and we expect to continue to expand and protect existing patents, as well as file additional patent applications for new products, services and process enhancements.

The following table presents key statistics for Advantage IQ:

 

     2008    2007    2006

Customers at year-end

     537      403      373

Billed sites at year-end

     417,078      199,088      199,752

Dollars of customer bills processed (in billions)

   $ 16.7    $ 12.5    $ 10.8

The 2008 amounts include customers and sites of Cadence Network, which was acquired by Advantage IQ in July 2008 (see “Note 5 of the Notes to Consolidated Financial Statements”).

Other Businesses

In prior periods, we had a reportable Energy Marketing and Resource Management segment. This segment primarily included the results of Avista Energy. On June 30, 2007, Avista Energy and its subsidiary, Avista Energy Canada, completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this business segment. Avista Energy Canada provided natural gas services to industrial and commercial customers in British Columbia, Canada.

The historical activities of Avista Energy included trading electricity and natural gas, the optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage and electric transmission and natural gas transportation arrangements.

This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. We expect these assets to eventually be transferred to our utility operations, subject to regulatory approval.

Our other businesses include AM&D doing business as METALfx, a subsidiary that performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, telecom and medical industries. Our other investments and operations include:

 

   

real estate investments (primarily commercial office buildings),

 

   

investments in venture capital funds and low income housing, and

 

   

the remaining investment in a previous fuel cell subsidiary of the Company.

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy.

 

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Item 1A. Risk Factors

Risk Factors

The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. Please also see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Our results of operations, financial condition and cash flows are significantly affected by weather.

Weather has a significant effect on our utility operations related to variations in temperatures and precipitation. Weather impacts include customer demand and operating revenues and the cost of energy we supply. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues.

Precipitation (consisting of snowpack and its melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly impact hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. There is a significantly higher cost for resources other than hydroelectric generation, and these costs can be greater than the retail revenue from the related energy delivered to customers.

Regional precipitation and snowpack conditions typically have a significant effect on the wholesale price of electricity. Plentiful hydroelectric generation typically depresses market prices, sometimes when we are selling surplus energy, while constrained hydroelectric generation typically elevates market prices, sometimes when we are purchasing energy. In general, high demand for electricity will generally increase both the quantity needed and price of fuel for generation and wholesale market prices. These price patterns typically fluctuate seasonally with regional supply and demand and they are exaggerated or moderated by the relative level of supply, fuel costs, and end user energy demand.

As a result of these factors operating in combination, our net cost of power supply – the difference between our generating and market purchases costs and revenue from wholesale sales – varies significantly because of weather.

Financial market conditions may impact our results and our liquidity

The deterioration in the financial markets and credit availability that arose in 2008 and the current state of the global, United States and regional economies could have an impact on our operations. We could experience increased borrowing costs or limited access to capital on reasonable terms. Additionally, we may experience an increase in uncollectible customer accounts and collection times. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Concerns about the regional or local economy may also influence the willingness of regulators to grant necessary rate increases to recover our costs.

The deterioration in the financial markets has also resulted in significant declines in the market values of assets held by our pension plan (which impacts the funded status of the plan) and will increase future funding obligations and pension expense.

We rely on access to credit from financial institutions for short-term borrowings.

We need to maintain access to adequate levels of credit with financial institutions for short-term liquidity. We have a $320 million committed line of credit, which is scheduled to expire in April 2011, and a $200 million committed line of credit, which is scheduled to expire in November 2009. We cannot predict whether we will have access to credit beyond the expiration dates. The line of credit agreements contain customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.

 

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We are dependent on our ability to access long-term capital markets.

We need to access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

We are subject to commodity price risk.

Our utility operations are affected by electric and natural gas commodity price risk. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.

Electricity prices are affected by a number of factors, including:

 

   

demand for electricity,

 

   

the number of market participants and the willingness of market participants to trade,

 

   

adequacy of generating reserve margins,

 

   

scheduled and unscheduled outages of generating facilities,

 

   

availability of streamflows for hydroelectric generation,

 

   

price and availability of fuel for thermal generating plants, and

 

   

disruptions of or constraints on transmission facilities.

Natural gas prices are affected by a number of factors, including:

 

   

amount of North American production and production capacity that can be delivered to our service areas,

 

   

level of imports and exports, particularly from Canada by pipeline and to a growing extent by LNG,

 

   

inventory levels and regional accessibility,

 

   

demand for natural gas, including natural gas as fuel for electric generation,

 

   

the number of market participants and the willingness of market participants to trade,

 

   

global energy markets, including oil or other natural gas substitutes, and

 

   

availability of pipeline capacity to transport natural gas from region to region.

Any combination of these factors that results in a shortage of energy generally causes the market price to move upward.

Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.

We regularly review the need for retail electric and natural gas rate changes in each state in which we provide service. We expect to periodically file for rate increases with regulatory agencies to recover our costs and provide a reasonable return to our shareholders. If regulators grant substantially lower rate increases than our requests in the future, it could have a negative effect on our operating revenues, net income and cash flows.

Deferred power and natural gas costs are subject to regulatory review; costs higher than those recovered in base rates reduce cash flows, and it may take several years for us to recover deferred costs.

We defer income statement recognition and current recovery from customers of certain power and natural gas costs that are higher than what is currently authorized by regulators. These excess power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and for the potential of disallowance by state regulators.

Despite the opportunity to eventually recover a substantial portion of power and natural gas costs, our operating cash flows are negatively affected until these costs are recovered from customers.

Relicensing our hydroelectric facilities located on the Spokane River at a cost-effective level with reasonable terms and conditions may not be possible.

We have six hydroelectric plants on the Spokane River, and five of these are under one FERC license. Collectively,

 

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these five plants are referred to as the Spokane River Project. Since the FERC was unable to issue new license orders prior to the August 1, 2007 (and subsequent August 1, 2008) expiration of the current license, an annual license was issued for all five plants, in effect extending the current license and its conditions until August 1, 2009.

The relicensing process for the Spokane River Project is a public regulatory process that involves complex natural resource, recreation and cultural issues. We cannot predict the terms and conditions that will ultimately be imposed by the FERC. The costs of these terms and conditions could have a negative effect on our operating expenses and require significant utility capital expenditures reducing net income and cash flows. We also cannot predict whether the FERC will ultimately issue new licenses or whether we will be willing to meet the licensing requirements to continue to operate the Spokane River Project. We plan to request regulatory approval to recover future licensing costs. However, we cannot be certain that these costs will be recovered through the rate making process.

We are subject to credit risk.

Credit risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. We often extend credit to counterparties and customers, and we are exposed to the risk of not being able to collect amounts owed to us. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Credit risk includes potential counterparty default due to circumstances:

 

   

relating directly to the counterparty,

 

   

caused by market price changes, and

 

   

relating to other market participants that have a direct or indirect relationship with such counterparty.

Should a counterparty, customer or supplier fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

Credit risk also involves the exposure that counterparties perceive related to our ability to perform deliveries and settlement under physical and financial energy contracts. These counterparties may seek assurances of performance in the form of letters of credit, prepayment, or cash deposits.

Credit exposure can change significantly in periods of price volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us, from each counterparty, depends on the extent of forward contracts, unsettled transactions and market prices. There is a risk that we may seek additional collateral from counterparties that are unable or unwilling to provide the collateral.

Our energy resource management activities may cause volatility in our cash flows and results of operations.

We engage in active hedging and resource optimization practices; however, we cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To reduce energy cost volatility and economic exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We do not cover the entire market price volatility exposure for our forecasted net positions. To the extent we have unhedged positions, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which requires additional transactions or dispatch decisions that impact cash flows.

Risk management procedures may not prevent losses.

We have a risk management policy and control procedures designed to mitigate energy market risks. However, our risk management policy and control procedures cannot prevent material losses in all possible situations or from all potential causes. As a result, there can be no assurance that our risk management procedures will prevent losses that could negatively affect our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

Downgrades in our credit ratings could limit our ability to obtain financing, adversely affect the terms of financing and impact our ability to acquire energy resources.

 

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In late 2007 and early 2008, we restored an overall corporate investment grade credit rating with the two major credit rating agencies. Our credit ratings were downgraded during the fourth quarter of 2001, which resulted in an overall corporate credit rating that was below investment grade. The downgrades were due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs that we incurred in our utility operations. These downgrades increased our debt service costs. Any future downgrades could limit our ability to access capital markets or obtain other financing on reasonable terms. In addition, future downgrades could require us to provide letters of credit and/or collateral to lenders and counterparties.

An increase in interest rates could negatively affect our future results of operations and cash flows.

We expect utility capital expenditures to be over $210 million in each of 2009 and 2010. In addition to ongoing needs for our utility distribution system, significant projects include the continued enhancement of our transmission system and upgrades to generating facilities. Our forecasts indicate that we will issue new securities to fund a portion of these requirements. Rising interest rates could increase future debt service costs and decrease operating cash flows to the extent we issue new securities to fund these obligations.

We are subject to various operational and event risks that are common to the utility industry.

Our utility operations are subject to operational and event risks that include:

 

   

blackouts or disruptions to distribution, transmission or transportation systems,

 

   

forced outages at generating plants,

 

   

fuel quality and availability,

 

   

disruptions to our information systems and other administrative resources required for normal operations,

 

   

weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service, and

 

   

terrorism and other malicious threats.

We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets as disclosed in “Note 26 of the Notes to Consolidated Financial Statements.”

Through our utility operations and the prior operations of Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints with respect to energy markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in 2000 and 2001. This allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:

 

   

refund proceedings in California and the Pacific Northwest,

 

   

market conduct investigations by the FERC, and

 

   

complaints filed by various parties related to alleged misconduct by other parties in western power markets.

As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from us, which could result in a negative effect on our results of operations and cash flows. See “Note 26 of the Notes to Consolidated Financial Statements” for further information. Any potential refunds or obligations arising from western energy market issues (or any other contingent matters) were retained by Avista Energy as part of its asset sale agreement in June 2007.

We are subject to legislation and related administrative rulemaking which may adversely effect our operational and financial performance.

We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules published by government agencies, such as the FERC, NERC and the EPA. Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows.

We may be affected by long-term global climate changes.

Rising concerns about long-term global climate changes could have a significant effect on our business. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of hydroelectric

 

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generation capacity. Changing temperatures could also increase or decrease customer demand. We continue to monitor legislative developments at both the state and national level for the potential of further restrictions on sulfur dioxide, nitrogen oxide, carbon dioxide, as well as other greenhouse gas and mercury emissions. Our operations could be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources.

Environmental laws and regulations may have the effect of:

 

   

increasing the costs of generating plants,

 

   

increasing the lead time for the construction of new generating plants,

 

   

requiring modification of our existing generating plants,

 

   

requiring existing generating plants to be curtailed or shut down,

 

   

increasing the risk of delay on construction projects,

 

   

reducing the amount of energy available from our generating plants, and

 

   

restricting the types of generating plants that can be built.

As such, compliance with such environmental laws and regulations could result in increases to capital expenditures and operating expenses.

We have contingent liabilities, as disclosed in “Note 26 of the Notes to Consolidated Financial Statements,” and cannot predict the outcome of these matters.

We have multiple matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the rate making process. See “Note 26 of the Notes to Consolidated Financial Statements” for further details of these matters.

Other Environmental Matters

We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. Environmental issues include, but are not limited to, contamination of certain parcels of land and waters that:

 

   

we currently own,

 

   

we have formerly owned or have used as a customer,

 

   

are adjacent to our property,

 

   

are located on the Spokane or Clark Fork Rivers, or

 

   

are downstream of our hydroelectric facilities.

Item 1B. Unresolved Staff Comments

As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the Securities and Exchange Commission.

 

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Item 2. Properties

Avista Utilities

Substantially all of our utility properties are subject to the lien of our various mortgage indentures.

Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

Generation Properties

 

     No. of
Units
   Nameplate
Rating
(MW) (1)
   Present
Capability
(MW) (2)

Hydroelectric Generating Stations (River)

        

Washington:

        

Long Lake (Spokane)

   4    70.0    83.3

Little Falls (Spokane)

   4    32.0    34.6

Nine Mile (Spokane)

   3    26.4    17.6

Upper Falls (Spokane)

   1    10.0    10.2

Monroe Street (Spokane)

   1    14.8    15.0

Idaho:

        

Cabinet Gorge (Clark Fork)

   4    265.0    254.6

Post Falls (Spokane)

   6    14.8    18.0

Montana:

        

Noxon Rapids (Clark Fork)

   5    480.6    548.4
            

Total Hydroelectric

      913.6    981.7

Thermal Generating Stations

        

Washington:

        

Kettle Falls GS

   1    50.7    50.0

Kettle Falls CT

   1    7.2    6.9

Northeast CT

   2    61.8    56.3

Boulder Park

   6    24.6    24.0

Idaho:

        

Rathdrum CT

   2    166.5    149.0

Montana:

        

Colstrip Units 3 and 4 (3)

   2    233.4    222.0

Oregon:

        

Coyote Springs 2

   1    287.0    278.3
            

Total Thermal

      831.2    786.5
            

Total Generation Properties

      1,744.8    1,768.2
            

 

        
(1) Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.
(2) Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2008.
(3) Jointly owned; data refers to our 15 percent interest.

 

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Electric Distribution and Transmission Plant

We operate approximately 18,100 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 660 miles of 230 kV line and 1,500 miles of 115 kV line. We also own an 11 percent interest (representing 465 MW of capacity) in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution system also includes numerous substations with transformers, switches, monitoring and metering devices, and other equipment.

The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company. These interconnections serve as points of delivery for power from generating facilities outside of our distribution territory, including:

 

   

Colstrip,

 

   

Coyote Springs 2, and

 

   

Mid-Columbia hydroelectric generating facilities.

These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric and the Kettle Falls GS. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp, Pend Oreille County PUD and Puget Sound Energy. Both the 115 kV and 230 kV interconnections with the BPA are used to exchange energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term contract that allows us to serve our native load customers that are connected through the BPA’s transmission system.

Natural Gas Plant

We have natural gas distribution mains of approximately 3,400 miles in Washington, 1,900 miles in Idaho and 2,300 miles in Oregon. The natural gas distribution system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.

We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 239.5 million therms. Natural gas storage enables us to place natural gas into storage when prices are lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Avista Energy controls 30.3 million therms of our capacity at Jackson Prairie and in conjunction with the asset sales agreement has assigned this capacity to Shell Energy through April 30, 2011. After that date, it is our intent to transfer this capacity to Avista Utilities for use in utility operations subject to regulatory approval.

Item 3. Legal Proceedings

See “Note 26 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.

Item 4. Submission of Matters to a Vote of Security Holders

None.

 

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is currently listed on the New York Stock Exchange. As of January 31, 2009, there were 12,312 registered shareholders of our common stock.

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:

 

   

our results of operations, cash flows and financial condition,

 

   

the success of our business strategies, and

 

   

general economic and competitive conditions.

Our net income available for dividends is generally derived from our regulated utility operations (Avista Utilities).

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock (when outstanding) contained in our Restated Articles of Incorporation, as amended.

On February 13, 2009, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.18 per share on the Company’s common stock.

As further discussed at “Note 28 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions if and when we implement a holding company structure. One of the conditions would require IPUC approval of any dividend to the holding company that would reduce utility common equity below 25 percent. We entered into a similar agreement in Washington. This agreement would require WUTC approval of any dividend to the holding company that would reduce utility common equity below 30 percent. The utility equity component was approximately 47.6 percent as of December 31, 2008.

For additional information, refer to “Notes 1, 23, 24 and 25 of Notes to Consolidated Financial Statements.” For high and low stock prices, as well as dividend information, refer to “Note 31 of Notes to Consolidated Financial Statements.”

For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

 

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Item 6. Selected Financial Data

 

(in thousands, except per share data and ratios)

   Years Ended December 31,  
   2008     2007     2006    2005     2004  

Operating Revenues:

           

Avista Utilities

   $ 1,572,664     $ 1,288,363     $ 1,267,938    $ 1,161,317     $ 972,574  

Advantage IQ

     59,085       47,255       39,636      31,748       23,444  

Other

     45,014       82,139       198,737      185,971       292,773  

Intersegment Eliminations

     —         —         —        (19,429 )     (137,211 )
                                       

Total

   $ 1,676,763     $ 1,417,757     $ 1,506,311    $ 1,359,607     $ 1,151,580  
                                       

Income (Loss) from Operations (pre-tax):

           

Avista Utilities

   $ 174,245     $ 150,053     $ 177,049    $ 165,101     $ 134,073  

Advantage IQ

     11,297       11,012       10,479      6,973       1,742  

Other

     (631 )     (22,636 )     12,032      (20,327 )     4,655  
                                       

Total

   $ 184,911     $ 138,429     $ 199,560    $ 151,747     $ 140,470  
                                       

Net Income (Loss):

           

Avista Utilities

   $ 70,032     $ 43,822     $ 57,794    $ 52,299     $ 32,467  

Advantage IQ

     6,090       6,651       6,255      3,922       577  

Other

     (2,502 )     (11,998 )     8,892      (11,233 )     2,570  
                                       

Net income before cumulative effect of accounting change

     73,620       38,475       72,941      44,988       35,614  

Cumulative effect of accounting change

     —         —         —        —         (460 )
                                       

Net income

   $ 73,620     $ 38,475     $ 72,941    $ 44,988     $ 35,154  
                                       

Average common shares outstanding, basic

     53,637       52,796       49,162      48,523       48,400  

Average common shares outstanding, diluted

     54,028       53,263       49,897      48,979       48,886  

Common shares outstanding at year-end

     54,488       52,909       52,514      48,593       48,472  

Earnings per Common Share, Diluted:

           

Earnings before cumulative effect of accounting change

   $ 1.36     $ 0.72     $ 1.46    $ 0.92     $ 0.73  

Cumulative effect of accounting change

     —         —         —        —         (0.01 )
                                       

Total earnings per common share, diluted

   $ 1.36     $ 0.72     $ 1.46    $ 0.92     $ 0.72  
                                       

Total earnings per common share, basic

   $ 1.37     $ 0.73     $ 1.48    $ 0.93     $ 0.73  
                                       

Dividends paid per common share

   $ 0.690     $ 0.595     $ 0.57    $ 0.545     $ 0.515  

Book value per common share at year-end

   $ 18.30     $ 17.27     $ 17.41    $ 15.82     $ 15.50  

Total Assets at Year-End:

           

Avista Utilities

   $ 3,434,844     $ 3,009,499     $ 2,895,883    $ 2,838,154     $ 2,608,155  

Advantage IQ

     125,911       108,929       100,431      46,094       47,318  

Other

     69,992       71,369       1,060,194      2,064,246       1,056,148  
                                       

Total

   $ 3,630,747     $ 3,189,797     $ 4,056,508    $ 4,948,494     $ 3,711,621  
                                       

Long-Term Debt (including current portion)

   $ 826,465     $ 948,833     $ 976,459    $ 1,029,514     $ 986,988  

Long-Term Debt to Affiliated Trusts

     113,403       113,403       113,403      113,403       113,403  

Preferred Stock Subject to Mandatory Redemption

     —         —         26,250      28,000       29,750  

Stockholders’ Equity

   $ 996,883     $ 913,966     $ 914,525    $ 768,849     $ 751,106  

Ratio of Earnings to Fixed Charges (1)

     2.41       1.67       2.14      1.73       1.58  

 

(1) See Exhibit 12 for computations.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

From time to time, we make forward-looking statements such as statements regarding projected or future:

 

   

financial performance,

 

   

capital expenditures,

 

   

dividends,

 

   

capital structure,

 

   

other financial items,

 

   

strategic goals and objectives, and

 

   

plans for operations.

These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and many of them could have a significant effect on our operations, results of operations, financial condition or cash flows. This could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

 

 

weather conditions and its effect on energy demand and generation, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand and wholesale energy markets;

 

 

global financial and economic conditions (including the availability of credit) and their effect on the Company’s ability to obtain funding for working capital and long-term capital requirements on acceptable terms;

 

 

economic conditions in the Company’s service areas, including the effect on the demand for, and customers’ ability to pay for, the Company’s utility services;

 

 

our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions;

 

 

changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

 

 

changes in wholesale energy prices that can affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities;

 

 

volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales;

 

 

the effect of state and federal regulatory decisions affecting our ability to recover costs and/or earn a reasonable return including, but not limited to, the disallowance of costs that we have deferred, and the influence local economic conditions may have on the willingness of regulators to grant necessary rate increases;

 

 

the potential effects of legislation or administrative rulemaking, including the possible adoption of national or state laws requiring resources to meet certain standards and placing restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

 

 

the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, and including possible retroactive price caps and resulting refunds;

 

 

the outcome of legal proceedings and other contingencies;

 

 

changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs;

 

 

wholesale and retail competition including, but not limited to, electric retail wheeling and transmission costs;

 

 

the ability to relicense and maintain licenses for our hydroelectric generating facilities at cost-effective levels with reasonable terms and conditions;

 

 

unplanned outages at any of our generating facilities or the inability of facilities to operate as intended;

 

 

unanticipated delays or changes in construction costs, as well as our ability to obtain required operating permits for present or prospective facilities;

 

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natural disasters that can disrupt energy production or delivery, as well as the availability and costs of materials and supplies and support services;

 

 

blackouts or disruptions of interconnected transmission systems;

 

 

the potential for terrorist attacks or other malicious acts, particularly with respect to our utility assets;

 

 

changes in the long-term climate of the Pacific Northwest, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;

 

 

changes in industrial, commercial and residential growth and demographic patterns in our service territory;

 

 

the loss of significant customers and/or suppliers;

 

 

default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy;

 

 

deterioration in the creditworthiness of our customers and counterparties;

 

 

the effect of any potential decline in our credit ratings;

 

 

increasing health care costs and the resulting effect on health insurance provided to our employees and retirees;

 

 

increasing costs of insurance, changes in coverage terms and our ability to obtain insurance;

 

 

employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as our ability to recruit and retain employees;

 

 

the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in our common stock price;

 

 

changes in technologies, possibly making some of the current technology obsolete;

 

 

changes in tax rates and/or policies; and

 

 

changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, data contained in our records and other data available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of such factors, nor can we assess the effect of each such factor on our business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corporation (Avista Corp. or the Company) and its subsidiaries. This discussion focuses on significant factors concerning our financial condition and results of operations and should be read along with the consolidated financial statements.

Potential Holding Company Formation

At the Annual Meeting of Shareholders in May 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change the Company’s organization to a holding company structure. We received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies), the IPUC in June 2006 and the WUTC in February 2007. We also filed for approval from the utility regulators in Oregon and Montana and proceedings are pending in each of these jurisdictions. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. We can not predict when the remaining regulatory approvals will be obtained or if they will be on terms acceptable to us. See further information at “Note 28 of the Notes to Consolidated Financial Statements.”

Business Segments

We have two reportable business segments as follows:

 

   

Avista Utilities – an operating division of Avista Corp. comprising our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

 

   

Advantage IQ – an indirect subsidiary of Avista Corp. that provides sustainable utility expense management solutions, partnering with multi-site companies across North America to assess and manage utility costs and usage. Primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills as well as strategic management services.

 

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In prior periods, the Company had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. The remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” See “Note 3 of the Notes to Consolidated Financial Statements” for further information.

We have other businesses including sheet metal fabrication, venture fund investments and real estate investments. These activities are conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx. The Other category is not a reportable segment.

Avista Energy, Advantage IQ and the various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Our total common stockholders’ equity was $996.9 million as of December 31, 2008, of which $77.5 million represented our investment in Avista Capital.

The following table presents net income (loss) for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):

 

     2008     2007     2006

Avista Utilities

   $ 70,032     $ 43,822     $ 57,794

Advantage IQ

     6,090       6,651       6,255

Other

     (2,502 )     (11,998 )     8,892
                      

Net income

   $ 73,620     $ 38,475     $ 72,941
                      

Executive Level Summary

Overall

Our operating results and cash flows are primarily from:

 

   

regulated utility operations (Avista Utilities), and

 

   

facility information and cost management services for multi-site customers (Advantage IQ).

Our net income was $73.6 million for 2008, an increase from $38.5 million for 2007. This increase was primarily due to increased earnings at Avista Utilities (primarily due to the implementation of general rate increases in Washington and Idaho) and the $11.9 million net loss at Avista Energy (included in Other) in 2007.

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The total value of the transaction was $37 million. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to redeem their shares of Advantage IQ stock during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties. Based on the estimated fair market value of Advantage IQ common stock held by the previous owners of Cadence Network, the liability was $28.8 million as of December 31, 2008 related to this potential redemption obligation.

We would like to monetize at least a portion of our investment in Advantage IQ within the next four years. The potential monetization of Advantage IQ depends on future market conditions, growth of the business and other factors. There can be no assurance that we will be able to complete a monetization event.

In late 2007 and early 2008, Moody’s Investors Service and Standard & Poor’s upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflected several steps taken over the past few years to lower our business risk profile and improve financial metrics.

It is important to note that we are at the lower end of the investment grade category. We are working to continuously strengthen our credit ratings by improving earnings and operating cash flows, controlling costs and reducing the debt ratios.

 

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Our operations are affected by global financial and economic conditions. The instability within the financial markets has caused industry wide concern regarding the ability to access sufficient capital at a reasonable cost. The turmoil has also resulted in significant declines in the market values of assets held by pension plans (which may impact the funded status of pension plans) as well as concerns regarding credit risk.

We are observing modest declines in employment throughout our service area due to cutbacks in the construction, forest products, mining and manufacturing sectors. However, agriculture, health care, higher education and governmental sectors continue to perform well. Non-farm employment contraction for 2008 as compared to 2007 was 2.3 percent in Spokane, 2.1 percent in Medford and 4.1 percent in Coeur d’Alene, compared to the national average of 2.1 percent. Unemployment rates are much higher than a year ago, having moved above the national average in our eastern Washington, northern Idaho and southern Oregon service areas. Unemployment rates for December 2008 were 7.6 percent in Spokane, 7.3 percent in Coeur d’Alene and 9.9 percent in Medford, compared to the national average of 7.2 percent. The housing market has remained relatively balanced with stable prices keeping foreclosures in check. Foreclosure rates for Spokane, Coeur d’Alene and Medford were all less than 0.4 percent for 2008 compared to the national average of 1.85 percent.

Avista Utilities

Avista Utilities is our most significant business segment. Our utility operating and financial performance is dependent upon, among other things:

 

   

weather conditions,

 

   

the price of natural gas in the wholesale market, including the effect on the price of fuel for generation,

 

   

the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand, and

 

   

regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a fair return on investment.

Our utility net income was $70.0 million for 2008, an increase from $43.8 million for 2007 partially due to an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to the implementation of the general rate increases in Washington and Idaho effective January 1, 2008 and October 1, 2008, respectively. The increase in net income was also partially due to a decrease in interest expense. This was partially offset by an increase in other operating expenses. Also contributing to the increase in net income for 2008 was $5.7 million (pre-tax) of interest income, partially offset by $1.4 million (pre-tax) of interest expense, related to income tax settlements reached during the third quarter of 2008 and the resulting refunds received and payments made to the Internal Revenue Service. Additionally, the improvement in 2008 results as compared to 2007 was also due to a regulatory disallowance recorded in the third quarter of 2007.

We plan to continue to invest in generation, transmission and distribution systems with a focus on providing reliable service to our customers. Utility capital expenditures were $219.2 million for 2008. We expect utility capital expenditures to be over $210 million for 2009.

Advantage IQ

Advantage IQ had net income of $6.1 million for 2008, a decrease from $6.7 million for 2007. This was primarily due to the decrease in our ownership percentage in the business in connection with the acquisition of Cadence Network effective July 2, 2008, an increase in amortization of intangible assets (related to the Cadence acquisition) and lower short-term interest rates (which decreases interest revenue). During 2009, we are anticipating slower internal growth at Advantage IQ than had been expected as some of their clients are experiencing bankruptcies and store closures in these difficult economic times. Additionally, interest revenue is expected to be lower in 2009 due to the historic low short-term interest rate environment that we are currently experiencing and that is expected to continue throughout 2009.

Other Businesses

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy. The net loss for these operations was $2.5 million for 2008 compared to a net loss of $12.0 million for 2007. Contributing to the net loss in 2008 was losses on long-term venture fund investments and litigation costs. The net loss for 2007 was primarily due to Avista Energy.

Liquidity and Capital Resources

We need to access long-term capital markets from time to time to finance capital expenditures, repay maturing long-term debt and obtain additional working capital. Our ability to access capital on reasonable terms is subject to numerous factors, many of which, including market conditions, are beyond our control. Current conditions in the financial markets have resulted in companies having limited access to capital on reasonable terms and have resulted

 

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in a significant increase in borrowing rates for corporations. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011. We had $250.0 million of cash borrowings and $24.3 million in letters of credit outstanding as of December 31, 2008, under our $320.0 million committed line of credit.

In November 2008, we entered into a new committed line of credit in the total amount of $200.0 million with an expiration date of November 24, 2009. We had no borrowings outstanding as of December 31, 2008, under our $200.0 million committed line of credit.

We entered into the $200.0 million line of credit to ensure we had adequate liquidity, as conditions in the financial markets resulted in limited access to capital on reasonable terms.

In March 2008, we amended our accounts receivable sales facility with Bank of America, N.A. to extend the termination date to March 2009. We expect to renew this facility before the March 2009 expiration. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. Based upon calculations under this agreement, we had the ability to sell up to $85.0 million as of December 31, 2008. We had sold $17.0 million of accounts receivable under this facility as of December 31, 2008.

As of December 31, 2008, we had a combined $313.7 million of available liquidity under our $320.0 million committed line of credit, $200.0 million committed line of credit, and $85.0 million revolving accounts receivable sales facility.

In 2008 debt maturities were $404 million, the majority being the $273 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. In April 2008, we issued $250 million of 5.95 percent First Mortgage Bonds to fund a significant portion of this debt that matured. In December 2008, we issued $30 million of 7.25 percent First Mortgage Bonds due in 2013 and refinanced $17 million of Pollution Control Bonds. The proceeds from the $30 million issuance, together with funds borrowed under the $320 million committed line of credit, were used to fund $25 million of medium term notes that matured in December 2008 and to purchase $66.7 million of Pollution Control Bonds in December 2008 that we will hold until they are refunded at a later date.

We anticipate issuing long-term debt and common stock during 2009 to reduce the balances outstanding under our committed line of credit agreements. Additionally, we are planning to remarket or refund the $66.7 million of Pollution Control Bonds during 2009. We do not have any scheduled long-term debt maturities in 2009. The current portion of long-term debt includes $17 million of Pollution Control Bonds because they are subject to purchase at any time at the option of the bond holder due to the interest rate currently being reset daily. After considering the issuances of long-term debt and common stock during 2009, we expect net cash flows from operating activities and our committed line of credit agreements (total of $520.0 million) to provide adequate resources to fund:

 

   

capital expenditures,

 

   

dividends, and

 

   

other contractual commitments.

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We issued 750,000 shares of common stock (total net proceeds of $16.6 million) under this sales agency agreement during the third quarter of 2008. These were our first issuances under the sales agency agreement. We plan to continue to evaluate issuing common stock in future periods.

Due to market conditions and the decline in the fair value of pension plan assets, our contributions to the pension plan in 2009 are expected to be $48 million as compared to the $28 million we contributed in 2008. The final determination of pension plan contributions beyond 2009 is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We have adequate liquidity to meet our pension plan funding obligations for 2009.

 

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Avista Utilities – Electric Resources

As of December 31, 2008, our generation facilities had a total net capability of 1,768 MW, of which 56 percent was hydroelectric and 44 percent was thermal. In addition to company owned generation resources, we have a number of long-term power purchase and exchange contracts that increase our available resources. See “Note 7 of the Notes to Consolidated Financial Statements” for information with respect to the resource optimization process.

Settlement with the Coeur d’Alene Tribe

In December 2008, we reached a comprehensive agreement with the Coeur d’Alene Tribe (Tribe) and the United States Department of Interior over our past and future use of Tribal land and water in the operation of our Spokane River Hydroelectric Projects, including the Post Falls dam. Pursuant to the settlement, we will compensate the Tribe a total of $39 million for past storage of water for the period from 1907 through 2007. We paid $25 million in December 2008 with remaining payments of $10 million in 2009 and $4 million in 2010. This obligation has been recorded as a regulatory asset as of December 31, 2008. We will compensate the Tribe for future storage of water through payments of $0.4 million per year beginning in 2008 and continuing through the first 20 years of a new license and $0.7 million per year through the remaining term of the license.

In addition to past and future storage payments, the agreement provides for annual payments to fund a variety of protection, mitigation and enhancement measures on the Coeur d’Alene Reservation that would be implemented over the life of a new FERC license. This will be accomplished through the creation of a Coeur d’Alene resource protection trust fund. Annual payments from Avista Corp. to the trust fund for protection, mitigation and enhancement measurements would commence with the issuance of the new FERC license and are expected to total approximately $100 million over an assumed 50-year license term.

Avista Utilities – Regulatory Matters

General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:

 

   

provide for recovery of operating costs and capital investments, and

 

   

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include in-service dates of major infrastructure investments and the timing of changes in major revenue and expense items. Primarily due to the significant amount of capital investments we are making in our utility infrastructure and increasing operating costs, we filed general rate cases in Washington and Idaho in January 2009. We are planning to file in Oregon during the first half of 2009. The following is a summary of our authorized rates of return in each jurisdiction:

 

Jurisdiction and service

   Implementation
Date
   Authorized
Overall Rate
of Return
    Authorized
Return on
Equity
    Authorized
Equity
Level
 

Washington electric and natural gas

   January 2009    8.22 %   10.2 %   46 %

Idaho electric and natural gas

   October 2008    8.45 %   10.2 %   48 %

Oregon natural gas

   April 2008    8.21 %   10.0 %   50 %

As approved by the WUTC, on January 1, 2008, electric rates for our Washington customers increased by an average of 9.4 percent, which was designed to increase annual revenues by $30.2 million. As part of this general rate increase, the base level of power supply costs used in the Energy Recovery Mechanism (ERM) calculations was updated. Also, on January 1, 2008, natural gas rates increased by an average of 1.7 percent, which was designed to increase annual revenues by $3.3 million.

In September 2008, we entered into a settlement stipulation with respect to our general rate case that was filed with the WUTC in March 2008. Other parties to the settlement stipulation are the staff of the WUTC, Northwest Industrial Gas Users, and the Energy Project. The Industrial Customers of Northwest Utilities (ICNU) joined in portions of the settlement and the Public Counsel Section of the Washington Attorney General’s Office (Public Counsel) did not join in the settlement stipulation. This settlement stipulation was approved by the WUTC in December 2008. The new electric and natural gas rates became effective on January 1, 2009. As agreed to in the settlement, base electric rates for our Washington customers increased by an average of 9.1 percent, which is designed to increase annual revenues by $32.5 million. Base natural gas rates for our Washington customers increased by an average of 2.4 percent, which is designed to increase annual revenues by $4.8 million.

 

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Our original request in March 2008 was for base electric rate increases averaging 10.3 percent, which was designed to increase annual revenues by $36.6 million. Our original request was to increase base natural gas rates by an average of 3.3 percent, which was designed to increase annual revenues by $6.6 million.

The settlement was based on an overall rate of return of 8.22 percent with a common equity ratio of 46.3 percent and a 10.2 percent return on equity. Our original request was based on a proposed overall rate of return of 8.43 percent with a common equity ratio of 46.3 percent and a 10.8 percent return on equity.

On January 27, 2009, Public Counsel filed a Petition for Judicial Review of the WUTC’s December 2008 order approving our multiparty settlement. Public Counsel raised a number of issues that were previously argued before the WUTC. These include whether settlement costs associated with resolving the dispute with the Coeur d’Alene Tribe were prudent and whether recovery of such costs would constitute illegal “retroactive ratemaking.” Public Counsel also questioned whether the WUTC’s decision to entertain supplemental testimony by us to update our filing for power supply costs during the course of the proceedings was appropriate. Finally, Public Counsel argued that the settlement improperly included advertising costs, dues and donations, and certain other expenses.

The appeal itself does not prevent the new rates from going into effect. The appeals process may take several months and a decision is not expected until later in 2009. The court will either affirm the decision of the WUTC in its entirety or reverse the decision, in whole or in part, and remand the matter back to the WUTC for further consideration, which could possibly result in refunds.

In January 2009, we filed a general rate case with the WUTC requesting to increase base electric rates for our Washington customers. In the general rate case filing, we requested a net electric rate increase of 8.6 percent. The net electric rate increase is based on a requested 16.0 percent increase in billed rates with an offsetting 7.4 percent reduction in the current Energy Recovery Mechanism (ERM) surcharge. We also requested a 2.4 percent increase in natural gas rates. The filing is designed to increase annual base electric service revenues by $69.8 million ($37.5 million net after considering the reduction in the current ERM surcharge) and increase annual natural gas service revenues by $4.9 million. Our request is based on a proposed rate of return on rate base of 8.68 percent, with a common equity ratio of 47.5 percent and an 11.0 percent return on equity. The WUTC generally has up to 11 months to review a general rate case filing.

As part of the general rate case settlement agreement that was modified and approved by the WUTC in December 2005, we agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. Our utility equity component met this target as it was approximately 47.6 percent as of December 31, 2008.

In August 2008, we entered into an all-party settlement stipulation with respect to our general rate case that was filed with the IPUC in April 2008. This settlement stipulation was approved by the IPUC in September 2008. The new electric and natural gas rates became effective on October 1, 2008. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 12.0 percent, which is designed to increase annual revenues by $23.2 million. Base natural gas rates for our Idaho customers increased by an average of 4.7 percent, which is designed to increase annual revenues by $3.9 million.

Our original request was for base electric rate increases averaging 16.7 percent, which was designed to increase annual revenues by $32.3 million. We also requested to increase base natural gas rates by an average of 5.8 percent, which was designed to increase annual revenues by $4.7 million.

In January 2009, we filed a general rate case with the IPUC requesting to increase base electric rates for our Idaho customers. In the general rate case filing, we requested a net electric rate increase of 7.8 percent. The net electric rate increase is based on a requested 12.8 percent increase in billed rates with an offsetting 5.0 percent reduction in the current Power Cost Adjustment (PCA) surcharge. We also requested a 3.0 percent increase in natural gas rates. The filing is designed to increase annual base electric service revenues by $31.2 million ($18.9 million net after considering the reduction in the current PCA surcharge) and increase annual natural gas service revenues by $2.7 million. Our request is based on a proposed rate of return on rate base of 8.8 percent, with a common equity ratio of 50 percent and an 11.0 percent return on equity. The IPUC generally has up to seven months to review a general rate case filing.

As approved by the OPUC in March 2008, natural gas rates for our Oregon customers increased 0.4 percent effective April 1, 2008 (designed to increase annual revenues by $0.5 million) and increased an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million).

 

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Purchased Gas Adjustments

Effective January 6, 2009, natural gas rates decreased 4.7 percent in Idaho. Effective January 16, 2009, natural gas rates decreased 3.0 percent in Washington. Effective November 1, 2008, natural gas rates decreased 4.1 percent in Oregon. Purchased gas adjustments (PGAs) are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb 10 percent of the difference between actual and projected gas costs for unhedged supply. In October 2008, the OPUC issued an order based upon an extensive review of the current PGA mechanism. The order reaffirmed the current mechanism and included several minor modifications that we believe will not have a significant impact on our gas purchasing and hedging strategies or net income. Total net deferred natural gas costs were a liability of $18.6 million as of December 31, 2008, a change from a net asset of $2.4 million as of December 31, 2007.

Oregon Senate Bill 408

The OPUC established rules in September 2007 related to Oregon Senate Bill 408 (OSB 408), which was enacted into law in 2005. These rules direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. The automatic adjustment clause may result in either rate increases or rate decreases and applies only to taxes paid and collected on or after January 1, 2006.

In February 2008, we reached a settlement with respect to the refund liability for the 2006 tax report that was approved by the OPUC in April 2008. The approved settlement provided for a refund to customers of $1.5 million, including interest. In October 2008, we filed the tax report for 2007 showing taxes paid to be less than taxes collected by $2.0 million before interest. We claimed that no refund should be made in connection with the 2007 tax report, asserting that such a refund would violate the “fair and reasonable” standard provided for under OPUC rules. In January 2009, we reached a settlement that would result in no refund related to the 2007 tax report. A joint brief related to the settlement was filed in February 2009. The OPUC is expected to rule on the settlement before April 15, 2009. We have recorded a potential refund liability related to the 2008 tax report of $1.4 million. However, any final determination of refunds or surcharges to customers will ultimately be determined based on final calculations for the 2008 tax year.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism. Because our rate structure provides for recovery of the majority of fixed costs on a per-therm (sales volume) basis, energy efficiency and conservation objectives have been directly at odds with the recovery of fixed costs, which do not vary with the volume of natural gas sold. Decoupling separates the direct link between natural gas sales volume and the recovery of the fixed cost of providing service to our customers. Our decoupling mechanism should allow us to recover lost margin resulting from lower usage by Washington customers due to conservation and price elasticity. However, the mechanism does not provide rate adjustments related to abnormal weather. The decoupling mechanism is a two and one half year “pilot” that began in January 2007. Continuation of the mechanism beyond June 2009 is subject to review and approval by the WUTC. A rate adjustment in any one year would be limited to no more than 2 percent. Our most recent decoupling rate adjustment became effective November 1, 2008. The rate adjustment is designed to recover $0.7 million from Washington residential and small commercial customers over a twelve month period. This represents an incremental rate increase of 0.3 percent, reflecting 90 percent of the lost margin due to conservation by the Company’s Washington residential and small commercial gas customers during the period July 2007 through June 2008.

Wind Generation Costs

In June 2008, we filed a petition with the WUTC and the IPUC requesting that costs (including land, turbine down payments and other preliminary costs) associated with wind generation projects be accounted for as construction work in progress, allowing for the accrual of an allowance for funds used during construction (AFUDC). In July 2008, the IPUC approved our request. In December 2008, we withdrew our request in Washington and plan to address this item in a future proceeding.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual net power supply costs and the amount included in base retail rates for our Washington customers.

This difference in net power supply costs primarily results from changes in:

 

   

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

 

   

the level of hydroelectric generation,

 

   

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

 

   

retail loads.

 

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The initial amount of power supply costs in excess of or below the level in retail rates, which we either incur the cost of, or receive the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We share annual power supply cost variances between $4.0 million and $10.0 million with customers. Through December 31, 2008, 50 percent of the annual power supply cost variance in this range was deferred for future surcharge or rebate to customers and we incurred the cost of, or received the benefit from, the remaining 50 percent. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. We incur the cost of, or receive the benefit from, the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates. The following is a summary of the ERM through December 31, 2008:

 

Annual Power Supply

Cost Variability

   Deferred for Future
Surcharge or Rebate
to Customers
    Expense or Benefit
to the Company
 

+/- $0 - $4 million

   0 %   100 %

+/- between $4 million - $10 million

   50 %   50 %

+/- excess over $10 million

   90 %   10 %

Based upon the approved September 2008 settlement stipulation with respect to our general rate case that was filed with the WUTC in March 2008 (the settlement stipulation was approved in December 2008), the ERM was adjusted for the sharing level for the annual power supply cost variance in the $4.0 million to $10.0 million band. The adjustment resulted in a 75 percent customers/25 percent Company sharing when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. The 50 percent customers/50 percent Company sharing was maintained when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. The revisions to the ERM became effective on January 1, 2009.

The following is a summary of the revised ERM:

 

Annual Power Supply

Cost Variability

   Deferred for Future
Surcharge or Rebate
to Customers
    Expense or Benefit
to the Company
 

+/- $0 - $4 million

   0 %   100 %

+ between $4 million - $10 million

   50 %   50 %

- between $4 million - $10 million

   75 %   25 %

+/- excess over $10 million

   90 %   10 %

Under the ERM, we make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. In August, 2008, the WUTC issued an order, which approved the recovery of power costs incurred for 2007. Additionally, we must make a filing (no sooner than January 1, 2011), to allow all interested parties the opportunity to review the ERM, and make recommendations to the WUTC related to the continuation, modification or elimination of the ERM.

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. The PCA rate surcharge, as approved by the IPUC, is 0.61 cents per KWh (designed to recover $21.7 million) for the period October 1, 2008 through September 30, 2009.

The following table shows activity in deferred power costs for Washington and Idaho during 2007 and 2008 (dollars in thousands):

 

     Washington     Idaho     Total  

Deferred power costs as of December 31, 2006

   $ 70,159     $ 9,357     $ 79,516  

Activity from January 1 – December 31, 2007:

      

Power costs deferred

     16,344       16,750       33,094  

Interest and other net additions

     3,023       788       3,811  

Recovery of deferred power costs through retail rates

     (31,002 )     (5,732 )     (36,734 )
                        

Deferred power costs as of December 31, 2007

   $ 58,524     $ 21,163     $ 79,687  

 

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     Washington     Idaho     Total  

Activity from January 1 – December 31, 2008:

      

Power costs deferred

   $ 7,049     $ 10,029     $ 17,078  

Interest and other net additions

     2,231       1,153       3,384  

Recovery of deferred power costs through retail rates

     (30,852 )     (11,690 )     (42,542 )
                        

Deferred power costs as of December 31, 2008

   $ 36,952     $ 20,655     $ 57,607  
                        

Results of Operations

The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses in the business segment discussions (Avista Utilities, Advantage IQ and the other businesses) that follow this section.

2008 compared to 2007

Utility revenues increased $284.3 million to $1,572.7 million as a result of increases in natural gas revenues of $157.0 million and electric revenues of $127.3 million. The increase in natural gas revenues was primarily the result of increased wholesale revenues (due to increased prices and volumes) of $139.5 million and retail natural gas revenues (due to increased volumes) of $16.4 million. The increase in electric revenues was primarily due to increased retail revenues (primarily due to the Washington general rate increase implemented on January 1, 2008 and the Idaho general rate increase implemented on October 1, 2008) of $58.8 million, wholesale revenues of $36.0 million and sales of fuel of $31.8 million.

Non-utility energy marketing and trading revenues decreased $36.3 million to $25.2 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007. The remaining revenues primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

Other non-utility revenues increased $11.0 million to $78.9 million as a result of an increase in revenues from Advantage IQ of $11.8 million primarily due to customer growth and the acquisition of Cadence Network in the third quarter of 2008, partially offset by a decrease in interest earnings on funds held for customers (due to lower interest rates).

Utility resource costs increased $251.0 million due to increases in natural gas resource costs of $147.9 million and electric resource costs of $103.1 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases and increased amortization of deferred natural gas costs. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case implemented on January 1, 2008 and the Idaho general rate case implemented on October 1, 2008, as well as higher purchased power and fuel costs.

Utility other operating expenses increased $7.8 million primarily due to an increase of $4.0 million in electric generation operating and maintenance expenses, as well as a $3.4 million increase in electric distribution expenses. This was partially offset by the impairment of a turbine in the third quarter of 2007 of $2.3 million.

Utility depreciation and amortization increased $1.8 million primarily due to additions to utility plant.

Non-utility resource costs decreased $45.1 million. This category of expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007. The remaining costs primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

The net change in other non-utility operating expenses was a decrease of $2.7 million due to:

 

   

a decrease of $13.2 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

 

   

an increase of $10.5 million for Advantage IQ due to expanding operations and the acquisition of Cadence Network in the third quarter of 2008.

Interest expense decreased $5.7 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007 and 2008, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets and the issuance of long-term debt at lower interest rates. This was partially offset by interest expense of $1.4 million related to an income tax settlement.

 

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Interest expense to affiliated trusts decreased $1.2 million due to a decrease in the variable interest rate.

Other income-net decreased $1.5 million primarily due to a decrease in interest income of $4.6 million. The decrease in interest income was primarily due to the disposition of Avista Energy’s ongoing operations. Also contributing to the decrease were losses on long-term venture fund investments. The net decrease was offset by $5.7 million of interest income recorded on the IRS settlement agreement for the 2001 through 2003 tax years and the resulting refund. See “Note 13 of the Notes to Consolidated Financial Statements” for additional information with respect to the IRS settlement agreement.

Income taxes increased $21.3 million primarily due to increased income before income taxes. Our effective tax rate was 38.3 percent for 2008 compared to 38.7 percent for 2007.

2007 compared to 2006

Utility revenues increased $20.4 million to $1,288.4 million as a result of an increase in natural gas revenues of $56.7 million, which were the result of increased wholesale (primarily due to increased volumes) and retail (due to an increase in rates and volumes) natural gas sales. This was partially offset by a decrease in electric revenues of $36.3 million reflecting decreased wholesale revenues and sales of fuel, partially offset by increased retail revenues.

Non-utility energy marketing and trading revenues decreased $116.0 million to $61.5 million. This category of revenues decreased significantly in 2007 with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $7.0 million to $67.9 million as a result of an increase in revenues from Advantage IQ of $7.6 million primarily due to customer growth, as well as an increase in interest earnings on funds held for customers. This was partially offset by decreased other revenues of $0.6 million due in part to decreased sales at AM&D.

Utility resource costs increased $29.4 million due to an increase in natural gas resource costs of $54.1 million primarily reflecting an increase in the volume of natural gas purchases. The increase in natural gas resource costs was partially offset by a decrease in electric resource costs of $24.7 million primarily due to a decrease in other fuel costs (economic sales of fuel that was not used in generation) and a decrease in the net amortization of deferred power costs. The decrease in other fuel costs was consistent with reduced resource optimization activities during 2007 and lower sales of fuel and wholesale sales as part of the process of balancing loads and resources. The decrease in the net amortization of deferred power costs reflected higher electric resource costs as compared to the amount included in base electric rates and the resulting increase in deferrals for future recovery from customers. In 2007, we deferred $33.1 million of power costs as compared to $5.7 million in 2006.

Utility other operating expenses increased $11.3 million primarily due to the impairment of a turbine of $2.3 million, increased maintenance expenses of $3.5 million, natural gas distribution expenses of $1.8 million, outside services of $2.3 million, and regulatory commission fees of $2.7 million.

Utility depreciation and amortization increased $4.2 million primarily due to additions to utility plant.

Utility taxes other than income taxes increased $2.6 million primarily due to increased retail electric and natural gas revenues and related taxes.

Non-utility resource costs decreased $75.5 million. This category of expenses decreased significantly in 2007 with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

The net change in other non-utility operating expenses was an increase of $1.2 million due to:

 

   

an increase of $6.8 million for Advantage IQ due to expanding operations and consulting services, and

 

   

a decrease of $5.6 million in the other businesses due the sale of Avista Energy’s ongoing operations, to lower operating expenses at AM&D and the accrual of an environmental liability at Avista Development during 2006, partially offset by the loss on the sale of Avista Energy’s operations.

Interest expense decreased $9.9 million due to our issuance of fixed rate long-term debt that replaced maturing debt (which had relatively high interest rates) in the fourth quarter of 2006 and a decrease in interest expense on short-term borrowings under our committed line of credit. The decrease in short-term borrowings partially reflects the availability of funds from the Avista Energy transaction.

Capitalized interest increased $0.9 million due to increased utility construction activity and the associated increase in construction work in progress balances.

 

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In the Washington general rate case settlement, we agreed to write off $3.8 million of unamortized debt repurchase costs effective September 30, 2007. These costs were for premiums paid to repurchase higher coupon debt prior to its scheduled maturity as part of an effort to reduce interest expense.

Other income-net increased $2.2 million due to an increase in equity-related AFUDC (consistent with increased utility construction activity) and gains on long-term venture fund investments, partially offset by a decrease in interest income and interest on power and natural gas deferrals.

Income taxes decreased $17.7 million primarily due to decreased income before income taxes. Our effective tax rate was 38.7 percent for 2007 compared to 36.5 percent for 2006. The increase in the effective tax rate was primarily due to certain tax adjustments in 2007 and 2006. In 2007, the Company recognized tax adjustment expenses of $1.0 million. In 2006, the Company recognized adjustments related to IRS audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact to recorded 2006 tax expense of $1.3 million.

Avista Utilities

2008 compared to 2007

Net income for the utility was $70.0 million for 2008 compared to $43.8 million for 2007. Utility income from operations was $174.2 million for 2008 compared to $150.1 million for 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses and depreciation and amortization.

The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):

 

     Electric    Natural Gas    Total
     2008    2007    2008    2007    2008    2007

Operating revenues

   $ 838,457    $ 711,130    $ 734,207    $ 577,233    $ 1,572,664    $ 1,288,363

Resource costs

     425,373      322,237      606,616      458,761      1,031,989      780,998
                                         

Gross margin

   $ 413,084    $ 388,893    $ 127,591    $ 118,472    $ 540,675    $ 507,365
                                         

Utility operating revenues increased $284.3 million and utility resource costs increased $251.0 million, which resulted in an increase of $33.3 million in gross margin. The gross margin on electric sales increased $24.2 million and the gross margin on natural gas sales increased $9.1 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008 and Idaho effective October 1, 2008. The increase was also partially due to colder weather in 2008, which increased customer usage, during the heating season and customer growth. The Company absorbed $7.4 million in 2008 and $8.5 million in 2007 under the ERM.

The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars and MWhs in thousands):

 

     Electric Operating
Revenues
   Electric Energy
MWh sales
     2008    2007    2008    2007

Residential

   $ 279,641    $ 251,357    3,744    3,670

Commercial

     247,714      224,179    3,188    3,132

Industrial

     101,785      95,207    2,059    2,084

Public street and highway lighting

     5,962      5,517    26    26
                       

Total retail

     635,102      576,260    9,017    8,912

Wholesale

     141,744      105,729    1,964    1,594

Sales of fuel

     44,695      12,910    —      —  

Other

     16,916      16,231    —      —  
                       

Total

   $ 838,457    $ 711,130    10,981    10,506
                       

Retail electric revenues increased $58.8 million due to an increase in:

 

   

total MWhs sold (increased revenues $7.3 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

 

   

revenue per MWh (increased revenues $51.5 million) primarily due to the Washington general rate increase implemented on January 1, 2008 and the Idaho general rate increase implemented on October 1, 2008.

Wholesale electric revenues increased $36.0 million due to an increase in sales prices (increased revenues $9.3 million), and an increase in sales volumes (increased revenues $26.7 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units,

 

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we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $31.8 million due to increased thermal generation resource optimization activities.

The following table presents our utility natural gas operating revenues and therms delivered for the year ended December 31 (dollars and therms in thousands):

 

     Natural Gas
Operating Revenues
   Natural Gas
Therms Delivered
     2008    2007    2008    2007

Residential

   $ 276,386    $ 264,546    210,125    195,756

Commercial

     152,147      148,416    128,224    121,557

Interruptible

     5,428      5,040    5,758    5,003

Industrial

     6,731      6,244    6,438    5,830
                       

Total retail

     440,692      424,246    350,545    328,146

Wholesale

     281,668      142,167    345,916    223,084

Transportation

     6,327      6,638    148,723    148,765

Other

     5,520      4,182    526    438
                       

Total

   $ 734,207    $ 577,233    845,710    700,433
                       

The $16.4 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $28.1 million), partially offset by lower retail rates (decreased revenues $11.7 million). We sold more retail natural gas in 2008 primarily due to colder weather during the heating season and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008 and Idaho general rate increase implemented on October 1, 2008.

The increase in our wholesale revenues of $139.5 million was due to an increase in prices (increased revenues $39.5 million) and an increase in volumes (increased revenues $100.0 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Additionally, we engage in optimization of under utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. This activity increased significantly in 2008 as compared to 2007. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the year ended December 31:

 

     Electric
Customers
   Natural Gas
Customers
     2008    2007    2008    2007

Residential

   311,381    306,737    277,892    273,415

Commercial

   39,075    38,488    32,901    32,327

Interruptible

   —      —      40    41

Industrial

   1,388    1,378    257    261

Public street and highway lighting

   434    426    —      —  
                   

Total retail customers

   352,278    347,029    311,090    306,044
                   

The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):

 

     2008    2007

Electric resource costs:

     

Power purchased

   $ 193,924    $ 158,245

Power cost amortizations, net of deferrals

     25,464      3,641

Fuel for generation

     134,446      125,043

Other fuel costs

     43,103      16,454

Other regulatory amortizations, net

     10,490      4,437

Other electric resource costs

     17,946      14,417
             

Total electric resource costs

     425,373      322,237
             

Natural gas resource costs:

     

Natural gas purchased

     579,248      433,140

Natural gas amortizations, net of deferrals

     20,372      16,875

Other regulatory amortizations, net

     6,996      8,746
             

Total natural gas resource costs

     606,616      458,761
             

Total resource costs

   $ 1,031,989    $ 780,998
             

 

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Power purchased increased $35.7 million due in part to an increase in wholesale prices (increased costs $23.0 million). The increase was also due to an increase in the volume of power purchases (increased costs $12.7 million) primarily due to an increase in sales volumes (due to colder weather, customer growth, and optimization).

Net amortization of deferred power costs was $25.5 million for 2008 compared to $3.6 million for 2007. During 2008, we recovered (collected as revenue) $30.9 million of previously deferred power costs in Washington and $11.7 million in Idaho. During 2008, we deferred $7.0 million of power costs in Washington and $10.0 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $9.4 million due to an increase in thermal generation volumes and an increase in fuel prices.

Other fuel costs increased $26.6 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economic to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs were less than the revenues we received from selling the natural gas. We account for this difference under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to increased thermal generation resource optimization activities and increased fuel prices.

Other regulatory amortizations increased $6.1 million primarily due to amortization of demand side management program expenses.

The expense for natural gas purchased increased $146.1 million due to an increase in total therms purchased and the price of natural gas. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes. We engage in optimization of under utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. This activity increased significantly in 2008 as compared to 2007. During 2008, we amortized $20.4 million of deferred natural gas costs compared to $16.9 million for 2007.

2007 compared to 2006

Net income for the utility was $43.8 million for 2007 compared to $57.8 million for 2006. Utility income from operations was $150.1 million for 2007 compared to $177.0 million for 2006. This decrease in income from operations was primarily due to decreased gross margin (operating revenues less resource costs). The decrease was also due to an increase in:

 

   

other utility operating expenses (primarily due to the impairment of a turbine, increased maintenance expenses, natural gas distribution expenses, outside services, and regulatory commission fees).

 

   

depreciation and amortization (due to additions to utility plant), and

 

   

taxes other than income taxes (primarily due to increased retail electric and natural gas revenues and related taxes).

The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):

 

     Electric    Natural Gas    Total
     2007    2006    2007    2006    2007    2006

Operating revenues

   $ 711,130    $ 747,383    $ 577,233    $ 520,555    $ 1,288,363    $ 1,267,938

Resource costs

     322,237      346,980      458,761      404,666      780,998      751,646
                                         

Gross margin

   $ 388,893    $ 400,403    $ 118,472    $ 115,889    $ 507,365    $ 516,292
                                         

Utility operating revenues increased $20.4 million and utility resource costs increased $29.4 million, which resulted in a decrease of $8.9 million in gross margin. The gross margin on electric sales decreased $11.5 million and the gross margin on natural gas sales increased $2.6 million. The decrease in our electric gross margin was primarily due to the difference in electric resource costs as compared to the amount included in base retail rates resulting in the expense of $8.5 million of power supply costs in Washington under the ERM during 2007. We received a benefit of $2.6 million under the ERM in 2006. The increase in power supply costs for 2007 (as compared to the amount included in base rates) was primarily due to lower hydroelectric generation, higher purchased power and fuel costs and greater use of our thermal generating resources (particularly Coyote Springs 2). The increase in natural gas gross margin was primarily due to colder weather in the first quarter of 2007 and customer growth.

 

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The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars and MWhs in thousands):

 

     Electric Operating
Revenues
   Electric Energy
MWh sales
     2007    2006    2007    2006

Residential

   $ 251,357    $ 234,714    3,670    3,578

Commercial

     224,179      221,193    3,132    3,110

Industrial

     95,207      92,961    2,084    2,062

Public street and highway lighting

     5,517      5,268    26    25
                       

Total retail

     576,260      554,136    8,912    8,775

Wholesale

     105,729      126,208    1,594    2,117

Sales of fuel

     12,910      48,176    —      —  

Other

     16,231      18,863    —      —  
                       

Total

   $ 711,130    $ 747,383    10,506    10,892
                       

Retail electric revenues increased $22.1 million due to an increase in:

 

   

total MWhs sold (increased revenues $8.8 million) primarily due to customer growth and partially due to an increase in use per customer, and

 

   

revenue per MWh (increased revenues $13.3 million) primarily due to the elimination of the BPA residential exchange credit.

The increase in use per customer was primarily due to colder weather in the first and fourth quarters.

Wholesale electric revenues decreased $20.5 million due to:

 

   

a decrease in sales volumes (decreased revenues $34.7 million) consistent with decreased volume of wholesale purchases and decreased resource optimization activities, partially offset by

 

   

an increase in sales prices (increased revenues $14.2 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel decreased $35.3 million as a greater percentage of our fuel purchases were used in generation.

Other electric revenues decreased $2.6 million primarily due to revenues of $3.0 million from the sale of claims we had against Enron Corporation (Enron) and certain of its affiliates received in 2006 (first quarter).

The following table presents our utility natural gas operating revenues and therms delivered for the year ended December 31 (dollars and therms in thousands):

 

     Natural Gas
Operating Revenues
   Natural Gas
Therms Delivered
     2007    2006    2007    2006

Residential

   $ 264,546    $ 257,753    195,756    192,833

Commercial

     148,416      146,581    121,557    120,989

Interruptible

     5,040      4,676    5,003    4,539

Industrial

     6,244      7,000    5,830    6,501
                       

Total retail

     424,246      416,010    328,146    324,862

Wholesale

     142,167      93,221    223,084    154,884

Transportation

     6,638      6,499    148,765    149,717

Other

     4,182      4,825    438    443
                       

Total

   $ 577,233    $ 520,555    700,433    629,906
                       

Natural gas revenues increased $56.7 million due to an increase in retail and wholesale natural gas revenues. The $8.2 million increase in retail natural gas revenues was due to higher retail rates (increased revenues $4.0 million) and increased volumes (increased revenues $4.2 million). We sold more retail natural gas in 2007 primarily due to customer growth. The increase in our wholesale revenues of $48.9 million was due to an increase in volumes (increased revenues $43.4 million) and an increase in prices (increased revenues $5.5 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Any variance between the revenues and costs of the sale of resources in excess of load requirements is accounted for through the PGA mechanisms.

 

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The following table presents our average number of electric and natural gas retail customers for the year ended December 31:

 

     Electric
Customers
   Natural Gas
Customers
     2007    2006    2007    2006

Residential

   306,737    300,940    273,415    267,345

Commercial

   38,488    37,912    32,327    31,746

Interruptible

   —      —      41    41

Industrial

   1,378    1,388    261    254

Public street and highway lighting

   426    425    —      —  
                   

Total retail customers

   347,029    340,665    306,044    299,386
                   

The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):

 

     2007    2006  

Electric resource costs:

     

Power purchased

   $ 158,245    $ 150,719  

Power cost amortizations, net of deferrals

     3,641      29,259  

Fuel for generation

     125,043      109,723  

Other fuel costs

     16,454      50,881  

Other regulatory amortizations, net

     4,437      (6,199 )

Other electric resource costs

     14,417      12,597  
               

Total electric resource costs

     322,237      346,980  
               

Natural gas resource costs:

     

Natural gas purchased

     433,140      371,142  

Natural gas amortizations, net of deferrals

     16,875      28,426  

Other regulatory amortizations, net

     8,746      5,098  
               

Total natural gas resource costs

     458,761      404,666  
               

Total resource costs

   $ 780,998    $ 751,646  
               

Power purchased increased $7.5 million due to an increase in the price of power purchases (increased costs $12.6 million) due to overall increases in wholesale markets. This was partially offset by a decrease in the volume of power purchases (decreased costs $5.1 million) primarily due to increased thermal generation as well as decreased resource optimization activities as part of the process of balancing loads and resources. This was consistent with a decrease in wholesale sales volumes.

Net amortization of deferred power costs was $3.6 million for 2007 compared to $29.3 million for 2006 due to lower hydroelectric generation, higher purchased power and fuel costs and greater use of our thermal generating resources. During 2007, we recovered (collected as revenue) $31.0 million of previously deferred power costs in Washington and $5.7 million in Idaho. During 2007, we deferred $16.3 million of power costs in Washington and $16.7 million in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $15.3 million due to higher natural gas fuel prices and an increase in thermal generation volumes (particularly Coyote Springs 2).

Other fuel costs decreased $34.4 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economic to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs exceeded revenues we received from selling the natural gas. We account for this shortfall under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to an increased percentage of fuel used in generation and decreased resource optimization activities.

Other regulatory amortizations increased $10.6 million primarily due to the elimination of the BPA residential exchange credit.

The expense for natural gas purchased for sale to customers increased $62.0 million primarily due to an increase in total therms purchased. This was primarily due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process, and partially due to an increase in retail sales volumes. The increase was also partially due to an increase in natural gas prices. During 2007, we amortized $16.9 million of deferred natural gas costs compared to $28.4 million for 2006.

 

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Advantage IQ

2008 compared to 2007

Net income for Advantage IQ was $6.1 million for 2008 compared to $6.7 million for 2007. Operating revenues increased $11.8 million and operating expenses increased $11.5 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base and the third quarter acquisition of Cadence Network, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of December 31, 2008, Advantage IQ had 537 customers representing 417,000 billed sites in North America, a significant increase from the end of 2007 primarily due to the acquisition of Cadence Network. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, as well as the third quarter acquisition of Cadence Network (including the amortization of intangible assets). In 2008, Advantage IQ processed bills totaling $16.7 billion, an increase of $4.2 billion, or 34 percent, as compared to 2007. The acquisition of Cadence Network (in July 2008) added $2.1 billion in processed bills for 2008.

2007 compared to 2006

Net income for Advantage IQ was $6.7 million for 2007 compared to $6.3 million for 2006. Operating revenues increased $7.6 million and operating expenses increased $7.1 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base as well as an increase in interest earnings on funds held for customers. As of December 31, 2007, Advantage IQ had 403 customers representing 199,000 billed sites in North America. The number of billed sites decreased slightly from December 31, 2006. This decrease was due to the loss of a customer that had a significant number of billed sites, and represented approximately 1 percent of annualized revenues. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, which included consulting services. In 2007,  Advantage IQ processed bills totaling $12.5 billion, an increase of $1.7 billion, or 16 percent, as compared to 2006.

Other Businesses

2008 compared to 2007

Net loss from these operations was $2.5 million for 2008 compared to $12.0 million for 2007. Operating revenues decreased $37.1 million and operating expenses decreased $59.1 million. Contributing to the net loss in 2008 was losses on long-term venture fund investments and litigation costs. The net loss for 2007 and the decrease in operating revenues and expenses were primarily due to the sale of Avista Energy in 2007.

2007 compared to 2006

Net loss from these operations was $12.0 million for 2007 compared to net income of $8.9 million for 2006. Operating revenues decreased $116.6 million and operating expenses decreased $81.9 million. The net loss for 2007 and the decrease in operating revenues and expenses were primarily due to Avista Energy. The decline in results at Avista Energy in 2007 was primarily due to the underperformance on the power side of the business, losses on the power purchase agreement for the Lancaster Plant, and a loss on the sale of net assets to Shell Energy in June 2007.

New Accounting Standards

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (FIN 48) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of FIN 48 did not have a cumulative effect on our financial statements. See Note 13 for further information.

Effective January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. We will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008, did not have a material impact on our financial condition and results of operations. However, we expanded disclosures with respect to fair value measurements. See Note 22 for the expanded disclosures.

Effective January 1, 2008, we adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option is elected would be reported in net income. We did not elect to use the fair value option under SFAS No. 159 for any financial assets and liabilities at implementation and as such the adoption of SFAS No. 159 did not have any impact on our financial condition and results of operations.

 

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Effective January 1, 2008, we adopted FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39.” FSP FIN 39-1 amends certain paragraphs of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts, an interpretation of APB Opinion No. 10 and FASB Statement No. 105.” This statement permits an entity to offset fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. As of December 31, 2008 we did not offset any fair value cash collateral receivables against net derivative positions.

Effective December 31, 2006, SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132 (R)” required us to recognize the overfunded or underfunded status of defined benefit postretirement plans in our Consolidated Balance Sheet measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plans, the benefit obligation is the accumulated postretirement benefit obligation. Previously, we only recognized the underfunded status of defined benefit pension plans as the difference between the fair value of plan assets and the accumulated benefit obligation. As we have historically recovered and currently recover our pension and other postretirement benefit costs related to our regulated operations in retail rates, we record a regulatory asset for that portion of our pension and other postretirement benefit funding deficiency. As such, the underfunded status of our pension and other postretirement benefit plans under SFAS No. 158 resulted in the recognition as of December 31, 2006 of:

 

   

a liability of $60.1 million (associated deferred taxes of $21.0 million) for pensions and other postretirement benefits,

 

   

a regulatory asset of $54.2 million (associated deferred taxes of $19.0 million) for pensions and other postretirement benefits,

 

   

an increase to accumulated other comprehensive loss of $3.7 million (net of taxes of $2.1 million), and

 

   

the removal of the intangible pension asset of $3.7 million (was included in other deferred charges).

As such, the total effect on the deferred income tax liability for the adoption of SFAS No. 158 was a net decrease of $2.1 million. The adoption of this statement did not have any effect on our net income.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. We will be required to begin applying this statement to any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. We will be required to adopt SFAS No. 160 in 2009. We do not expect the adoption of SFAS No. 160 to have any material impact on our financial condition and results of operations. However, it will impact the presentation and disclosure of noncontrolling (minority) interests in the consolidated financial statements. We are still in the process of evaluating the full impact SFAS No. 160 will have on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement will require disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement will also require disclosure of derivative features that are related to credit risk. We will be required to adopt SFAS No. 161 in 2009. We will have expanded disclosures with respect to derivatives and hedging activities.

In December 2008, the FASB issued FSP 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”. This FSP amends FASB statement No. 132(R) “Employer’s Disclosures about Pensions and Other Postretirement Benefits.” This statement provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. We will be required to adopt FSP 132(R)-1 at the end of 2009. We will have expanded disclosures with respect to our pension and other postretirement benefit plan assets.

 

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Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements that require the use of estimates and assumptions:

Avista Utilities Operating Revenues

Operating revenues for our utility related to the sale of energy are generally recorded when service is rendered or energy is delivered to our customers. The determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, we estimate the amount of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue is estimated and recorded.

Our estimate of unbilled revenue is based on:

 

   

the number of customers,

 

   

current rates,

 

   

meter reading dates,

 

   

actual native load for electricity, and

 

   

actual throughput for natural gas.

Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs.

Regulatory Accounting

We prepare our consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” for our regulated utility operations. SFAS No. 71 requires us to reflect the effect of regulatory decisions in our financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our statement of income until the period during which matching revenues are recognized. We expect to recover our regulatory assets through future rates. Our regulatory assets are subject to review for prudence and recoverability. As such, certain deferred costs may be disallowed by our regulators. If at some point in the future we determine that we no longer meet the criteria for continued application of SFAS No. 71 for all or a portion of our regulated operations, we could be:

 

   

required to write off regulatory assets, and

 

   

precluded from the future deferral of costs not recovered through rates when such costs are incurred, even if we expect to recover such costs in the future.

Utility Energy Commodity Derivative Assets and Liabilities

Our utility enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of our management of loads and resources and certain contracts are considered derivative instruments. In conjunction with the provisions of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing us to offset any 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. As such, we do not recognize unrealized gains or losses on utility derivative commodity instruments in our Consolidated Statements of Income. We recognize realized gains or losses in the period of settlement, subject to regulatory 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 and the PCA mechanism. We use quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments. As such, the fair value of utility derivative commodity instruments recorded on our Consolidated Balance Sheets is sensitive to market price fluctuations that can occur on a daily basis.

 

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Pension Plans and Other Postretirement Benefit Plans

We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities.

Our Finance Committee of the Board of Directors:

 

   

establishes investment policies, objectives and strategies that seek an appropriate return for the pension plan, and

 

   

reviews and approves changes to the investment and funding policies.

We have contracted with an investment consultant who is responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies.

Our pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real estate, absolute return, venture capital/private equity and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established investment allocation percentages by asset classes as disclosed in “Note 12 of the Notes to Consolidated Financial Statements.”

We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to our executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans.

Pension costs (including the SERP) were $13.9 million for 2008, $14.3 million for 2007 and $14.5 million for 2006. Of our pension costs, approximately 65 percent are expensed and 35 percent are capitalized consistent with labor charges. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by:

 

   

employee demographics (including age, compensation and length of service by employees),

 

   

the amount of cash contributions we make to the pension plan, and

 

   

the return on pension plan assets.

Changes made to the provisions of our pension plan may also affect current and future pension costs. Pension plan costs may also be significantly affected by changes in key actuarial assumptions, including the:

 

   

expected return on pension plan assets,

 

   

discount rate used in determining the projected benefit obligation and pension costs, and

 

   

assumed rate of increase in employee compensation.

The change in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statement of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.

In 2008, the rates at which participants are assumed to retire by age were analyzed based upon historical trends and future projections. We revised the rates to assume that a greater percentage of participants would retire between the ages of 55 and 65. The assumed rates were revised to range from 5% to 40% and 100% at age 65. The previous rates ranged from 2% to 30% and 100% at age 65. The change resulted in an increase of $11.0 million to the pension benefit obligation as of December 31, 2008. The changes will also increase future years’ pension costs.

We have not made any changes to pension plan provisions in 2008, 2007 and 2006 that have had any significant effect on our recorded pension plan amounts. We have revised the key assumption of the discount rate in 2008, 2007 and 2006. Such changes had an effect on our pension costs in 2008, 2007 and 2006 and may affect future years, given the cost recognition approach described above. However, in determining pension obligation and cost amounts, our assumptions can change from period to period, and such changes could result in material changes to our future pension costs and funding requirements.

In selecting a discount rate, we consider yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. We decreased the pension plan discount rate in 2008 from 6.35 percent to 6.25 percent. In 2007 we used the 6.35% rate for estimating our benefit obligation.

 

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The assumed long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by our plan. The assumed long-term rate of return was 8.5 percent in each of 2008, 2007 and 2006. The actual return on plan assets, net of fees, was a loss of $63.2 million (or -25.5 percent) for 2008, a gain of $18.3 million (or 8.1 percent) for 2007 and a gain of $25.2 million (or 12.6 percent) for 2006. We periodically analyze the estimated long-term rate of return on assets based upon revisions to the investment portfolio.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands):

 

Actuarial Assumption

   Change in
Assumption
    Effect on Projected
Benefit Obligation
    Effect on
Pension Cost
 

Expected long-term return on plan assets

   -0.5 %   $ —   *   $ 1,243  

Expected long-term return on plan assets

   +0.5 %     —   *     (1,243 )

Discount rate

   -0.5 %     22,384       2,180  

Discount rate

   +0.5 %     (20,179 )     (1,983 )

 

* Changes in the expected return on plan assets would not have an effect on our total pension liability.

We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service. Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase our accumulated postretirement benefit obligation as of December 31, 2008 by $2.1 million and the service and interest cost by $0.2 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease our accumulated postretirement benefit obligation as of December 31, 2008 by $1.8 million and the service and interest cost by $0.2 million.

Stock-Based Compensation

We recognize compensation costs relating to share-based payment transactions in our financial statements based on the fair value of the equity or liability instruments issued. We measure (at the grant date) the estimated fair value of performance shares granted in accordance with the provisions of SFAS No. 123R. The fair value of each performance share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to a peer group. Expected volatility is based on the historical volatility of our common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle. The risk-free interest rate is based on the U.S. Treasury yield at the time of grant.

Contingencies

We have unresolved regulatory, legal and tax issues for which there is inherent uncertainty with respect to the ultimate outcome of the respective matter. We account for contingencies in accordance with SFAS No. 5, “Accounting for Contingencies,” as well as other accounting guidance specific to a particular issue. In accordance with SFAS No. 5, we accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.

For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given for the ultimate outcome of any particular contingency.

 

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Liquidity and Capital Resources

Review of Cash Flow Statement

Overall In April 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $249.2 million (net of issuance discount and before Avista Corp.’s expenses), together with other available funds, were used to fund the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. In December 2008, we issued $30.0 million of 7.25 percent First Mortgage Bonds due in 2013 and refinanced $17.0 million of Pollution Control Bonds. The proceeds from the $30.0 million issuance, together with funds borrowed under the $320.0 million committed line of credit, were used to fund $25.0 million of medium term notes that matured in December 2008 and $66.7 million of Pollution Control Bonds that we purchased in December 2008. During 2008, positive cash flows from operating activities of $115.6 million and a $252.2 million increase in short-term borrowings were used to fund the majority of our remaining cash requirements. These cash requirements included utility capital expenditures of $219.2 million, the cash settlement of interest rate swap agreements of $16.4 million and dividends of $37.1 million.

Operating Activities Net cash provided by operating activities was $115.4 million for 2008 compared to $251.6 million for 2007. The overall decrease was due in part to the sale of Avista Energy’s contracts and liquidation of Avista Energy’s remaining net current assets that is reflected in the 2007 activity, payments made related to the settlement of water storage on Coeur d’Alene Tribe land, the increase in accounts receivable and the decrease in the amount of receivables that were sold. Net cash used by working capital components was $113.8 million for 2008, compared to cash provided of $80.9 million for 2007. The net cash used during 2008 primarily reflects a decrease in cash flows from:

 

   

accounts receivable (representing an increase in the receivables outstanding and a $68.0 million decrease in the amount of receivables that were sold),

 

   

deposits from counterparties (representing the return to counterparties of cash posted as collateral at Avista Utilities), and

 

   

materials and supplies, fuel stock and natural gas stored (primarily representing an increase in natural gas that was stored).

This cash used was partially offset by positive cash flows from accounts payable (representing an increase in accounts payable).

The net cash provided during 2007 primarily reflects positive cash flows from:

 

   

accounts receivable (representing net cash received from our customers primarily related to the liquidation of Avista Energy’s receivables), and

 

   

deposits with counterparties (representing the return from counterparties of cash posted as collateral at Avista Energy).

This cash provided was partially offset by negative cash flows from accounts payable (representing cash paid to our vendors primarily related to the liquidation of Avista Energy’s payables) and deposits from counterparties (representing cash returned that was collateral funds from counterparties at Avista Utilities).

Significant non-cash items included $45.8 million of power and natural gas cost amortizations, net of deferrals, for 2008, an increase from $19.6 million for 2007. There was also an increase in the provision for deferred income taxes to $44.2 million for 2008 from a benefit of $7.4 million for 2007. Income tax payments (net of refunds) decreased to $10.0 million for 2008, compared to $29.4 million for 2007.

Investing Activities Net cash used in investing activities was $185.3 million for 2008, a slight increase compared to $186.3 million for 2007. Utility property capital expenditures increased in 2008 as compared to 2007, and funds held from customers at Advantage IQ decreased. This was offset by a change in restricted cash. We liquidated $25.8 million of restricted cash in 2007 primarily representing the return of cash collateralizing energy contracts at Avista Energy.

The purchase of subsidiary minority interest of $6.6 million primarily represents the redemption of common stock from employees of Advantage IQ. Advantage IQ’s employee stock incentive plan provides an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value upon the date of reacquisition.

 

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Financing Activities Net cash provided by financing activities was $82.4 million for 2008 compared to net cash used of $81.7 million for 2007. During 2008, our short-term borrowings increased $252.2 million, which reflects an increase in the amount of debt outstanding under our $320.0 million committed line of credit. Net proceeds from long-term debt issuances were $296.2 million in 2008 and common stock issuances increased to $28.6 million for 2008 (primarily $16.6 million from the issuance of 750,000 shares of common stock under a sales agency agreement). Debt maturities were $403.9 million and cash paid to settle interest rate swaps was $16.4 million in 2008. Cash dividends paid increased to $37.1 million (or 69.0 cents per share) for 2008 from $31.5 million (or 59.5 cents per share) for 2007. Additionally, customer funds obligations at Advantage IQ decreased by $30.8 million.

During 2007, our short-term borrowings decreased $4.0 million, which reflects a decrease in the amount of debt outstanding under our $320.0 million committed line of credit. Debt maturities were $26.7 million for 2007 and we redeemed the remaining $26.3 million of our preferred stock outstanding as required.

Overall Liquidity

Our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from our utility operations include the purchase of electricity and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

We design operating and capital budgets to control operating costs and optimize capital expenditures, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction, improvement and maintenance of utility facilities.

Over time, our operating cash flows usually do not fully support the amount required for utility capital expenditures. As such, from time to time, we need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

We periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. Effective January 1, 2008, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $30.2 million and annual natural gas revenues by $3.3 million. Effective January 1, 2009, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $32.5 million and annual natural gas revenues by $4.8 million. Effective October 1, 2008, the IPUC authorized an increase in our rates in Idaho designed to increase annual electric revenues by $23.2 million and annual natural gas revenues by $3.9 million. See further details in the section “Avista Utilities – Regulatory Matters.”

With respect to our utility operations, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

 

   

increases in demand (either due to weather or customer growth),

 

   

low availability of streamflows for hydroelectric generation,

 

   

unplanned outages at generating facilities, and

 

   

failure of third parties to deliver on energy or capacity contracts.

We monitor the potential liquidity impacts of increasing energy commodity prices for our utility operations. We believe that we have adequate liquidity to meet the increased cash needs of higher energy commodity prices through our:

 

   

$320.0 million committed line of credit,

 

   

$200.0 million committed line of credit, and

 

   

$85.0 million revolving accounts receivable sales facility.

As of December 31, 2008, we had a combined $313.7 million of available liquidity under the three facilities described above. We anticipate issuing long-term debt and common stock during 2009 to reduce the balances outstanding under our committed line of credit agreements. Additionally, we are planning to remarket or refund the $66.7 million of Pollution Control Bonds during 2009.

 

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Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Credit and Nonperformance Risk

Our contracts for the purchase and sale of energy commodities often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in our credit ratings or adverse changes in market prices. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below investment grade and energy prices decreased by 15 percent in the first year and 20 percent in subsequent years, we estimate, based on our positions outstanding at December 31, 2008, that we would have had to post additional collateral of approximately $163.0 million.

Our utility held cash deposits from other parties in the amount of $0.2 million as of December 31, 2008, a decrease from $12.5 million as of December 31, 2007. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, consisted of the following as of December 31, 2008 and 2007 (dollars in thousands):

 

     December 31, 2008     December 31, 2007  
     Amount    Percent
of total
    Amount    Percent
of total
 

Current portion of long-term debt

   $ 17,207    0.8 %   $ 427,344    21.6 %

Short-term borrowings

     252,200    11.5       —      —    

Long-term debt to affiliated trusts

     113,403    5.2       113,403    5.8  

Long-term debt

     809,258    37.0       521,489    26.4  
                          

Total debt

     1,192,068    54.5       1,062,236    53.8  

Stockholders’ equity

     996,883    45.5       913,966    46.2  
                          

Total

   $ 2,188,951    100.0 %   $ 1,976,202    100.0 %
                          

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $82.9 million during 2008 primarily due to net income, other comprehensive income and the issuance of common stock under the sales agency agreement and other plans, partially offset by dividends.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities, issuance of long-term debt and common stock issuance are expected to be the primary source of funds for operating needs, dividends and capital expenditures for 2009. Borrowings under our $320.0 million committed line of credit, $200.0 million committed line of credit and sales of accounts receivable under our $85.0 million revolving facility may supplement these funds to the extent necessary.

We do not have any scheduled long-term debt maturities in 2009. The current portion of long-term debt includes $17.0 million of Pollution Control Bonds because they are subject to purchase at any time at the option of the bond holder. We are planning to issue long-term debt and common stock during 2009 to repay a portion of the amounts that are outstanding on our credit agreement.

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011 with the following banks:

 

     Commitment (in millions)

The Bank of New York Mellon

   $45.0

Union Bank of California, N.A.

   $45.0

Wells Fargo Bank, National Association

   $35.0

US Bank National Association

   $35.0

Keybank National Association

   $35.0

 

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     Commitment (in millions)

Bank of America, N.A.

   $30.0

Mizuho Corporate Bank, LTD

   $25.0

Comerica West Incorporated

   $20.0

Goldman Sachs Credit Partners, L.P.

   $15.0

Societe Generale

   $15.0

First Commercial Bank, New York

   $10.0

Bank Hapoalim B.M., New York Branch

   $10.0

Under the agreement, we can request the issuance of up to $320.0 million in letters of credit. As of December 31, 2008, we had $250.0 million in borrowings outstanding under this committed line of credit, an increase from no borrowings outstanding as of December 31, 2007. As of December 31, 2008, there were $24.3 million in letters of credit outstanding, a decrease from $34.8 million as of December 31, 2007. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Additionally, in November 2008, we entered into a new committed line of credit in the total amount of $200.0 million with an expiration date of November 2009 with the following banks:

 

     Commitment (in millions)

Union Bank of California, N.A.

   $44.25

Wells Fargo Bank, National Association

   $44.25

JPMorgan Chase Bank, N.A.

   $26.50

Keybank National Association

   $22.00

Suntrust Bank

   $22.00

US Bank National Association

   $17.50

The Bank of New York Mellon

   $13.50

UBS Loan Finance LLC

   $10.00

As of December 31, 2008, we did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $200.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Our committed line of credit agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of December 31, 2008, we were in compliance with this covenant with a ratio of 3.27 to 1. The committed line of credit agreements also have a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at any time. As of December 31, 2008, we were in compliance with this covenant with a ratio of 54.5 percent. If the proposed change in organization to a holding company structure becomes effective, the committed line of credit agreements will remain at Avista Corp. (Avista Utilities). See “Note 28 of the Notes to Consolidated Financial Statements” for further information on the proposed change in organization to a holding company structure. The committed line of credit agreements also have a covenant which requires the Company to maintain a minimum funded ratio of the pension plan assets to liabilities. The Pension Protection Act of 2006 (that was implemented in 2008) modified the liability calculation utilized to calculate the funded ratio. Avista Corp. amended the covenant related to the pension funded ratio, under its $320.0 million committed line of credit agreement, to conform with the calculations under the Pension Protection Act of 2006.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We do not guarantee the indebtedness of any of our subsidiaries. As of December 31, 2008, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

We are restricted under our Restated Articles of Incorporation as to the additional preferred stock we can issue. As of December 31, 2008, we could issue $706.2 million of additional preferred stock at an assumed dividend rate of 6.95 percent.

 

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Under the Mortgage and Deed of Trust securing our First Mortgage Bonds (including Secured Medium-Term Notes), we may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of:

 

   

70 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or

 

   

an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage; or

 

   

deposit of cash

provided, however, that we may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless our “net earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2008, our property additions and retired bonds would have entitled us to issue $688.9 million in aggregate principal amount of additional First Mortgage Bonds. However, using an interest rate of 8 percent on additional First Mortgage Bonds, and based on net earnings for the 12 months ended December 31, 2008, the net earnings test would limit the principal amount of additional bonds we could issue to $545.9 million. We believe that we have adequate capacity to issue First Mortgage Bonds to meet our financing needs over the next several years.

In December 2005, the WUTC issued an order approving the settlement agreement reached in our Washington general rate case with certain conditions. We agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. Our utility equity component met this target as it was approximately 47.6 percent as of December 31, 2008.

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We issued 750,000 shares of common stock (total net proceeds of $16.6 million) under this sales agency agreement during the third quarter of 2008. These were our first issuances under the sales agency agreement. We will continue to evaluate issuing common stock in future periods.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is our wholly owned, bankruptcy-remote subsidiary formed for the purpose of acquiring or purchasing interests in certain of our accounts receivable, both billed and unbilled. On March 14, 2008, Avista Corp., ARC and Bank of America, N.A. amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 17, 2008 to March 13, 2009.

The Receivables Purchase Agreement was originally entered into on May 29, 2002 and provides us with cost-effective funds for:

 

   

working capital requirements,

 

   

capital expenditures, and

 

   

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our ommitted line of credit agreements. As of December 31, 2008, we had the ability to sell up to $85.0 million of receivables and there was $17.0 million in accounts receivable sold under this revolving agreement. We expect to renew this facility before the March 13, 2009 expiration.

Spokane Energy, LLC

In December 1998, we received cash proceeds of $143.4 million from a transaction in which we assigned and transferred certain rights under a long-term power sales contract with Portland General Electric Company (PGE) to a funding trust. Pursuant to orders from the WUTC and the IPUC, we fully amortized this amount by the end of 2002.

Under this power exchange arrangement, Peaker, LLC (Peaker) purchases capacity from our utility and sells capacity to Spokane Energy LLC (Spokane Energy), our unconsolidated subsidiary formed in 1998 solely for the purpose of facilitating a long-term capacity contract between PGE and Avista Corp. Spokane Energy sells the related capacity to PGE. Peaker acts as an intermediary to fulfill certain regulatory requirements between Spokane Energy and Avista Corp. The transaction is structured such that Spokane Energy bears full recourse risk for a loan (balance of $80.7

 

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million as of December 31, 2008) that matures in January 2015. We have no recourse related to this loan. Peaker makes monthly payments (which are not material to our financial statements) to us for its capacity purchase.

Credit Ratings

The following table summarizes our credit ratings as of February 27, 2009:

 

     Standard & Poor’s (1)    Moody’s (2)    Fitch, Inc. (3)

Avista Corporation

        

Corporate/Issuer rating

   BBB-    Baa3    BB+

Senior secured debt (4)

   BBB+    Baa2    BBB

Senior unsecured debt

   BBB-    Baa3    BBB-

Preferred stock

   BB    Ba2    BB+

Avista Capital II (5)

        

Preferred Trust Securities

   BB    Ba1    BB+

AVA Capital Trust III (5)

        

Preferred Trust Securities

   BB    Ba1    BB+

Rating outlook

   Stable    Stable    Positive

 

  (1) Ratings were upgraded in February 2008.
  (2) Ratings were upgraded in December 2007.
  (3) Ratings were upgraded in August 2007 and affirmed in February 2008.
  (4) Based on our understanding of the methodology currently used by Standard & Poor’s, the rating on senior secured debt may depend on, among other things, the amount of our utility property (net of depreciation) relative to the amount of such debt outstanding and the amount currently issuable. Thus, the rating on senior secured debt as of any particular time may depend on factors affecting our utility property accounts, as well as factors affecting the principal amount of such debt issued and issuable, including factors affecting our net income.
  (5) Only assets are subordinated debentures of Avista Corporation.

Each security rating agency has its own methodology for assigning ratings. Security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other ratings.

Pension Plan

As of December 31, 2008, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $28 million to the pension plan in 2008 and $15 million in both 2006 and 2007. Our total pension plan contributions were $112 million from 2002 through 2008. Due to market conditions and the decline in the fair value of pension plan assets, we plan to contribute $48 million to the pension plan in 2009. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We have adequate liquidity to meet our pension plan funding obligations for 2009.

Dividends

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:

 

   

our results of operations, cash flows and financial condition,

 

   

the success of our business strategies, and

 

   

general economic and competitive conditions.

Our net income available for dividends is primarily derived from our regulated utility operations.

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in our Restated Articles of Incorporation, as amended.

On February 13, 2009, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.18 per share on the Company’s common stock.

As further discussed at “Note 28 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions if and when we implement a holding company structure. One of the conditions would require IPUC approval of any dividend to the holding

 

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company that would reduce utility common equity below 25 percent. We entered into a similar agreement in Washington. This agreement would require WUTC approval of any dividend to the holding company that would reduce utility common equity below 30 percent. The utility equity component was approximately 47.6 percent as of December 31, 2008.

Avista Utilities Operations

Capital expenditures for our utility were $586.3 million for the years 2006 through 2008. We expect utility capital expenditures to be over $210 million for each of 2009, 2010 and 2011. In addition to ongoing needs for our distribution system, significant projects include upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. There are no scheduled long-term debt maturities in 2009 and $35.0 million of scheduled maturities in 2010.

Two series of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds became subject to remarketing in December 2008. The $66.7 million series was purchased by us and we expect that at a later date, subject to market conditions, these bonds will be remarketed to unaffiliated investors or refunded by a new issue. The $17.0 million series was refunded by a new issue.

See “Notes 6, 15, 16, 17, 18, 21, 22 and 23 of Notes to Consolidated Financial Statements” for additional details related to our financing activities.

We are committed to investment in generation, transmission and distribution systems with a focus on increasing capacity and improving reliability. We continue to upgrade hydroelectric plants to increase their availability and capture additional output.

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of over $125 million with the majority of the costs expected to be incurred in 2013 and thereafter. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

We are participating in planning activities for the development of a proposed 3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. Other participants include Pacific Gas and Electric Company, PacifiCorp, and British Columbia Transmission Corporation. We have executed an agreement (stage one agreement) with the other participants in order to perform preliminary studies and assessments for the project, including electrical system studies and resource mapping of possible transmission line corridors. Under the stage one agreement, we have committed to contribute $0.6 million, or 12.25 percent of the total stage one costs of the project.

Advantage IQ Operations

Capital expenditures for Advantage IQ were $8.2 million for the years 2006 through 2008. We do not expect capital expenditures for the years 2009 through 2011 for Advantage IQ to be significant to our consolidated cash flows and financial condition. However, they are expected to be higher than past years to improve technology that will support continued growth and reliable service to customers. These capital expenditures should be funded by Advantage IQ’s cash flows from operations. As of December 31, 2008, Advantage IQ had $0.1 million of debt outstanding related to capital leases.

In 2007, Advantage IQ amended its employee stock incentive plan to provide an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value at the date of reacquisition. This plan was amended to provide liquidity to participants of Advantage IQ’s stock option plan. As the repurchase feature is at the discretion of the minority shareholders and option holders, a liability of $10.4 million was outstanding as of December 31, 2008 for the intrinsic value of stock options outstanding, as well as outstanding redeemable stock. Additionally, Advantage IQ has a liability of $28.8 million related to the Cadence Network acquisition as the previous owners can exercise a right to put their stock back to Advantage IQ (refer to Note 5 of the Notes to Consolidated Financial Statements for further information. As of December 31, 2007, this liability was $14.0 million. During 2008, $6.6 million of common stock was repurchased from Advantage IQ employees.

In February 2008, Advantage IQ entered into a $12.5 million committed credit agreement with a bank that has an expiration date of February 2011. Advantage IQ has the ability to increase the credit facility to $25 million under the

 

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same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $2.2 million of borrowings outstanding under the credit agreement as of December 31, 2008.

Other Operations

Capital expenditures for these companies were $2.3 million for the years 2006 through 2008. We do not expect capital expenditures for the years 2009 through 2011 for these companies to be significant to our consolidated cash flows and financial condition. As of December 31, 2008, these companies had $2.8 million of long-term debt outstanding.

Contractual Obligations

The following table provides a summary of our future contractual obligations as of December 31, 2008 (dollars in millions):

 

     2009    2010    2011    2012    2013    Thereafter

Avista Utilities:

                 

Long-term debt maturities (1)

   $ 17    $ 35    $ —      $ 7    $ 75    $ 706

Long-term debt to affiliated trusts

     —        —        —        —        —        113

Interest payments on long-term debt (2)

     56      55      53      53      52      666

Short-term borrowings

     250      —        —        —        —        —  

Energy purchase contracts (3)

     410      222      163      133      113      864

Public Utility District contracts (3)

     5      3      3      3      2      34

Operating lease obligations (4)

     1      —        —        —        —        2

Other obligations (5)

     25      28      26      29      30      247

Payments to Coeur d’Alene tribe

     10      4      —        —        —        —  

Information services contracts

     15      15      15      15      15      —  

Pension plan funding (6)

     48      21      21      31      31      —  

Avista Capital (consolidated):

                 

Long-term debt

     —        —        —        —        —        3

Short-term debt

     2      —        —        —        —        —  

Energy purchase contracts (7)

     22      27      27      27      26      290

Venture funds investments (8)

     3      2      —        —        —        —  

Operating lease obligations (4)

     3      2      —        —        —        1
                                         

Total contractual obligations

   $ 867    $ 414    $ 308    $ 298    $ 344    $ 2,926
                                         

 

(1) We do not have any scheduled long-term debt maturities in 2009. The obligation for 2009 includes $17 million of bonds because they are subject to purchase at any time at the option of the bond holder.
(2) Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2008.
(3) Energy purchase contracts were entered into as part of the obligation to serve our 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.
(4) Includes the interest component of the lease obligation. Future capital lease obligations are not material.
(5) Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.
(6) Represents our estimated cash contributions to the pension plan through 2013. We cannot reasonably estimate pension plan contributions beyond 2013 at this time.
(7) These contractual commitments are primarily related to the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned by Avista Energy to Shell Energy through the end of 2009. Beginning in 2010 through 2026, the rights and obligations of the power purchase agreement for the Lancaster Plant are contracted to Avista Energy. We expect these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.
(8) Represents our commitment to fund a limited partnership venture fund commitment made by a subsidiary of Avista Capital.

These contractual obligations do not include income tax payments, including any payments related to uncertain tax positions. The timing of the payments on uncertain tax positions is not reasonably determinable.

In addition to the contractual obligations disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations.

 

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Competition

Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as set by our regulators.

In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternate providers of energy may also compete with us for sales to existing customers. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

In wholesale markets, competition for available electric supply is influenced by the:

 

   

localized and system-wide demand for energy,

 

   

type, capacity, location and availability of generation resources, and

 

   

variety and circumstances of market participants.

These wholesale markets are regulated by the FERC under authority of The Energy Policy Act of 1992 and other federal laws. The FERC requires electric utilities to:

 

   

transmit power and energy to or for wholesale purchasers and sellers,

 

   

enlarge or construct additional transmission capacity for the purpose of providing these services, and

 

   

transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

Participants in the wholesale energy markets include:

 

   

other utilities,

 

   

federal power marketing agencies,

 

   

energy marketing and trading companies,

 

   

independent power producers,

 

   

financial institutions, and

 

   

commodity brokers.

We actively monitor and participate, as appropriate in energy industry developments, to maintain and enhance the ability to effectively participate in wholesale energy markets consistent with our business goals.

Advantage IQ is subject to competition for service to existing customers and as they develop products and services and enter new markets. Competition from other companies may mean challenges for Advantage IQ to be the first to market a new product or service to gain the advantage in market share. Other challenges for Advantage IQ include the availability of funding and resources to meet capital needs, and rapidly advancing technologies which requires continual product enhancement to avoid obsolescence.

Business Risk

Primarily through our utility operations, we are exposed to risks including, but not limited to:

 

   

global financial and economic conditions (including the availability of credit) and their effect on our ability to obtain funding for working capital and long-term capital requirements on acceptable terms,

 

   

economic conditions in our service areas, including the effect on the demand for, and customers’ ability to pay for, our utility services,

 

   

streamflow and weather conditions that impact hydroelectric generation, utility operations and customer demand,

 

   

market prices and supply of wholesale energy, which we purchase and sell, including power, fuel and natural gas,

 

   

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments and the allowance of a reasonable rate of return on investment,

 

   

the effects of changes in legislative and governmental regulations, including restrictions on emissions from generating plants and requirements for the acquisition of new resources,

 

   

changes in regulatory requirements,

 

   

availability of generation facilities,

 

   

customer response to rate increases, and

 

   

competition.

 

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Also, like other utilities, our facilities and operations are exposed to natural disasters and terrorism risks or other malicious acts. In addition, the energy business exposes us to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of energy commodities. See further reference to risks and uncertainties under “Forward-Looking Statements.”

We have mechanisms in each regulatory jurisdiction that provide for recovery of the majority of the changes in our power and natural gas costs. The majority of power and natural gas costs exceeding the amount currently recovered through retail rates, excluding the ERM deadband in Washington, are deferred on our Consolidated Balance Sheets for the opportunity for recovery through future retail rates. These deferred power and natural gas costs are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Our hydroelectric generation was 99 percent of normal in 2008. Our hydroelectric generation was below normal (based on a 70-year average) for seven of the past nine years. We cannot determine if lower than normal hydroelectric generation will continue in future years. When we have excess hydroelectric generation, its value varies with market prices and other displaceable resources. When hydroelectric generation is below normal, the cost to obtain power from other sources is generally higher. When hydroelectric generation is above normal, prices in the wholesale market are often depressed which can adversely impact our surplus sales revenues. We are not able to predict how the combination of energy resources, energy loads, prices, rate recovery and other factors will ultimately drive deferred power costs and the timing of recovery of our costs in future periods. See further information at “Avista Utilities - Regulatory Matters.”

Market prices for natural gas continue to be competitive compared to alternative fuel sources for customers, and we believe that natural gas should sustain its long-term market advantage over competing energy sources based on the levels of existing reserves and potential natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction and conversions from competing space and water heating energy sources to natural gas.

Certain natural gas customers could by-pass our natural gas system reducing both revenues and recovery of fixed costs. To reduce the potential for such by-pass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers. This reduces the risk of these customers by-passing our system in the foreseeable future and minimizes the impact on our earnings.

The FERC continues to conduct proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds and some of the FERC’s decisions have been appealed in Federal Courts. Certain parties have asserted claims for significant refunds from us, which could result in liabilities for refunding revenues recognized in prior periods. We have joined other parties in opposing these proposals. We believe that we have adequate reserves established for refunds that may be ordered. The refund proceedings provide that any refunds would be offset against unpaid energy debts due to the same party. As of December 31, 2008, our accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. See “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 26 of the Notes to Consolidated Financial Statements” for further information with respect to the refund proceedings.

We engage in wholesale sales and purchases of energy commodities and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

Commodity Price Risk

In general, price risk is driven by fluctuation in the market price of the commodity needed, held or traded. The price of energy in wholesale markets is affected primarily by fundamental factors related to production costs and by other factors including weather and the resulting impact on retail loads. We hedge our exposure to price risk by making forward commitments for energy purchases and sales as further described under “Risk Management”.

Electricity prices are affected by a number of factors, including:

 

   

demand for electricity,

 

   

the number of market participants and the willingness of market participants to trade,

 

   

adequacy of generating reserve margins,

 

   

scheduled and unscheduled outages of generating facilities,

 

   

availability of streamflows for hydroelectric generation,

 

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price and availability of fuel for thermal generating plants, and

 

   

disruptions of or constraints on transmission facilities.

Natural gas prices are affected by a number of factors, including:

 

   

amount of North American production and production capacity that can be delivered to our service areas,

 

   

level of imports and exports, particularly from Canada by pipeline and to a growing extent by LNG,

 

   

level of inventories and regional accessibility,

 

   

demand for natural gas, including natural gas as fuel for electric generation,

 

   

the number of market participants and the willingness of market participants to trade,

 

   

global energy markets, including oil or other natural gas substitutes, and

 

   

availability of pipeline capacity to transport natural gas from region to region.

Any combination of these factors that results in a shortage of energy generally causes the market price to move upward. In addition to these factors, wholesale power markets are subject to regulatory constraints including price controls.

Price risk also includes the risk of fluctuation in the market price of associated derivative commodity instruments (such as options and forward contracts). Price risk may also be influenced to the extent that the performance or non-performance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity.

Credit Risk

Credit risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. We often extend credit to counterparties and customers, and we are exposed to the risk of not being able to collect amounts owed to us. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Credit risk includes potential counterparty default due to circumstances:

 

   

relating directly to the counterparty,

 

   

caused by market price changes, and

 

   

relating to other market participants that have a direct or indirect relationship with such counterparty.

Should a counterparty, customer or supplier fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

We seek to mitigate credit risk by:

 

   

entering into bilateral contracts that specify credit terms and protections against default,

 

   

applying credit limits and duration criteria to existing and prospective counterparties, and

 

   

actively monitoring current credit exposures, and

 

   

conducting some of our transactions on exchanges with clearing arrangements that essentially eliminate counterparty default risk.

Our credit policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. We also use standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group. However, despite mitigation efforts, defaults by our counterparties periodically occur.

We regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. We reduce or eliminate open (unsecured) credit limits and implement other credit risk reduction measures for parties perceived to have increased default risk. Counterparty collateral is used to offset our credit risk where unsettled net positions and future obligations by counterparties to pay us or deliver to us warrant.

We have concentrations of suppliers and customers in the electric and natural gas industries including:

 

   

electric utilities,

 

   

electric generators and transmission providers,

 

   

natural gas producers and pipelines,

 

   

financial institutions, and

 

   

energy marketing and trading companies.

 

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In addition, we have concentrations of credit risk related to geographic location in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

Credit risk also involves the exposure that counterparties perceive related to our ability to perform deliveries and settlement under physical and financial energy contracts. These counterparties may seek assurances of performance in the form of letters of credit, prepayment, or cash deposits.

Credit exposure can change significantly in periods of price volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us, from each counterparty, depends on the extent of forward contracts, unsettled transactions and market prices. There is a risk that we may seek additional collateral from counterparties that are unable or unwilling to provide.

We maintain credit reserves that are based on the evaluation of the credit risk of the overall portfolio. Based on our credit policies, exposures and credit reserves, we do not anticipate a materially adverse effect on our financial condition or results of operations as a result of counterparty nonperformance.

Other Operational and Event Risks

We are subject to various operational and event risks, which are common to the utility industry, including:

 

   

blackouts or disruptions to our distribution, transmission or transportation systems,

 

   

forced outages at generating plants,

 

   

fuel quality and availability,

 

   

disruptions to information systems and other administrative resources required for normal operations, and

 

   

weather conditions and natural disasters that can cause physical damage to our property, requiring repairs to restore utility service.

Terrorism and other malicious threats are a risk to the entire utility industry. Potential disruptions to operations or destruction of facilities from terrorism or other malicious acts are not readily determinable. We have taken various steps to mitigate terrorism risks and prepare contingency plans in the event that our facilities are targeted.

Interest Rate Risk

We are affected by fluctuating interest rates related to a portion of our existing debt and our future borrowing requirements. We manage interest rate risk by taking advantage of market conditions when timing the issuance of long-term financings and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. We also have $17.0 million of Pollution Control Bonds with interest rates that adjust daily. Additionally, amounts borrowed under our $320.0 million and $200.0 million committed line of credit agreements have variable interest rates.

In December 2008, we entered into two interest rate swap agreements, totaling $50.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt in 2009. Under the terms of these agreements, the value of the interest rate swaps is determined based upon us paying a fixed rate and receiving a variable rate based on LIBOR. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates. As of December 31, 2008, we had a derivative asset of $0.9 million. We estimate that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2008 would increase this derivative asset by $0.4 million, while a 10-basis-point decrease would decrease the asset by $0.4 million.

In January 2009, the Company entered into two interest rate swaps totaling $50.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt in 2009.

Foreign Currency Risk

A significant portion of our natural gas supply is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars which avoids foreign currency risk. A growing portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. In early 2009, we implemented a process to hedge a portion of the foreign currency risk by purchasing Canadian currency when such commodity transactions are initiated. This risk has not had

 

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a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking.

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have an energy resources risk policy and control procedures to manage these risks, both qualitative and quantitative. Our Risk Management Committee established a risk management policy for energy resources. The Risk Management Committee is comprised of certain officers and other management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses risk assessment and risk management policies, including the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them. Our Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with our risk management policy and control procedures. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values.

We also operate with a wholesale energy markets credit policy. The credit policy is designed to reduce the risk of financial loss in case counterparties default on delivery or settlement obligations and to conserve our liquidity as other parties may place credit limits or require cash collateral.

We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of hourly, daily and weekly load fluctuations. We use the wholesale power markets to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation.

To reduce the impact on our operations of energy market price volatility such as the significant wholesale energy market price changes experienced in 2008, we have initiated longer term hedging practices for electricity (including fuel for generation) and natural gas. Executing this extended hedging program may increase our credit risks, particularly in consideration of the national economic conditions with resultant financial stress among energy market participants. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.

Electric load/resource imbalances within a planning horizon up to 36 months ahead are compared against established volumetric guidelines. Management determines the timing and actions to manage the imbalances. We also assess available resource alternatives and actions that are appropriate for longer-term planning periods. Expected load and resource volumes for forward periods are based on monthly and quarterly averages that may vary significantly from the actual loads and resources within any individual month or operating day. Future projections of resources are updated as forecasted streamflows and other factors differ from prior estimates. Forward power markets may be illiquid, and market products available may not match our desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Our projected natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends four years into the future with the goal of reducing price volatility in our gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years at multiple basins mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

Economic and Utility Load Growth

Along with others in our utility service area, we encourage regional economic development, including expanding existing businesses and attracting new businesses to the Inland Northwest and Southwest Oregon region. Agriculture, mining and lumber were the primary industries for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors have grown in importance in our utility service area.

Based on our forecast for electric customer growth to average 1.8 to 2.0 percent and natural gas customer growth to average 2.5 to 2.7 percent within our service area, we anticipate retail electric and natural gas load growth will average between 1.5 and 2.5 percent annually for the four year period 2009-2012. This forecast of load growth is a

 

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decline as compared to our forecast in the prior year. While the number of electric customers is growing, the average annual usage by each residential electric customer has stabilized. Natural gas sales growth has slowed as retail prices have risen and Company sponsored conservation programs have intensified. Population increases and business growth in our three-state service territory remains above the national average. Natural gas loads for space heating vary significantly with annual fluctuations in weather within our service territories.

The forward-looking projections set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including:

 

   

assumptions relating to weather and economic and competitive conditions,

 

   

internal analysis of company-specific data, such as energy consumption patterns,

 

   

internal business plans, and

 

   

an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling.

Changes in actual experience can vary significantly from our forward-looking projections.

Succession Planning

Maintaining our culture, mission, and long-term strategy by having a strong succession planning and management development process is one of our key strategic initiatives. Our executive officer team continues to work towards ensuring that an effective succession planning process is in place for the best interests of our future. We have implemented bench strength analysis in our management group as well as in key technical and craft areas. The focus is on organizational leadership capability as well as technical proficiency in complex jobs. We have implemented development plans for future successors that identify areas of strengths and weaknesses. Development plans provide action steps that provide new opportunities to work towards ensuring that successor candidates have the needed experience. We believe that our succession planning process, coupled with market based recruitment, provides the right structure to assure that we have the ability to fill vacancies with personnel having adequate training and experience.

Environmental Issues and Other Contingencies

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have an ownership interest are designed and operated in compliance with applicable environmental laws.

We monitor legislative and regulatory developments at all levels of government with respect to environmental issues, particularly those with the potential to alter the operation and productivity of our generating plants and other assets.

Environmental laws and regulations may:

 

   

increase the costs of generating plants,

 

   

increase the lead time for the construction of new generating plants,

 

   

require modification of our existing generating plants,

 

   

require existing generating plants to be curtailed or shut down,

 

   

increase the risk of delay on construction projects,

 

   

reduce the amount of energy available from our generating plants, and

 

   

restrict the types of generating plants that can be built.

As such, compliance with such environmental laws and regulations could result in increases to capital expenditures and operating expenses. However, we intend to seek recovery of incurred costs through the rate making process.

Rising concerns about long-term global climate changes could have a significant effect on our business. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of hydroelectric generation capacity. Changing temperatures could also increase or decrease customer demand. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources.

Greenhouse gas requirements could result in significant costs for us to comply with restrictions on carbon dioxide or other greenhouse gas emissions. Such requirements could also preclude us from developing certain types of generating plants.

We continue to monitor and evaluate the possible adoption of national, regional, or state greenhouse gas requirements. In particular, a greenhouse gas bill was passed by the legislature in the state of Washington and bills

 

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have been introduced in the U. S. Senate and House of Representatives. There will most likely be continuing activity in the near future.

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington started the Western Climate Initiative (WCI) for the purpose of developing regional strategies to address climate change. The Governors of Utah and Montana, and the Premiers of British Columbia, Manitoba, Ontario and Quebec subsequently joined the WCI. In August 2007, the WCI partners set an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. In September 2008, the WCI partners announced recommendations for the design of a regional market-based cap-and-trade program to help achieve this reduction goal. The program will require emitters to cut their greenhouse gas levels by setting a limit (cap) on emissions and then allowing the market to identify the least-cost ways to achieve the limit. These emissions goals were codified under Washington law with the passage of HB 2815 in March 2008. This greenhouse gas bill sets goals to reduce emissions in the state of Washington to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050.

A bill was introduced in January 2009 before the Washington State Legislature to confer authority to the Washington State Department of Ecology (DOE) to implement and enforce a cap and trade regulatory regime. The legislation requires all DOE rules “must be consistent with the regional cap and trade program” designed by the WCI participants. The legislation is currently pending before the Washington State Legislature and outcome is uncertain at this time.

A greenhouse gas emissions performance standard (SB 601) passed into law in the state of Washington during 2007. This law places significant restrictions on greenhouse gas emissions from any new generation plants built in the state of Washington. Furthermore, the bill intends to prevent utilities from entering into long-term contracts (five years or more) to purchase energy produced by plants in other states that do not meet the same restrictions. Currently, the only type of non-renewable base load thermal generating plants that meet these restrictions are natural gas-fired combined-cycle combustion turbines.

Initiative Measure 937 (I-937), the Energy Independence Act, was passed into law through the General Election in Washington in November 2006. I-937 requires investor-owned, cooperative, and government-owned electric utilities with over 25,000 customers to acquire new renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. Failure to comply with renewable energy and energy efficiency standards will result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable resources and/or renewable credits.

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in August 2007, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirement by the various milestone dates. The IRP outlines a preferred resource strategy that calls for 350 MW of natural gas generation, 300 MW of wind generation, 87 MW of conservation, 38 MW of hydroelectric generation plant upgrades and 35 MW of other renewable generation by 2017. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

In October 2007, we became a member of the Chicago Climate Exchange (CCX), North America’s only voluntary, verifiable and legally binding emissions reduction and trading marketplace for all six greenhouse gases. Members agree to reduce their greenhouse gas emissions by 6 percent from an established baseline by 2010. The CCX allows participants who exceed their reduction targets to bank or sell the excess CCX Carbon Financial Instruments. The audit establishing our 2007 baseline emissions was completed in July 2008. We received credit for 1,470 CCX Carbon Financial Instruments in October 2008.

For other environmental issues and other contingencies see “Note 26 of the Notes to Consolidated Financial Statements.”

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Business Risk and – Risk Management,” “Note 7 of the Notes to Consolidated Financial Statements” and “Note 22 of the Notes to Consolidated Financial Statements.”

Item 8. Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Avista Corporation and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

As described in Note 2 to the consolidated financial statements (“Note 2”), during 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. Additionally, as described in Note 2, during 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009, expressed an unqualified opinion on the Company’s internal control over financial reporting.

 

/s/    Deloitte & Touche LLP
Seattle, Washington
February 27, 2009

 

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CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

 

For the Years Ended December 31

Dollars in thousands, except per share amounts

 

     2008     2007     2006  

Operating Revenues:

      

Utility revenues

   $ 1,572,664     $ 1,288,363     $ 1,267,938  

Non-utility energy marketing and trading revenues

     25,225       61,541       177,551  

Other non-utility revenues

     78,874       67,853       60,822  
                        

Total operating revenues

     1,676,763       1,417,757       1,506,311  
                        

Operating Expenses:

      

Utility operating expenses:

      

Resource costs

     1,031,989       780,998       751,646  

Other operating expenses

     206,528       198,778       187,457  

Depreciation and amortization

     87,845       86,091       81,904  

Taxes other than income taxes

     72,057       72,443       69,882  

Non-utility operating expenses:

      

Resource costs

     23,553       68,676       144,137  

Other operating expenses

     65,093       67,783       66,546  

Depreciation and amortization

     4,787       4,559       5,179  
                        

Total operating expenses

     1,491,852       1,279,328       1,306,751  
                        

Income from operations

     184,911       138,429       199,560  
                        

Other Income (Expense):

      

Interest expense

     (73,446 )     (79,142 )     (89,051 )

Interest expense to affiliated trusts

     (6,141 )     (7,298 )     (7,116 )

Capitalized interest

     4,612       3,864       2,934  

Regulatory disallowance of unamortized debt repurchase costs

     —         (3,850 )     —    

Other income - net

     9,309       10,806       8,600  
                        

Total other income (expense)-net

     (65,666 )     (75,620 )     (84,633 )
                        

Income before income taxes

     119,245       62,809       114,927  

Income taxes

     45,625       24,334       41,986  
                        

Net income

   $ 73,620     $ 38,475     $ 72,941  
                        

Weighted-average common shares outstanding (thousands), basic

     53,637       52,796       49,162  

Weighted-average common shares outstanding (thousands), diluted

     54,028       53,263       49,897  

Total earnings per common share, basic (Note 24)

   $ 1.37     $ 0.73     $ 1.48  
                        

Total earnings per common share, diluted (Note 24)

   $ 1.36     $ 0.72     $ 1.46  
                        

Dividends paid per common share

   $ 0.690     $ 0.595     $ 0.570  
                        

The Accompanying Notes are an Integral Part of These Statements.

 

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Table of Contents

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

 

For the Years Ended December 31

Dollars in thousands

 

     2008     2007     2006  

Net income

   $ 73,620     $ 38,475     $ 72,941  
                        

Other Comprehensive Income (Loss):

      

Foreign currency translation adjustment

     —         1,010       (38 )

Reclassification adjustment for foreign currency translation adjustment included in loss on sale of contracts

     —         (2,379 )     —    

Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(2,063), $(1,874) and $436, respectively

     (3,831 )     (3,480 )     810  

Reclassification adjustment for realized losses on interest rate swap agreements deferred as a regulatory asset (included in long-term debt) - net of taxes of $5,738 and $1,308

     10,657       —         2,430  

Change in unfunded benefit obligation for pension plan - net of taxes of $3,602, $1,642 and $4,023, respectively

     6,690       3,050       7,472  

Unrealized losses on derivative commodity instruments - net of taxes of $(324) and $(555), respectively

     —         (602 )     (1,030 )

Reclassification adjustment for realized gains on