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, 2005

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

Pacific 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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 $902,211,367 based on the last reported sale price thereof on the consolidated tape on June 30, 2005.

As of February 28, 2006, 48,617,354 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-Prospectus to be filed in

connection with the annual meeting

of shareholders to be held May 11, 2006

  

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

   4
  

Electric Resources

   4
  

Hydroelectric Relicensing

   5
  

Future Resource Needs

   6
  

Natural Gas Operations

   7
  

Regulatory Issues

   8
  

Industry Restructuring

   9
  

Environmental Issues

   10
  

Avista Utilities Operating Statistics

   12
  

Energy Marketing and Resource Management

   14
  

Avista Energy

   14
  

Avista Power

   15
  

Avista Advantage

   15
  

Other

   15

1A.

  

Risk Factors

   16

1B.

  

Unresolved Staff Comments

   20

2.

  

Properties

   21
  

Avista Utilities

   21

3.

  

Legal Proceedings

   22

4.

  

Submission of Matters to a Vote of Security Holders

   22
   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
  

Avista Corp. Business Segments

   26
  

Executive Level Summary

   27
  

Avista Utilities – Electric Resources

   29
  

Avista Utilities – Regulatory Matters

   29
  

Power Market Issues

   31
  

Energy Policy Act of 2005

   32
  

Results of Operations

   33
  

Overall Operations

   33
  

Avista Utilities

   35
  

Energy Marketing and Resource Management

   42
  

Avista Advantage

   46
  

Other Business Segment

   46
  

New Accounting Standards

   46
  

Critical Accounting Policies and Estimates

   47
  

Liquidity and Capital Resources

   50
  

Review of Cash Flow Statement

   50
  

Overall Liquidity

   50

 

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Capital Resources

   51  
  

Inter-Company Debt; Subordination

   53  
  

Pension Plan

   53  
  

Off-Balance Sheet Arrangements

   53  
  

Spokane Energy, LLC

   54  
  

WP Funding LP

   54  
  

Credit Ratings

   54  
  

Dividends

   54  
  

Avista Utilities Operations

   55  
  

Energy Marketing and Resource Management Operations

   55  
  

Avista Advantage Operations

   56  
  

Other Operations

   57  
  

Contractual Obligations

   57  
  

Competition

   58  
  

Business Risk

   58  
  

Risk Management

   61  
  

Economic and Load Growth

   63  
  

Succession Planning

   63  
  

Environmental Issues and Other Contingencies

   63  

7A.

  

Quantitative and Qualitative Disclosures about Market Risk

   63  

8.

  

Financial Statements and Supplementary Data

   63  
  

Report of Independent Registered Public Accounting Firm

   64  
  

Financial Statements

   65-71  
  

Consolidated Statements of Income

   65  
  

Consolidated Statements of Comprehensive Income

   66  
  

Consolidated Balance Sheets

   67-68  
  

Consolidated Statements of Cash Flows

   69-70  
  

Consolidated Statements of Stockholders’ Equity

   71  
  

Notes to Consolidated Financial Statements

   72  

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   113 *

9A.

  

Controls and Procedures

   113  

9B.

  

Other Information

   115  
   Part III   

10.

  

Directors and Executive Officers of the Registrant

   115  

11.

  

Executive Compensation

   116  

12.

  

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

   117  

13.

  

Certain Relationships and Related Transactions

   117  

14.

  

Principal Accountant Fees and Services

   117  
   Part IV   

15.

  

Exhibits, Financial Statement Schedules

   118  
  

Signatures

   119  
  

Exhibit Index

   120  

* = not an applicable item in the 2005 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

APB

   - Accounting Principles Board

Avista Advantage

   - Avista Advantage, 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 produces 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

Dead band or ERM dead band

   - the first $9.0 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 - a measure of capacity on transmission lines

Lancaster Project

   - the natural gas-fired combined cycle combustion turbine plant located in northern Idaho that is 49 percent owned by Avista Power

KW, KWH

   - Kilowatt or 1000 watts, kilowatt-hour or 1000 watt hours

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

   - Oregon Public Utility Commission

PCA

   - the Power Cost Adjustment mechanism in the State of Idaho

PLP

   - Potentially liable party

PUD

   - Public Utility District

PUHCA

   - the Public Utility Holding Company Act of 1935

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)

VAR

   - Value-at-Risk, measures the expected risk of portfolio loss under hypothetical adverse price movements, over a given time interval within a given confidence level

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

WECC

   - Western Electricity Coordinating Council

WUTC

   - Washington Utilities and Transportation Commission

 

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PART I

This Annual Report on Form 10-K contains forward-looking statements, which should be read with the cautionary statements and important factors included in this Annual Report on Form 10-K at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those that are identified by the use of words such as, but not limited to, “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking statements are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corporation and many of which could have a significant effect on Avista Corporation’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Available Information

The Web site address of Avista Corporation (Avista Corp. or the Company) is www.avistacorp.com. Avista Corp. makes available free of charge, on or through its Web site, its annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such reports with the Securities and Exchange Commission. Information contained on Avista Corp.’s Web site is not part of this report.

 

Item 1. Business

Company Overview

Avista Corp., 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, 2005, the Company employed approximately 1,435 people in its utility operations and approximately 550 people in its subsidiary businesses. The Company’s corporate headquarters are in Spokane, Washington, center of the Inland Northwest geographic region. 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.

The Company has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. The Company’s total common stockholders’ equity was $771.1 million as of December 31, 2005 of which $237.7 million represented its investment in Avista Capital.

Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations that started in 1889. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas. Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Based on Avista Utilities’ forecast for electric customer growth of 2.5 percent and natural gas customer growth of 4 percent within its service area, Avista Utilities anticipates retail electric and natural gas load growth will average between 3 and 3.5 percent annually for the next four years. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy, which commenced operations in 1997, is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Energy focuses on optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to end-user industrial and commercial customers in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy continues to seek opportunities to expand its business of optimizing generation assets

 

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owned by other entities and has expanded its natural gas end-user business to industrial and commercial customers in Montana. Avista Power’s primary asset is its 49 percent interest in a 270 megawatt (MW) natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of facility information and cost management services for multi-site customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services. Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage a foundation on which to expand beyond utility bill information services to provide similar services relating to telecom expense management.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development, Advanced Manufacturing and Development (AM&D) and certain other operations of Avista Capital. The Company continues to limit its future investment in the Other business segment.

The Company’s current organization and business segments, and the companies included within them, are illustrated below:

LOGO

 

¨ - denotes a business entity; Avista Advantage is also a business segment.

 

 0 - denotes business segment.

See “Item 6. Selected Financial Data” and “Note 29 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment.

In February 2006, the Board of Directors of Avista Corp. made the decision to ask shareholders to approve a change in the Company’s organization, which would result in the formation of a holding company. See further information at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Potential Holding Company Formation.”

 

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Avista Utilities

General

Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as part of its resource management and load-serving obligations.

Avista Utilities provides electric distribution and transmission as well as natural gas distribution services in parts of eastern Washington and northern Idaho with a population of approximately 865,000. It also provides natural gas distribution service in parts of northeast and southwest Oregon with a population of approximately 470,000. At the end of 2005, Avista Utilities supplied retail electric service to a total of 338,000 customers and retail natural gas service to a total of 297,000 customers across its entire service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California. See “Item 2. Properties” for further information with respect to Avista Utilities’ electric distribution and transmission assets, as well as natural gas distribution assets.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic and Load Growth” for information with respect to projected load growth in Avista Utilities’ service territory.

Electric Operations

In addition to providing electric distribution and transmission services, Avista Utilities generates electricity from facilities that it owns. It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of electric resources to meet its retail and wholesale energy requirements under a range of operating conditions. In addition to company-owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources.

Avista Utilities engages in an ongoing process of resource optimization, which involves the pursuit of economic resources to serve load obligations and using existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy to and from utilities and other entities as part of the process of acquiring resources to serve its retail and wholesale load obligations. These transactions range from a term as short as one hour up to long-term contracts that extend beyond one year. Avista Utilities makes continuing projections of (1) future retail and wholesale loads based on, among other things, forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2) resource availability based on, among other things, estimates of streamflows, generating unit availability, historic and forward market information and experience. On the basis of these continuing projections, Avista Utilities makes purchases and sales of energy on an annual, quarterly, monthly, daily and hourly basis to match expected resources to expected energy requirements. Resource optimization also includes transactions such as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting electric wholesale market purchases for the operation of Avista Utilities’ own resources, as well as other wholesale transactions to capture the value of available generation and transmission resources. This optimization process includes entering into financial and physical hedging transactions as a means of managing risks.

Avista Utilities’ generation assets are interconnected through its transmission system and are operated on a coordinated basis to achieve a high level of load-serving capability and reliability. Avista Utilities offers transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Avista Utilities’ 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, which are included in Other Electric Revenues at “Avista Utilities Operating Statistics – Electric Operations,” totaled $11.0 million, $13.9 million and $11.6 million for 2005, 2004 and 2003, respectively. Avista Utilities is currently in the process of enhancing its transmission system. The transmission system project is expected to cost approximately $115 million, of which $67 million has been incurred as of December 31, 2005.

Challenges facing Avista Utilities’ electric operations include, among other things, streamflows to hydroelectric generating facilities, weather conditions, changes in the availability of and volatility in the prices of power and fuel, the timing and approval of the recovery of deferred power costs, generating unit availability, legislative and governmental regulations, potential tax law changes, and customer response to price increases and surcharges. See “Industry Restructuring,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Business Risk and Risk Management” and “Note 1 of Notes to Consolidated Financial Statements” for additional information.

 

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Electric Requirements

The peak electric native load requirement for 2005 occurred on December 8, 2005 at which time native load was 1,660 MW, long-term wholesale obligations were 172 MW and short-term wholesale obligations were 110 MW. At that time the maximum resource capacity available from Avista Utilities was 2,556 MW, which included 1,816 MW of company-owned electric generation, 70 MW of long-term hydroelectric contracts, 316 MW of other long-term wholesale purchases and 354 MW of short-term wholesale purchases. Variations in energy usage by Avista Utilities’ customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both wholesale purchases and sales of energy for annual, quarterly, monthly, daily and hourly periods in order to meet electric requirements and to prudently manage and optimize available resources.

Electric Resources

General Avista Utilities has a diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges. At the end of 2005, Avista Utilities’ owned facilities had a total net capability of approximately 1,800 MW, of which 54 percent was hydroelectric and 46 percent was thermal. See “Item 2. Properties” for detailed information with respect to generating facilities.

Hydroelectric Resources Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is Avista Utilities’ lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on its total power supply costs. Under normal streamflow and operating conditions, Avista Utilities projects that it would be able to meet approximately one-half of its total average electric requirements (both retail and long-term wholesale) with the combination of its own hydroelectric generation and long-term hydroelectric purchase contracts with certain Public Utility Districts (PUDs) in Washington state. Avista Utilities estimates that 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). This is a decrease from previous estimates of normal annual hydroelectric generation of 550 aMW (or 4.8 million MWhs) primarily due to changes in long-term hydroelectric contracts with certain PUDs during 2005. Hydroelectric resources generated 511 aMW, 523 aMW and 492 aMW during 2005, 2004 and 2003, respectively. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. Avista Utilities cannot determine if this trend of lower than normal hydroelectric generation will continue in future years.

The following table shows Avista Utilities’ hydroelectric generation (in thousands of MWhs) during the years ended December 31:

 

     2005         2004         2003

Noxon Rapids

   1,589       1,595       1,543

Cabinet Gorge

   1,004       1,062       975

Post Falls

   87       96       80

Upper Falls

   71       71       67

Monroe Street

   101       107       99

Nine Mile

   107       135       122

Long Lake

   460       511       465

Little Falls

   192       212       189
                    

Total company-owned hydroelectric generation

   3,611       3,789       3,540

Long-term hydroelectric contracts with PUDs

   864       794       775
                    

Total hydroelectric generation

   4,475       4,583       4,315
                    

Thermal Resources Since January 2005, Avista Utilities has owned 100 percent of the combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon. Prior to January 2005, Avista Utilities owned 50 percent of Coyote Springs 2. Avista Utilities owns a 15 percent interest in a twin-unit, coal-fired generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana. Avista Utilities owns a wood-waste-fired generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington and a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT). Avista Utilities also owns a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT). In 2005, Avista Utilities acquired the Rathdrum CT from WP Funding LP, an entity that was included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment. In addition, Avista Utilities owns two small generating facilities (Boulder Park and Kettle Falls CT).

 

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Fuel Supply for Thermal Resources Coyote Springs 2, which is operated by Portland General Electric Corporation, is supplied with natural gas under both term contracts and spot market purchases, and has transportation agreements with unilateral renewal rights in place.

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 December 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 have provided and are expected to meet, future fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used for peaking electric requirements and are also operated when marginal costs are below prevailing wholesale electric prices. These generating units have not been operated significantly in 2005, 2004 and 2003. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

The following table shows Avista Utilities’ thermal generation (in thousands of MWhs) during the years ended December 31:

 

     2005         2004         2003

Coyote Springs 2 (1)

   1,528       407       397

Colstrip

   1,771       1,605       1,593

Kettle Falls GS

   338       366       366

Northeast CT and Rathdrum CT

   6       6       20

Boulder Park and Kettle Falls CT

   23       24       22
                    

Total thermal generation

   3,666       2,408       2,398
                    

 

(1) The Company owned 50 percent of Coyote Springs 2 prior to January 2005. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 from Mirant Oregon, LLC.

Purchases, Exchanges and Sales Avista Utilities purchases and sells power under various long-term contracts. Avista Utilities also enters into a significant number of short-term purchases and sales with terms of up to one year. See “Electric Operations” for additional information with respect to Avista Utilities’ use of wholesale purchases and sales as part of its resource optimization process.

Under the Public Utility Regulatory Policies Act of 1978 (PURPA), Avista Utilities is 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 2022. In February 2006, the PURPA was amended by the Federal Energy Regulatory Commission (FERC) as required by the Energy Policy Act of 2005. These amendments are not expected to have an effect on Avista Utilities’ current 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 2005, 2004 and 2003.

Hydroelectric Relicensing

Avista Corp. is 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 the Company’s hydroelectric plants are regulated by the FERC through project licenses issued for 30 to 50 year periods. Avista Corp.’s 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, Avista Utilities 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, Avista Utilities initiated implementation of protection, mitigation and enhancement measures in March 1999. Measures in the

 

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agreement address issues related to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion. Previously deferred hydroelectric relicensing costs, as well as estimated levels of ongoing costs associated with implementation of the Clark Fork Settlement Agreement, were addressed by both the WUTC and IPUC and received recovery through retail rates.

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 the Cabinet Gorge during periods when excess river flows must be diverted over the spillway and the Company’s mitigation plans and efforts.

The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one FERC license and are referred to, collectively, as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license for the Spokane River Project expires on August 1, 2007; the Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups has been underway since that time. The Company filed its license application with the FERC in July 2005. The Company has requested the FERC to consider a license for Post Falls that is separate from the other four hydroelectric plants. This is due to the fact that Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project. If granted, new licenses would have a term of 30 to 50 years. In the license application, the Company has proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River. Currently, certain environmental measures in the Company’s license application have estimated costs of $3.2 million per year. For certain items, costs cannot be reasonably estimated at this time. The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better known and estimable as the process continues through July 2007. The Company intends to seek recovery of relicensing costs through the rate making process.

Future Resource Needs

Avista Utilities has operational strategies to have available resources sufficient to meet its 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 Avista Utilities’ average annual energy requirements and resources for 2006, 2007, 2008 and 2009:

Forecasted Electric Energy Requirements and Resources

(aMW)

 

     2006         2007         2008         2009

Requirements:

                    

System load

   1,086       1,121       1,155       1,194

Contracts for power sales

   61       61       61       61
                            

Total requirements

   1,147       1,182       1,216       1,255
                            

Resources:

                    

Company-owned and contract hydro generation (1)

   538       538       538       535

Company-owned base load thermal generation

   226       229       243       228

Company-owned other thermal generation

   284       294       279       294

Contracts for power purchases

   293       295       294       295
                            

Total resources

   1,341       1,356       1,354       1,352
                            

Surplus resources

   194       174       138       97

Additional available energy (2)

   142       145       145       145
                            

Total surplus resources

   336       319       283       242

 

(1) The forecasts assume normal hydroelectric generation of 538 aMW for 2006, 2007 and 2008, and 535 aMW for 2009 (due to changes in certain contracts with PUDs).

 

(2) Additional available resources are the Northeast CT and Rathdrum CT, which are generally only used 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. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

 

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In October 2005, Avista Utilities submitted its 2005 Electric Integrated Resource Plan (IRP) to the WUTC and the IPUC. The IRP identifies a strategic resource portfolio that meets future electric load requirements, promotes environmental stewardship and meets Avista Utilities’ obligation to provide reliable electric service to customers at rates, terms and conditions that are fair, just and reasonable and sufficient. Avista Utilities regards the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Based on the assumptions in the IRP, Avista Utilities forecasts that quarterly energy deficits will begin in 2007 and annual energy deficits will begin in 2010. In order to meet these increased demands, Avista Utilities’ preferred resource plan, which is part of the IRP, includes 400 MW of wind power, 250 MW of coal-based generation, 80 MW of biomass, 52 MW of generation plant upgrades and 69 MW of conservation by 2016. In January 2006, Avista Utilities issued a request for proposals (RFP) to consider adding approximately 35 average megawatts of long-term renewable energy supplies. It is expected that deliveries of any energy supplies from this RFP would begin in the fourth quarter of 2007. In early 2006, Avista Utilities has also entered into an agreement with Idaho Power to jointly investigate possible future coal-based generation resources.

Natural Gas Operations

General Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, as well as parts of northeast and southwest Oregon. Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates.

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $8.13, $6.62 and $5.50 in 2005, 2004 and 2003, respectively. This continued upward price trend has resulted in increased rates for customers and lengthened the recovery period for deferred natural gas costs. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers, and Avista Utilities believes 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. In order to maintain that competitive advantage and to offset increasing demand, natural gas must be used more efficiently. Avista Utilities is committed to encouraging efficient use of natural gas and has several incentive programs available to its customers.

Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, increases in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing and approval of recovery for increased natural gas costs.

Avista Utilities offers natural gas sales and transportation service to large natural gas customers. The majority of Avista Utilities’ large industrial customers purchase natural gas through marketers. For these customers, Avista Utilities provides transportation services for a fee to move the customers’ natural gas through Avista Utilities’ distribution system from the natural gas transmission pipeline delivery points to the customers’ premises. Several of Avista Utilities’ largest natural gas customers are provided natural gas transportation service under individual contracts. All individual contracts are subject to regulatory review and approval. The total volume transported on behalf of transportation customers for 2005, 2004 and 2003 was 153.0, 154.4 and 153.4 million therms, which represented approximately 27 percent, 31 percent and 31 percent of Avista Utilities’ total system deliveries, respectively.

As part of the process of balancing natural gas retail load requirements and resources obtained through wholesale purchases, Avista Utilities engages in wholesale sales of natural gas. This activity has increased significantly in 2005 due to the transition of natural gas procurement activities from Avista Energy to Avista Utilities with the termination of the Agency Agreement (see discussion below).

Natural Gas Supply Avista Utilities does not have any natural gas reserves and purchases all of its natural gas in the wholesale market. Avista Utilities is connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. 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. Avista Utilities has capacity delivery rights on six pipelines and owns natural gas storage facilities. Access to a diverse portfolio of natural gas resources allows Avista Utilities to make natural gas procurement decisions that benefit its natural gas customers. Approximately 25 percent of Avista Utilities’ natural gas supplies are obtained from domestic sources, with the remaining 75 percent from Canadian sources.

From 1999 through March 31, 2005, the Company’s energy marketing, trading and resource management subsidiary, Avista Energy, was responsible for natural gas procurement functions, including the daily management and optimization of these natural gas resources for the requirements of customers in the states of Washington, Idaho and Oregon under the Natural Gas Benchmark Mechanism and related Agency Agreement with Avista Utilities. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas

 

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procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Natural Gas Storage Avista Utilities owns 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 8.8 million therms, with a total working natural gas inventory of 221.4 million therms. The role of Jackson Prairie in providing flexible natural gas supplies is important to Avista Utilities’ natural gas operations. It enables Avista Utilities to place natural gas into storage when prices are low or to meet minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are high. Avista Energy controls a portion of the capacity at Jackson Prairie for a ten-year period ending in 2009. During 2002, a multi-year project to further increase the capacity at Jackson Prairie commenced. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

Regulatory Issues

General Avista Corp., as a regulated public utility, is currently 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 Oregon Public Utility Commission (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. The Company is also subject to the jurisdiction of the FERC for its wholesale natural gas rates charged for the release of capacity from Jackson Prairie, licensing of hydroelectric generation resources, and for electric transmission service and wholesale sales.

In each regulatory jurisdiction, 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 and are designed to provide, after recovery of allowable operating expenses, an opportunity 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 base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as determined by the utility commissions. 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 Restructuring” for additional information about deregulation, as well as changes with respect to transmission and wholesale electricity markets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Policy Act of 2005” for information on the Energy Policy Act.

General Rate Cases Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides 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 Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates. 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 Avista Utilities’ 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, Avista Utilities is allowed to adjust its 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” for information on natural gas rate increases to recover increased natural gas costs.

Residential Exchange Program The Residential Exchange Program provides access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s investor-owned utilities. The Bonneville Power Administration (BPA) administers the Residential Exchange Program. Avista Corp. has executed an agreement with the BPA in settlement of each party’s rights and obligations related to the Residential Exchange Program for the period

 

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October 1, 2001 through September 30, 2011. The benefits that Avista Corp. receives under the agreement with the BPA are passed through directly to residential and small-farm customers via a credit to their monthly electric bills. The current BPA rate period began on October 1, 2001 and continues through September 30, 2006. In 2004, Avista Corp. and other investor-owned utilities entered into amended agreements to provide benefits to customers during the rate period from October 1, 2006 through September 30, 2011.

Numerous parties have filed Petitions for Review in the Ninth Circuit Court of Appeals challenging the agreements between Avista Corp. and the BPA, as well as the BPA’s agreements with other investor-owned utilities. These challenges could possibly affect the amount of benefits paid by the BPA to Avista Corp. However, since these benefits are passed through to customers as adjustments to electric rates, which must be approved by the WUTC and the IPUC, the outcome of these Petitions for Review is not expected to have a significant effect on Avista Corp.’s financial condition or results of operations.

Industry Restructuring

Energy Policy Act of 2005 In August 2005, the Energy Policy Act of 2005 (Energy Policy Act) was passed into law. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Policy Act of 2005” for information on the Energy Policy Act.

Federal Level Industry restructuring to open the electric wholesale energy market to competition was initially promoted by federal legislation. The Energy Policy Act of 1992 (1992 Energy Act) expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers.

FERC orders issued in the mid-1990s require public utilities operating under the Federal Power Act to provide access to their transmission systems to third parties and establish an OASIS to provide transmission customers with information about available transmission capacity and other information by electronic means. FERC orders also require each public utility subject to the rule to functionally separate its transmission and wholesale power merchant functions.

In November 2003, the FERC issued a final rule (FERC Order No. 2004) revising the standards of conduct applicable to jurisdictional electric transmission providers and natural gas pipelines (collectively defined by the rule as “transmission providers”) and their “energy affiliates.” FERC Order No. 2004 replaces the previous natural gas and electricity standards of conduct with new unified standards of conduct applicable to both electric and natural gas transmission providers, and dramatically expands the range of affiliated entities covered by the standards. The standards of conduct are designed to ensure that transmission providers do not provide preferential access to service or information to affiliated entities. FERC Order No. 2004 became effective in February 2004 upon each transmission provider completing its filing with the FERC and posting on its OASIS or its Internet Web site its plan for implementing the revised standards of conduct. By June 2004, each transmission provider was required to comply with the new rule’s requirements and post procedures enabling customers and the FERC to determine whether the transmission provider complies with the new standards. Avista Utilities has complied with the revised standards, which have not had any substantive impact on the operation, maintenance and marketing of its transmission system or Avista Utilities’ ability to provide service to its customers.

The North American Electric Reliability Council (NERC) and the WECC have undertaken initiatives to establish a series of security coordinators to oversee the reliable operation of the regional transmission system. Accordingly, Avista Utilities, in cooperation with other utilities in the Pacific Northwest, established the Pacific Northwest Security Coordinator (PNSC) in the late-1990s, which oversees daily and short-term operations of the Northwest sub-regional transmission grid and has limited authority to direct certain actions of control area operators in the case of a pending transmission system emergency.

The utility industry experienced a significant blackout in August 2003, when 50 million people lost power in the northeastern United States and eastern Canadian provinces. As a result of this outage, the 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. Utilities in the western United States, including Avista Utilities, had already been following the provisions of approximately half of these NERC recommendations and Avista Utilities already complies with many of the remaining NERC recommendations.

 

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In February 2005, the NERC Board of Trustees approved reliability standards with the goal of restating existing standards in a manner that is clear, unambiguous, measurable and enforceable. These reliability standards became effective April 1, 2005. Also in February 2005, the FERC issued an order to supplement its April 2004 policy statement, which interprets the term “Good Utility Practice” as that term is used in the Open Access Transmission Tariff, to include compliance with reliability standards developed by the NERC. To comply with applicable standards, Avista Utilities submits annual reliability compliance reports to the NERC.

In February 2006, the FERC issued its final rule on the certification rules for a single Electric Reliability Organization (ERO). This organization, once certified, will have the authority to establish and enforce reliability standards, and will have the ability to delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC intends to provide adequate time to transition from the current system of voluntary reliability standards to mandatory standards under the ERO. The Company continues with its involvement in the NERC compliance process and expects to be involved in the transition to the ERO or regional compliance process.

Regional Transmission Organizations FERC Order No. 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. FERC Order No. 2000 is a follow-up to FERC Orders No. 888 and No. 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties. 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 that is developed by the region and that does not necessarily meet all of the functions and characteristics of an RTO outlined in Order No. 2000.

Since prior to the FERC’s Order No. 2000, Avista Utilities has been participating in discussions with utilities and others in the Pacific Northwest to develop the structure of an independently-governed transmission organization for the region. Interim bylaws governing continuing developmental activities for a non-profit membership corporation, Grid West, were adopted in December 2004. During 2005, certain regional parties explored an alternative structure that did not involve creation of an independently-governed organization. In September 2005, a proposal to converge the two alternatives under the Grid West organization emerged; however, a consensus was not achieved. As a result, Grid West was restructured into a non-member organization in November of 2005, with fewer participating transmission owners, and has been evaluating alternative implementation plans, which work is now in progress. Avista Utilities continues in these discussions regarding a reduced set of initial functions and geographical scope for Grid West, and will participate in discussions regarding other structural approaches that include those regional transmission provider systems currently not participating in the Grid West organization.

The final proposal for any RTO must be filed with the FERC and approved by the boards of directors of the filing companies and regulators in various states. The Company’s decision to move forward with the formation of any RTO serving the Pacific Northwest region, as well as the legal, financial and operating implications of such decisions, will ultimately depend on the terms and conditions related to the formation of the entities and conditions established in the regulatory approval process. The Company cannot predict these implications.

State Level While the 1992 Energy Act precludes the FERC from mandating retail wheeling, state regulators and legislators could open service territories to full competition at the retail level. Legislative action at the state level would be required for full retail wheeling and customer choice to occur in Washington and Idaho. Public policy makers in Washington and Idaho continue to examine other states’ experiences with restructuring, while cognizant that the Pacific Northwest generally benefits from electric rates that are among the lowest in the country. There is currently no movement toward deregulation in Washington or Idaho.

Environmental Issues

General The Company is subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which Avista Utilities has an ownership interest were designed to comply with all applicable environmental laws. Furthermore, the Company conducts periodic reviews of all its facilities and operations to respond to or to anticipate emerging environmental issues. The Company’s Board of Directors has a committee to oversee environmental issues.

Since December 1991, 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, have been 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 have not directly impacted generation levels at any of Avista Utilities’ hydroelectric facilities. Avista

 

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Utilities does, however, purchase power under long-term contracts with 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 Avista Utilities at this time. It is currently not possible to accurately predict the likely economic costs to the Company resulting from future actions. The Company 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” for further information.

Air Quality The most significant impact on the Company related to the Clean Air Act (CAA) and the 1990 Clear Air Act Amendments (CAAA) pertains to Colstrip, which is a “Phase II” coal-fired plant under the CAAA. Avista Utilities does not expect Colstrip to be required to implement any additional sulfur dioxide (SO2) mitigation in the foreseeable future in order to continue operations. Avista Utilities’ 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 2001 (expires in 2006 and the Company has applied for renewal) and the operating permit for the Kettle Falls GS was renewed in 2002 (expires in 2007). The Northeast CT was issued a Title V permit in February 2004 (expires in 2009). Boulder Park does not require a Title V permit based on its limited output and instead has a synthetic minor permit that does not expire. Coyote Springs 2 has a Title V permit that was issued in 2003 (expires in 2008).

In 1999, the Environmental Protection Agency (EPA) initiated enforcement actions against several utilities, asserting that older, coal-fired power plants operated by those utilities have, over the years, been modified in ways that subject them to more stringent requirements under the CAA. The EPA has since issued notices of violation and commenced enforcement activities against other utilities. The future direction of the EPA’s enforcement initiative is presently unclear. Therefore, at this time, Avista Utilities is unable to predict whether such EPA enforcement actions will be made against Colstrip. However, the EPA regional office that regulates plants in Montana has indicated an intention to issue information requests to all utilities in their jurisdiction and issued such a request to Colstrip in 2003. The owners of Colstrip began the process of responding to this information request. However, the EPA has stayed further production of Colstrip documents pending discussion among the Colstrip owners and the EPA. Avista Utilities cannot presently predict what action, if any, the EPA might take in this matter.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies “ for further information.

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 the Cabinet Gorge.

Other Environmental Issues See “Colstrip Generating Project Complaint,” “Environmental Protection Agency Administrative Compliance Order,” “Hamilton Street Bridge,” “Spokane River,” “Harbor Oil Inc. Site,” “Northeast Combustion Turbine Site” and “Other Contingencies” 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,  
     2005     2004     2003  

ELECTRIC OPERATIONS

      

ELECTRIC OPERATING REVENUES (Dollars in Thousands):

      

Residential

   $ 211,934     $ 209,518     $ 204,783  

Commercial

     203,480       201,775       201,339  

Industrial

     91,552       90,288       78,276  

Public street and highway lighting

     4,898       4,847       4,770  
                        

Total retail revenues

     511,864       506,428       489,168  

Wholesale revenues

     151,429       62,399       73,463  

Revenues from sales of fuel

     41,831       63,990       71,456  

Other revenues

     17,988       19,264       16,835  
                        

Total electric operating revenues

   $ 723,112     $ 652,081     $ 650,922  
                        

ELECTRIC ENERGY SALES (Thousands of MWhs):

      

Residential

     3,420       3,343       3,298  

Commercial

     2,994       2,919       2,919  

Industrial

     2,091       2,076       1,785  

Public street and highway lighting

     25       25       25  
                        

Total retail energy sales

     8,530       8,363       8,027  

Wholesale energy sales

     2,508       1,472       2,075  
                        

Total electric energy sales

     11,038       9,835       10,102  
                        

ELECTRIC ENERGY RESOURCES (Thousands of MWhs):

      

Hydro generation (from Company facilities)

     3,611       3,789       3,540  

Thermal generation (from Company facilities)

     3,666       2,408       2,398  

Purchased power - long-term hydroelectric contracts with PUDs

     864       794       775  

Purchased power - wholesale

     3,519       3,422       3,909  

Power exchanges

     10       38       36  
                        

Total power resources

     11,670       10,451       10,658  

Energy losses and Company use

     (632 )     (616 )     (556 )
                        

Total energy resources (net of losses)

     11,038       9,835       10,102  
                        

NUMBER OF ELECTRIC CUSTOMERS (Average for Period):

      

Residential

     294,036       288,422       283,497  

Commercial

     37,282       36,728       36,279  

Industrial

     1,408       1,416       1,414  

Public street and highway lighting

     421       418       422  
                        

Total electric retail customers

     333,147       326,984       321,612  

Wholesale

     46       43       47  
                        

Total electric customers

     333,193       327,027       321,659  
                        

ELECTRIC RESIDENTIAL SERVICE AVERAGES:

      

Annual use per customer (KWh)

     11,630       11,591       11,633  

Revenue per KWh (in cents)

     6.20       6.27       6.21  

Annual revenue per customer

   $ 720.78     $ 726.43     $ 722.35  

ELECTRIC AVERAGE HOURLY LOAD (aMW)

     1,046       1,025       984  
                        

RESOURCE AVAILABILITY at time of system peak (MW):

      

Total requirements (winter):

      

Retail native load

     1,660       1,766       1,509  

Wholesale obligations

     282       454       417  
                        

Total requirements (winter)

     1,942       2,220       1,926  

Total resource availability (winter)

     2,556       2,552       2,557  

Total requirements (summer):

      

Retail native load

     1,498       1,488       1,487  

Wholesale obligations

     575       294       449  
                        

Total requirements (summer)

     2,073       1,782       1,936  

Total resource availability (summer)

     2,519       2,409       2,365  

COOLING DEGREE DAYS: (1)

      

Spokane, WA

      

Actual

     409       571       578  

30-year average

     394       394       394  

% of average

     104 %     145 %     147 %

 

(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,  
     2005     2004     2003  

NATURAL GAS OPERATIONS

      

NATURAL GAS OPERATING REVENUES (Dollars in Thousands):

      

Residential

   $ 229,737     $ 194,470     $ 166,925  

Commercial

     126,648       104,754       90,523  

Industrial

     11,867       9,423       7,475  
                        

Total retail natural gas revenues

     368,252       308,647       264,923  

Wholesale revenues

     58,074       152       280  

Transportation revenues

     7,601       8,134       8,485  

Other revenues

     4,278       3,560       3,601  
                        

Total natural gas operating revenues

   $ 438,205     $ 320,493     $ 277,289  
                        

THERMS DELIVERED (Thousands of Therms):

      

Residential

     199,433       201,696       198,471  

Commercial

     122,981       122,852       122,115  

Industrial

     13,534       13,274       12,737  
                        

Total retail

     335,948       337,822       333,323  

Wholesale

     72,903       305       675  

Transportation

     152,990       154,427       153,352  

Interdepartmental and Company use

     466       3,030       3,124  
                        

Total therms delivered

     562,307       495,584       490,474  
                        

SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):

      

Purchases

     434,239       341,398       334,609  

Storage - injections

     (26,359 )     (60 )     (74 )

Storage - withdrawals

     5,314       52       76  

Natural gas for transportation

     152,990       154,427       153,352  

Interdepartmental transportation

     —         2,551       2,607  

Distribution system losses

     (3,877 )     (2,784 )     (96 )
                        

Total natural gas supply

     562,307       495,584       490,474  
                        

NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):

      

Residential

     265,294       268,571       261,063  

Commercial

     31,652       31,886       31,312  

Industrial

     307       311       310  
                        

Total natural gas retail customers

     297,253       300,768       292,685  

Wholesale

     12       1       1  

Transportation

     93       81       84  
                        

Total natural gas customers

     297,358       300,850       292,770  
                        

NATURAL GAS RESIDENTIAL SERVICE AVERAGES:

      

Annual use per customer (therms)

     752       751       760  

Revenue per therm (in dollars)

   $ 1.15     $ 0.96     $ 0.84  

Annual revenue per customer

   $ 865.97     $ 724.09     $ 639.41  

NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):

      

Net system maximum demand (winter)

     2,698       3,098       2,270  

Net system maximum firm contractual capacity (winter)

     4,340       4,340       4,340  

HEATING DEGREE DAYS: (1)

      

Spokane, WA

      

Actual

     6,538       6,314       6,351  

30-year average

     6,820       6,820       6,820  

% of average

     96 %     93 %     93 %

Medford, OR

      

Actual

     4,185       3,933       4,046  

30-year average

     4,533       4,533       4,533  

% of average

     92 %     87 %     89 %

 

(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 below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

 

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Energy Marketing and Resource Management

The Energy Marketing and Resource Management business segment includes Avista Energy and Avista Power, both subsidiaries of Avista Capital.

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily within the WECC. Avista Energy’s headquarters are in Spokane, Washington, and it also has natural gas marketing offices in Vancouver, British Columbia, Canada and Great Falls, Montana (which opened in early 2006). Avista Energy focuses on optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 200 end-user industrial and commercial customers that represent approximately 400 sites in British Columbia, Canada. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Energy continues to seek opportunities to expand its business of optimizing generation assets owned by other entities and has expanded its natural gas end-user business to industrial and commercial customers in Montana. Avista Energy’s earnings are primarily derived from the following activities:

 

    Taking speculative positions on future price movements within established risk management policies.

 

    Optimization of generation assets owned by other entities.

 

    Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.

 

    Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.

 

    Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.

 

    Marketing natural gas to end-user industrial and commercial customers.

Avista Energy trades electricity and natural gas, along with derivative commodity instruments including futures, options, swaps and other contractual arrangements. Most transactions are conducted on an “over-the-counter” basis. Avista Energy’s trading operations are affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, changing regulation of the electric and natural gas industries, the creditworthiness of counterparties and variations in liquidity in energy markets. See “Item 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Risk and – Risk Management” for further information.

In addition to its trading activities, a fundamental component of Avista Energy’s business strategy is having asset management and optimization agreements with other entities, which helps create synergies within its entire portfolio. Under this strategy, Avista Energy does not have ownership of the physical energy assets, which allows Avista Energy to focus on commodity management while minimizing responsibilities and risks associated with actual ownership. Avista Energy assists the asset owner with decisions regarding the operation of their generation assets to capture available economic value and shares in the benefits derived from optimization. This process includes transactions such as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting market purchases for the operation of the generating asset. Optimization also includes other transactions to capture the value of available generation, transmission and transportation resources. This optimization process is combined with other portions of Avista Energy’s business, including electric and natural gas trading, to maximize the value of Avista Energy’s entire portfolio, within established risk management policies.

The following table provides operating statistics for Avista Energy for the years ended December 31:

 

     2005    2004    2003

Gross Physical Realized Sales Volume:

        

Electricity (thousands of MWhs)

   28,377    32,629    41,579

Natural gas (thousands of dekatherms)

   182,874    219,719    228,397

 

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Avista Energy managed Avista Utilities’ natural gas storage assets, transportation contracts and natural gas purchasing operations from 1999 through March 31, 2005 under an Agency Agreement. Under that agreement, Avista Energy served as the natural gas supply agent for Avista Utilities, including purchasing natural gas for Avista Utilities’ retail customers. Effective April 1, 2005, the Agency Agreement was terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. The termination of the Agency Agreement was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan was approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Avista Power

Avista Power’s primary asset is its 49 percent ownership interest in the Lancaster Project. The Lancaster Project capacity is contracted to Avista Energy through 2026 through a power purchase agreement. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation, and convert to electricity for a fixed fee. Avista Power is not seeking additional investment opportunities.

Avista Advantage

Avista Advantage is a provider of facility information and cost management services for multi-site customers throughout North America. Through invoice processing, auditing, payment services and comprehensive reporting, Avista Advantage’s solutions are designed to provide companies with critical and easy-to-access information that enables them to proactively manage and reduce their utility, telecom and waste management expenses.

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

Avista Advantage has secured five patents on its two critical business systems: the Facility IQ system, which provides operational information drawn from facility bills, and the AviTrack database, which processes and reports on information gathered from service providers to ensure customers are receiving the most effective services at the proper price. Avista Advantage is not aware of any claimed or threatened infringement on any of its patents issued to date and will continue to expand and protect its existing patents, as well as file additional patent applications for new products, services and process enhancements.

As of December 31, 2005, Avista Advantage serviced 348 customers, having 174,910 billed sites throughout North America. This is an increase from 323 customers and 141,442 billed sites as of December 31, 2004. As of December 31, 2003, Avista Advantage serviced 292 customers and 109,583 billed sites. During 2005, Avista Advantage processed $9.3 billion of bills, an increase from $7.6 billion in 2004 and $6.4 billion in 2003.

Other

The Other business segment includes Avista Ventures, Pentzer, Avista Development and certain other operations of Avista Capital. Included in this business segment is AM&D doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also performs contract assembly for radiant floor heating systems. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments. Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. However, the Company may, from time to time, invest incremental funds in these businesses to protect its existing investments.

 

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Item 1A. Risk Factors

Risk Factors

The following are factors that could have a significant impact on the operations, results of operations, financial condition or cash flows of Avista Corp. and could cause actual results or outcomes to differ materially from those discussed in Avista Corp.’s reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. In addition to these risk factors, please also see the “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 Avista Corp.’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Avista Corp.’s results of operations, financial condition and cash flows can be significantly affected by weather.

Weather has a significant effect on Avista Utilities’ operations, both with respect to customer demand and resulting operating revenues (primarily heating requirements in the winter and cooling requirements in the summer) and electric resource costs (primarily the availability of hydroelectric generation and the tendency for high demand to increase the cost of fuel for electric generation and wholesale electric market prices). Avista Utilities normally experiences its highest retail (electric and natural gas) energy sales during the heating season in the first and fourth quarters of the year. Avista Utilities also experiences high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and colder weather in the cooling season will have a negative effect on Avista Utilities’ operating revenues. In addition, a reduction in precipitation (particularly snowpack) will decrease hydroelectric generation capability and increase resource costs and cash outflows to purchase electric resources. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. Avista Corp. has no way to predict whether this trend of lower than normal hydroelectric generation will continue in the future. Regional precipitation and snowpack conditions can also have a significant effect on the wholesale price of electricity.

Avista Corp. is subject to commodity price risk.

Both Avista Utilities and Avista Energy are subject to electric and natural gas commodity price risk. Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. Changes in wholesale energy prices can affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations, as well as the market value of derivative assets and liabilities and unrealized gains and losses. In the case of electricity, prices can be affected by the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, availability of streamflows for hydroelectric generation on a regional basis, the price and availability of fuel for thermal generating plants, and disruptions of or constraints on transmission facilities, among other things. Natural gas prices are affected by a number of factors, including but not limited to, the adequacy of North American production, the level of imports, the level of inventories, the demand for natural gas as fuel for electric generation, global energy markets, and the availability of pipeline capacity to transport natural gas from region to region. In addition, oil prices can influence natural gas and electricity prices, because of the fuel-switching capabilities of certain energy users. Demand changes caused by variations in the weather and other factors can also affect market prices for electricity and natural gas. Any combination of these factors that results in a shortage of energy generally causes the market price to move upward.

Increasing energy commodity prices have a significant effect on liquidity for both Avista Utilities and Avista Energy. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of its power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect Avista Corp.’s operating cash flow and liquidity until such costs, with interest, are recovered from customers.

Avista Utilities’ deferred power and natural gas costs are subject to regulatory review; costs in excess of levels recovered in base rates reduce cash flows and it may take several years to recover current balances of deferred costs.

Avista Utilities defers the recognition in the income statement of certain power and natural gas costs that are in excess of the level currently recovered from its retail customers as authorized by the WUTC, the IPUC and the OPUC. These excess power and natural gas costs are recorded as deferred charges on the Consolidated Balance Sheet with the opportunity for recovery through future retail rates. These deferred power and natural gas costs are

 

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subject to review by the WUTC, IPUC and OPUC, as applicable, for prudence and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Despite the opportunity to eventually recover a substantial portion of power and natural gas costs in excess of the levels currently recovered from retail customers, Avista Utilities’ operating cash flows are negatively affected in the periods in which these costs are paid. Factors that could cause costs to exceed the levels currently recovered from Avista Utilities’ customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase energy in the wholesale markets. Factors beyond Avista Utilities’ control that could result in an increased need to purchase energy in the wholesale markets include, but are not limited to, increases in demand (either due to weather or customer growth), low availability of hydroelectric resources, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts.

Avista Utilities currently expects that the recovery of current balances of deferred power and natural gas costs may take several years.

Avista Utilities is subject to the risk that regulators will not grant sufficient recovery of its costs and not provide a reasonable rate of return for Avista Corp.’s shareholders.

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. General rate increases granted since 2002 have been important steps in Avista Corp.’s financial recovery primarily through increased operating revenues and operating cash flows. Avista Utilities anticipates that it will continue to periodically file for general rate increases with regulatory agencies to recover its costs and provide a reasonable return to Avista Corp.’s shareholders. If regulators were to grant substantially lower rate increases than Avista Utilities requests in the future, it could have a negative effect on operating revenues and cash flows, which could result in future downgrades to its credit ratings or prevent Avista Corp. from improving its credit ratings.

Avista Corp. is subject to credit risk.

Avista Utilities and Avista Energy are subject to credit risk. Credit risk relates to the losses that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. Avista Utilities and Avista Energy often extend credit to counterparties and customers and are exposed to the risk that they may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits have been established. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, circumstances caused by market price changes and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, Avista Utilities and/or Avista Energy may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including but not limited to, electric utilities, natural gas distribution companies, and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location, as Avista Energy operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may negatively affect Avista Energy’s overall exposure to credit risk, because the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Credit risk also involves the exposure that counterparties perceive related to the ability of Avista Utilities and Avista Energy 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, and, in the case of Avista Energy, parent company (Avista Capital) performance guarantees. In periods of price volatility, the level of exposure can change significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash).

 

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Avista Corp.’s commodity trading, marketing and resource management activities may increase the volatility in its results of operations; Avista Corp. cannot, and does not attempt to, fully hedge its assets or positions against changes in commodity prices, and its hedging procedures may not fully match the corresponding purchase or sale.

Avista Energy engages in commodity trading and marketing, as well as resource management activities. These activities include entering into financial and physical derivative transactions, and taking speculative positions on future price movements, within established risk management policies. Avista Energy is required by applicable accounting principles to record all derivatives on the Consolidated Balance Sheet at estimated fair value. Changes in the estimated fair value of derivatives are immediately recognized in earnings unless they are designated as cash flow hedges of forecasted transactions. Changes in the estimated fair value of derivatives accounted for as cash flow hedges of forecasted transactions are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. Most of Avista Energy’s derivative contracts are marked-to-market and changes in their value caused by fluctuations in the underlying commodity prices, flow through Avista Corp.’s Consolidated Statements of Income. As a result, fluctuations in commodity prices and the corresponding effect on the market value of derivative instruments could have a significant effect on Avista Corp.’s operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

To reduce financial and economic exposure related to commodity price fluctuations, Avista Utilities and Avista Energy routinely enter into contracts to hedge a portion of their purchase and sale commitments for electricity and natural gas, as well as inventories of natural gas. As part of this strategy, Avista Utilities and Avista Energy routinely utilize derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. However, Avista Utilities and Avista Energy do not always cover the entire exposure of assets or positions to market price volatility and the coverage will vary over time. To the extent Avista Utilities or Avista Energy have unhedged positions, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material adverse effect on Avista Corp.’s operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

Avista Corp.’s risk management procedures may not prevent losses.

Avista Utilities and Avista Energy have risk management policies and control procedures designed to measure and mitigate energy market risks. However, these policies and procedures cannot prevent material losses in all possible situations or from all potential causes. Included in Avista Energy’s risk management policies are value-at-risk (VAR) limits and systematic measurement procedures derived from historic price behavior. VAR measures the expected portfolio loss under hypothetical adverse price movements over a given time interval within a given confidence level. Losses could exceed the VAR predictive amounts if prices deviate significantly from their historic patterns and in cases when actual events fall into the extreme end of the VAR confidence interval. In addition, continuing trends of small losses that may be individually less than VAR limits may cumulatively become significant. As a result of these and other factors, there can be no assurance that Avista Utilities’ and Avista Energy’s risk management procedures will prevent losses that could negatively affect its operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

Avista Corp. relies on access to credit from banks.

Avista Corp. needs to maintain access to adequate levels of credit with its banks. Avista Corp. has in place a committed line of credit in the amount of $350 million, which is scheduled to expire in December 2009. Avista Corp. cannot predict whether it will have access to credit beyond the expiration date. The line of credit contains customary covenants and default provisions. In the event of default, it would be difficult for Avista Corp. to obtain financing on any reasonable terms to pay creditors or fund operations, and Avista Corp. would likely be prohibited from paying dividends on its common stock.

Avista Energy also needs access to adequate levels of credit from banks and currently has a $145 million committed line of credit, which is scheduled to expire in July 2007. Avista Corp. cannot predict whether Avista Energy will have access to credit after the expiration of its current line of credit. Avista Energy’s credit agreement contains customary covenants and default provisions, including but not limited to, covenants to maintain “minimum net working capital” and “minimum net worth”, as well as a covenant limiting the amount of indebtedness that the co-borrowers (Avista Energy and Avista Energy Canada) may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including but not limited to, VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. These covenants, certain counterparty agreements and market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately Avista Corp. If Avista Energy were

 

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unable to continue to obtain credit from banks or other lenders, Avista Energy would likely not have sufficient liquidity to meet its obligations.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of its significant subsidiaries (including Avista Energy) 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, and could induce vendors and other counterparties to demand collateral.

A downgrade in Avista Corp.’s credit rating could limit its ability to obtain financing or adversely affect the terms of financing.

Avista Corp.’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. The downgrades were due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs incurred and the resulting increase in debt levels and debt service costs. Avista Corp. continues to work towards restoring an overall corporate investment grade credit rating. However, any future downgrades could limit Avista Corp.’s ability to issue debt securities or obtain other financing at reasonable interest rates. In addition, future downgrades could require Avista Corp. to provide letters of credit and/or collateral to lenders and counterparties.

An increase in interest rates could negatively affect Avista Corp.’s future results of operations and cash flows.

During the years 2006 through 2008, utility capital expenditures are currently expected to be in the range of $160 million to $175 million per year. In addition to continuing needs for Avista Utilities’ distribution system, significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities. Avista Corp. also has approximately $567 million of long-term debt maturities and mandatory preferred stock redemptions between 2006 and 2008, with the majority occurring in 2007 and 2008. Avista Corp.’s forecasts indicate that it will need to issue new securities to fund a significant portion of these requirements. In 2004, Avista Corp. entered into forward-starting interest rate swap agreements to effectively lock in market fixed interest rates, which are relatively low compared to historical interest rates, for $200 million of forecasted debt issuances. However, with respect to the remaining debt that Avista Corp. expects to issue, rising interest rates could increase Avista Corp.’s future debt service costs and decrease operating cash flows.

Avista Corp. is subject to various operational and event risks, which are common to the utility industry.

Avista Utilities, Avista Corp.’s regulated utility operation, is subject to operational and event risks including, among others, increases or decreases in load demand, blackouts or disruptions to transmission or transportation systems, fuel quality, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations.

Avista Utilities also has exposure to natural disasters and terrorism threats that can cause physical damage to its property, requiring repairs to restore utility service.

Avista Corp. may not be able to relicense its hydroelectric facilities located on the Spokane River at a cost-effective level with reasonable terms and conditions.

Avista Corp. owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one Federal Energy Regulatory Commission (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. The license for the Spokane River Project expires on August 1, 2007; Avista Corp. filed its license application with the FERC in July 2005. Avista Corp. has requested the FERC to consider a license for Post Falls that is separate from the other four hydroelectric plants. This is due to the fact that Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project. The FERC may impose certain environmental, operating and other conditions in connection with the new licenses that could result in significant capital expenditures, higher operating costs and/or reduced hydroelectric generation capability. Avista Corp. plans to request regulatory approval to recover these costs. However, Avista Corp. cannot estimate the magnitude of these costs or provide certainty that they will be recovered through the rate making process.

In 2001, Avista Corp. received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project and the Noxon Rapids Hydroelectric Generating Project, which represent approximately 80 percent of Avista Corp.’s current hydroelectric generating capability. The Spokane River facilities represent approximately 20 percent of Avista Corp.’s current hydroelectric generating capability.

 

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Avista Corp. is currently the subject of several regulatory proceedings and named in multiple lawsuits with respect to its participation in Western energy markets as disclosed in “Note 26 of the Notes to Consolidated Financial Statements.”

Avista Energy and Avista Utilities are involved in a number of legal and regulatory proceedings and complaints with respect to power 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 western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest, market conduct investigations by the FERC, and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. In addition, a class action shareholder complaint has been filed against Avista Corp. and certain current and former executive officers based on alleged misconduct in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from Avista Corp. and its subsidiaries, which could result in a negative effect on Avista Corp.’s results of operations and cash flows. See “Note 26 of the Notes to Consolidated Financial Statements” for further information.

Avista Corp. has contingent liabilities as disclosed in “Note 26 of the Notes to Consolidated Financial Statements.” Avista Corp. cannot predict the outcome of these matters.

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

Lake Coeur d’Alene Matter

Avista Corp. is liable for compensation (not yet determined as to amount) for the use of portions of the bed and banks of Lake Coeur d’Alene and the St. Joe River, which were determined to be property of the Coeur d’Alene Tribe of Idaho. Avista Corp. is engaged with the Tribe in discussions with respect to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake that are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation.

Montana Hydroelectric Litigation

A lawsuit was filed in Montana against all private owners of hydroelectric dams in Montana, including Avista Corp., alleging that the hydroelectric facilities are located on state-owned riverbeds and the owners have never paid compensation to the state’s public school trust fund. The lawsuit was originally filed by private parties and was subsequently joined by other public parties, including the Attorney General of the State of Montana. Various motions for summary judgment and counter claims are pending in federal and state courts.

Environmental Matters

Avista Corp. is subject to environmental regulation by federal, state and local authorities with respect to its past, present and future operations. Environmental issues include, but are not limited to, contamination of certain parcels of land that Avista Corp. currently owns, has formerly owned or has used as a customer, contamination of certain parcels of land and waters adjacent to Avista Corp.’s property, contamination of certain portions of the Spokane River as well as the levels of dissolved gas in waters downstream of Avista Corp.’s hydroelectric facilities and the resulting impact on free ranging fish.

Avista Corp. is subject to the risk from the potential effects of any legislation or administrative rulemaking.

Avista Corp. has been and is expected to continue to be impacted by legislation at the national and state level, as well as by administrative rules promulgated by government agencies, such as the FERC, NERC and the EPA. Future legislation or administrative rules could have a material adverse effect on Avista Corp.’s operations, results of operations, financial condition and cash flows.

 

Item 1B. Unresolved Staff Comments

As of the filing date of this Annual Report on Form 10-K, Avista Corp. does not have any unresolved comments from the staff of the Securities and Exchange Commission.

 

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Item 2. Properties

Avista Utilities

Avista Utilities’ 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    88.0

Little Falls (Spokane)

   4    32.0    36.0

Nine Mile (Spokane)

   4    26.4    24.5

Upper Falls (Spokane)

   1    10.0    10.2

Monroe Street (Spokane)

   1    14.8    15.0

Idaho:

        

Cabinet Gorge (Clark Fork)

   4    265.0    261.0

Post Falls (Spokane)

   6    14.8    18.0

Montana:

        

Noxon Rapids (Clark Fork)

   5    466.2    527.0
            

Total Hydroelectric

      899.2    979.7

Thermal Generating Stations

        

Washington:

        

Kettle Falls GS

   1    50.7    50.0

Kettle Falls CT

   1    6.9    6.9

Northeast CT

   2    61.8    66.8

Boulder Park

   6    24.6    24.6

Idaho:

        

Rathdrum CT

   2    166.5    176.0

Montana:

        

Colstrip Units 3 and 4 (3)

   2    233.4    222.0

Oregon:

        

Coyote Springs 2

   1    287.0    274.2
            

Total Thermal

      830.9    820.5
            

Total Generation Properties

      1,730.1    1,800.2
            

 

(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 without exceeding approved limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2005.

 

(3) Jointly owned; data refers to Avista Utilities’ 15 percent interest.

Electric Distribution and Transmission Plant

Avista Utilities operates approximately 17,000 miles of primary and secondary electric distribution lines. Avista Utilities has an electric transmission system of approximately 625 miles of 230 kV line and 1,539 miles of 115 kV line. Avista Utilities also owns an 11 percent interest (representing 465 MW capacity) in 495 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. The transmission and distribution system also includes numerous substations with transformers, switches, monitoring and metering devices, and other equipment related to its operation.

The 230 kV lines are used to transmit power from Noxon Rapids and Cabinet Gorge to major load centers in Avista Utilities’ 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, PacifiCorp, NorthWestern Energy and Idaho Power Company. These interconnections serve as points of delivery for power from generating facilities outside of the Company’s distribution territory, including the Colstrip generating station, Coyote Springs 2, and to integrate Mid-Columbia hydroelectric generating facilities, as well as for the interchange of power with entities within and outside the Pacific Northwest. Avista Utilities is currently in the process of enhancing its 230 kV transmission system, which Avista Utilities expects to be completed by the end of 2007.

 

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The 115 kV lines provide for transmission of energy and the integration of the Spokane River hydroelectric and Kettle Falls wood-waste generating stations with service-area load centers. These lines interconnect with the BPA, Grant County PUD, Puget Sound Energy, the South Columbia Basin Irrigation District, Chelan County PUD, PacifiCorp and NorthWestern Energy. Both the 115 kV and 230kV interconnections with the BPA are used to exchange energy with the BPA to facilitate service to each other’s customers that are connected through the other’s transmission system. Avista Utilities and the BPA have contracts in place that allow Avista Utilities to serve its native load customers connected through the BPA transmission system and allow the BPA to serve its wholesale utility customers connected through Avista Utilities’ transmission system.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 2,700 miles in Washington, 1,600 miles in Idaho and 1,850 miles in Oregon. The natural gas distribution system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment related to its operation.

Avista Utilities owns a one-third interest in Jackson Prairie, which has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 221.4 million therms. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

 

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.

PART II

 

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

Avista Corp.’s common stock is currently listed on the New York Stock Exchange (NYSE) and the Pacific Stock Exchange (PSE) with the NYSE maintaining the principal listing. As of February 28, 2006, there were approximately 14,269 registered shareholders of the Company’s no par value common stock.

On February 10, 2006, the Board of Directors of Avista Corp. decided to delist the Company’s common stock from the PSE. The Board of Directors made this decision primarily due to the limited volume of Avista Corp. Common Stock transactions on the PSE and the costs of listing on the PSE.

The Board of Directors considers the level of dividends on the Company’s common stock on a regular basis, taking into account numerous factors including, without limitation, the Company’s results of operations, cash flows and financial condition, as well as the success of the Company’s strategies and general economic and competitive conditions. The Company’s net income available for dividends is derived primarily from the operations of Avista Utilities and Avista Energy.

Covenants under the Company’s 9.75 percent Senior Notes that mature in 2008 limit the Company’s ability to increase its common stock cash dividend to no more than 5 percent over the previous quarter.

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheets. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. During 2005, Avista Energy paid $15.1 million in dividends to Avista Capital.

For additional information, refer to “Notes 1, 23, 24 and 25 of Notes to Consolidated Financial Statements.” For high and low stock price, as well as dividend information, refer to “Note 30 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

 

     Years Ended December 31,  
(in thousands, except per share data and ratios)    2005     2004     2003     2002     2001  

Operating Revenues:

          

Avista Utilities

   $ 1,161,317     $ 972,574     $ 928,211     $ 893,964     $ 1,230,847  

Energy Marketing and Resource Management

     167,439       275,646       307,141       222,634       403,743  

Avista Advantage

     31,748       23,444       19,839       16,911       13,151  

Other

     18,532       17,127       13,581       14,645       16,385  

Intersegment Eliminations

     (19,429 )     (137,211 )     (145,387 )     (85,238 )     (152,375 )
                                        

Total

   $ 1,359,607     $ 1,151,580     $ 1,123,385     $ 1,062,916     $ 1,511,751  
                                        

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

          

Avista Utilities

   $ 165,378     $ 134,073     $ 146,777     $ 149,180     $ 114,927  

Energy Marketing and Resource Management

     (18,267 )     11,681       30,078       29,211       94,669  

Avista Advantage

     6,973       1,742       (1,331 )     (6,363 )     (15,098 )

Other

     (2,060 )     (7,026 )     (3,821 )     (14,886 )     (10,432 )
                                        

Total

   $ 152,024     $ 140,470     $ 171,703     $ 157,142     $ 184,066  
                                        

Income (Loss) from Continuing Operations:

          

Avista Utilities

   $ 52,479     $ 32,467     $ 36,241     $ 36,382     $ 24,164  

Energy Marketing and Resource Management

     (8,621 )     9,733       20,672       22,425       63,246  

Avista Advantage

     3,922       577       (1,334 )     (4,253 )     (10,748 )

Other

     (2,612 )     (7,163 )     (4,936 )     (12,380 )     (8,421 )
                                        

Total

     45,168       35,614       50,643       42,174       68,241  

Loss from discontinued operations

     —         —         (4,949 )     (6,719 )     (56,085 )
                                        

Net income before cumulative effect of accounting change

     45,168       35,614       45,694       35,455       12,156  

Cumulative effect of accounting change

     —         (460 )     (1,190 )     (4,148 )     —    
                                        

Net income

     45,168       35,154       44,504       31,307       12,156  

Preferred stock dividend requirements (1)

     —         —         (1,125 )     (2,402 )     (2,432 )
                                        

Income available for common stock

   $ 45,168     $ 35,154     $ 43,379     $ 28,905     $ 9,724  
                                        

Average common shares outstanding, basic

     48,523       48,400       48,232       47,823       47,417  

Average common shares outstanding, diluted

     48,979       48,886       48,630       47,874       47,435  

Common shares outstanding at year-end

     48,593       48,472       48,344       48,044       47,633  

Earnings per Common Share, Diluted (3):

          

Earnings from continuing operations

   $ 0.92     $ 0.73     $ 1.02     $ 0.83     $ 1.38  

Loss from discontinued operations

     —         —         (0.10 )     (0.14 )     (1.18 )
                                        

Earnings before cumulative effect of accounting change

     0.92       0.73       0.92       0.69       0.20  

Cumulative effect of accounting change

     —         (0.01 )     (0.03 )     (0.09 )     —    
                                        

Total earnings per common share, diluted

   $ 0.92     $ 0.72     $ 0.89     $ 0.60     $ 0.20  
                                        

Total earnings per common share, basic

   $ 0.93     $ 0.73     $ 0.90     $ 0.60     $ 0.21  

Dividends paid per common share

     0.545       0.515       0.49       0.48       0.48  

Book value per common share at year-end

   $ 15.87     $ 15.54     $ 15.54     $ 14.84     $ 15.12  

Total Assets at Year-End:

          

Avista Utilities

   $ 2,838,154     $ 2,608,155     $ 2,532,936     $ 2,369,418     $ 2,569,798  

Energy Marketing and Resource Management

     2,012,354       1,002,843       1,013,213       1,349,626       1,506,185  

Avista Advantage

     46,094       47,318       45,621       31,733       20,288  

Other

     51,892       53,305       48,305       42,866       86,514  

Discontinued Operations

     —         —         —         5,900       27,919  
                                        

Total

   $ 4,948,494     $ 3,711,621     $ 3,640,075     $ 3,799,543     $ 4,210,704  
                                        

Long-Term Debt (not including current portion)

   $ 989,990     $ 901,556     $ 925,012     $ 902,635     $ 1,175,715  

Long-Term Debt to Affiliated Trusts (2)

     113,403       113,403       113,403       —         —    

Company-Obligated Mandatorily Redeemable Preferred Trust Securities (2)

     —         —         —         100,000       100,000  

Preferred Stock Subject to Mandatory Redemption (1)

     26,250       28,000       29,750       33,250       35,000  

Common Equity

   $ 771,128     $ 753,205     $ 751,252     $ 712,791     $ 720,063  

Ratio of Earnings to Fixed Charges

     1.75       1.60       1.88       1.69       1.98  

Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements

     1.75       1.60       1.85       1.63       1.91  

 

(1) Preferred Stock Subject to Mandatory Redemption was reclassified from equity to liabilities in 2003 with the adoption of SFAS No. 150. Accordingly, preferred stock dividend requirements were reclassified to interest expense effective July 1, 2003. Balance as of December 31, 2005, 2004 and 2003 does not include current portion.

 

(2) Company-Obligated Mandatorily Redeemable Preferred Trust Securities were reclassified to Long-Term Debt to Affiliated Trusts in 2003 with the adoption of FASB Interpretation No. 46.

 

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

Forward-Looking Statements

Avista Corporation (Avista Corp. or the Company) from time to time makes forward-looking statements such as statements regarding future financial performance, capital expenditures, dividends, capital structure and other financial items, and assumptions underlying them (many of which are based, in turn, upon further assumptions), as well as strategic goals and objectives and plans for future operations. Such statements are made both in Avista Corp.’s 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 other than statements of historical fact, including, without limitation, those that are identified by the use of words such as, but not limited to, “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

All 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 which are beyond the control of Avista Corp. and many of which could have a significant effect on Avista Corp.’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Such risks, uncertainties and other factors include, among others:

 

    weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand;

 

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

 

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

 

    the effect of state and federal regulatory decisions affecting the ability of the Company to recover its costs and/or earn a reasonable return, including, but not limited to, the disallowance of previously deferred costs;

 

    the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2001 and 2002, and including possible retroactive price caps and resulting refunds;

 

    changes in the utility regulatory environment in the individual states and provinces in which the Company operates as well as the United States and Canada in general, which can affect allowed rates of return, financings, or industry and rate structures;

 

    the outcome of legal proceedings and other contingencies concerning the Company or affecting directly or indirectly its operations;

 

    the potential effects of any legislation or administrative rulemaking passed into law, including the Energy Policy Act of 2005 which was passed into law in August 2005;

 

    the effect from the potential formation of a Regional Transmission Organization;

 

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

 

    changes in global energy markets that can affect, among other things, the price of natural gas purchased for retail customers and purchased as fuel for electric generation;

 

    the ability to relicense the Spokane River Project at a cost-effective level with reasonable terms and conditions;

 

    unplanned outages at any Company-owned generating facilities;

 

    unanticipated delays or changes in construction costs with respect to present or prospective facilities;

 

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

 

    blackouts or large disruptions of transmission systems, which can have an impact on the Company’s ability to deliver energy to its customers;

 

    the potential for future terrorist attacks, particularly with respect to utility plant 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 hydroelectric resources;

 

    changes in future economic conditions in the Company’s service territory and the United States in general, including inflation or deflation and monetary policy;

 

    changes in industrial, commercial and residential growth and demographic patterns in the Company’s service territory;

 

    the loss of significant customers and/or suppliers;

 

    failure to deliver on the part of any parties from which the Company purchases and/or sells capacity or energy;

 

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    changes in the creditworthiness of customers and energy trading counterparties;

 

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

 

    the effect of any potential change in the Company’s credit ratings;

 

    changes in actuarial assumptions, the interest rate environment and the actual return on plan assets with respect to the Company’s pension plan, which can affect future funding obligations, costs and pension plan liabilities;

 

    increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits;

 

    increasing costs of insurance, changes in coverage terms and the 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 the ability to recruit and retain employees;

 

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

 

    changes in tax rates and/or policies; and

 

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

The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. However, there can be no assurance that the Company’s 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. The Company undertakes 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 management to predict all of such factors, nor can it assess the effect of each such factor on the Company’s 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 Corp. and its subsidiaries. This discussion focuses on significant factors concerning the Company’s financial condition and results of operations and should be read along with the consolidated financial statements.

Potential Holding Company Formation

In February 2006, the Board of Directors of Avista Corp. made the decision to ask shareholders to approve a change in the Company’s organization, which would result in the formation of a holding company. The proposed holding company would become the parent to the regulated utility Avista Corp. (Avista Utilities) and Avista Capital, which is the parent to the Company’s non-utility subsidiaries. The holding company organizational structure is common in the utility industry. The recent repeal of the Public Utility Holding Company Act of 1935 removed certain restrictions on the formation of a public utility holding company for corporations like Avista Corp. that operate in more than one state.

The proposal for the formation of a holding company will be described for shareholders in Avista Corp.’s Proxy Statement-Prospectus to be distributed to shareholders in connection with the annual meeting of shareholders to be held on May 11, 2006. Avista Corp. has filed for regulatory approval from the Federal Energy Regulatory Commission (FERC) and the utility regulators in Washington, Idaho, Oregon and Montana, conditioned on approval by shareholders. If shareholders approve the proposal, and if state and federal regulatory approvals are received, the holding company organization could be implemented by the end of 2006.

 

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The following chart presents the expected organization of the Company upon completion of all of the transactions associated with the formation of the holding company:

LOGO

 

¨ - denotes a business entity; Avista Utilities Corporation and Avista Advantage are also business segments.

 

 0 - denotes business segment.

Avista Corp. Business Segments

Avista Corp. has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. The Company’s total common stockholders’ equity was $771.1 million as of December 31, 2005 of which $237.7 million represented its investment in Avista Capital.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Power’s primary asset is its 49 percent interest in a 270 megawatt (MW) natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of facility information and cost management services for multi-site customers throughout North America. Through invoice processing, auditing, payment services and comprehensive reporting, Avista Advantage’s solutions are designed to provide companies with critical and easy-to-access information that enables them to proactively manage and reduce their utility, telecom and waste management expenses.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, telecom and

 

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medical industries. AM&D also performs contract assembly for radiant floor heating systems. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments.

The following table presents results by business segment for the years ended December 31 (dollars in thousands):

 

     2005     2004     2003  

Avista Utilities

   $ 52,479     $ 32,467     $ 36,241  

Energy Marketing and Resource Management

     (8,621 )     9,733       20,672  

Avista Advantage

     3,922       577       (1,334 )

Other

     (2,612 )     (7,163 )     (4,936 )
                        

Income from continuing operations

     45,168       35,614       50,643  

Loss from discontinued operations

     —         —         (4,949 )
                        

Net income before cumulative effect of accounting change

     45,168       35,614       45,694  

Cumulative effect of accounting change

     —         (460 )     (1,190 )
                        

Net income

     45,168       35,154       44,504  

Preferred stock dividend requirements

     —         —         (1,125 )
                        

Income available for common stock

   $ 45,168     $ 35,154     $ 43,379  
                        

Executive Level Summary

Net income was $45.2 million for 2005 compared to $35.2 million for 2004. This increase was due to the improved performance of Avista Utilities, as well as Avista Advantage and the Other business segment. This was partially offset by a net loss for Avista Energy (Energy Marketing and Resource Management segment).

Avista Corp.’s operating results and cash flows are derived primarily from Avista Utilities and Avista Energy. Avista Corp. intends to continue to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

Avista Utilities is the Company’s most significant business segment. Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Based on Avista Utilities’ forecast for electric customer growth of 2.5 percent and natural gas customer growth of 4 percent within its service area, Avista Utilities anticipates retail electric and natural gas load growth will average between 3 and 3.5 percent annually for the next four years. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California.

Avista Utilities operating and financial performance is substantially dependent upon, among other things: 1) weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand, 2) the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, 3) 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 4) favorable regulatory decisions, allowing Avista Utilities to recover its costs, including particularly its purchased power and fuel costs, on a timely basis, and to earn a fair return on its investment.

Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year.

Avista Utilities has increased capital expenditures in order to meet load growth needs and to continue to provide reliable service to its customers. Utility capital expenditures totaled $213.7 million in 2005, the most significant of which were the acquisition of the remaining interest in Coyote Springs 2, transmission system enhancements, and the repurchase of the Company’s corporate headquarters and central operating facility in Spokane. For 2006, the Company has established a utility capital budget of approximately $160 million. Significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities.

 

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Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. Avista Utilities has received base rate increases in each of its jurisdictions since October 2003. Most recently, in December 2005, Avista Utilities received approval from the Washington Utilities and Transportation Commission (WUTC) to increase its base electric and natural gas rates effective January 1, 2006. Avista Utilities will continue to file for rate adjustments to provide for recovery of its operating costs and capital investments and to more closely align earned returns with those allowed by regulatory agencies.

Avista Utilities’ net income was $52.5 million for 2005, an increase from $32.5 million for 2004 primarily due to the general rate increases, as well as the $4.1 million pre-tax gain on the sale of the South Lake Tahoe natural gas properties. This was partially offset by increases in other operating expenses particularly with respect to depreciation and amortization from utility plant additions as well as compensation and other employee related expenses. Results for 2004 were reduced by write-offs of $14.4 million ($9.4 million, net of tax) related to the Idaho Public Utility Commission (IPUC) general rate case order. Avista Utilities expects net income for 2006 to be similar to 2005.

Avista Energy’s business activities include trading electricity and natural gas, as well as 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. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to end-user industrial and commercial customers in British Columbia, Canada.

The earnings and cash flows of Avista Energy are by nature subject to significant volatility because they are derived primarily from the day-to-day trading of electricity and natural gas and optimization of assets owned by other entities, as opposed to long-term revenue streams, and because Avista Energy’s activities are for the most part subject to mark-to-market accounting. In addition, with respect to the management of natural gas storage and certain other contracts, Avista Energy’s earnings are subject to the anomalies caused by the differences between the required accounting and the economic management of these assets and contracts. While Avista Energy has taken measures to enhance profitability and reduce the risk of losses in the future, this business will continue to have volatility in its results.

Avista Energy is subject to certain regulatory proceedings that remain unresolved; however, Avista Energy believes that it has adequate reserves established for refunds that may be ordered. The wholesale energy markets in which Avista Energy operates continue to have volatile market prices and variations in liquidity.

The Energy Marketing Resource Management segment, which consists primarily of Avista Energy, incurred a net loss of $8.6 million for 2005 compared to net income of $9.7 million for 2004. The net loss for 2005 was the first annual net loss for this business segment since 1999. The net loss for 2005 was primarily due to losses in Avista Energy’s natural gas portfolio. The volatility in natural gas and electricity prices can result in significant changes in earnings from Avista Energy from year-to-year. Avista Energy’s trading of electricity and natural gas, as well as asset optimization activities, have been cumulatively profitable since 1999. Asset optimization has resulted in the recovery of a majority of the fixed and variable costs associated with the power purchase agreement for the Lancaster Project for 2006. In addition, early in 2006, the Company captured a significant amount of value relative to prior years, from the economic management of natural gas storage. Earnings associated with these activities, as well as the anticipated future success of trading natural gas and electricity, are expected to return this segment to profitability in 2006.

Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage a foundation on which to expand beyond existing utility bill information services to provide similar services relating to telecom expense management. Net income for Avista Advantage was $3.9 million for 2005, an increase from $0.6 million for 2004 based on increased revenues from an expanding customer base and stabilizing operating expenses from processing efficiencies. The Company expects net income for Avista Advantage to increase in 2006 as compared to 2005.

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. However, the Company may, from time to time, invest incremental funds in these businesses to protect its existing investments. The net loss in the Other business segment was $2.6 million for 2005, a decrease from $7.2 million (excluding the cumulative effect of accounting change) for 2004 primarily due to

 

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decreased losses from asset impairments and write-offs incurred in 2004. The Company expects a similar net loss for 2006 as compared to 2005 for the Other business segment.

Total debt outstanding increased $37.5 million in 2005 primarily to fund utility capital expenditures that were in excess of net cash flows from operating activities. Avista Corp. issued $150.0 million of long-term debt during the fourth quarter of 2005 to, among other things, refinance borrowings on its committed line of credit. For 2006, the Company expects net cash flows from operating activities and Avista Corp.’s committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt, dividends and other contractual commitments. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007.

The Company has management succession plans that work towards ensuring that executive officer and key management positions can be appropriately filled as vacancies occur. The Company has taken similar steps in key technical and craft areas.

Avista Utilities – Electric Resources

As of December 31, 2005, Avista Utilities’ facilities had a total net capability of approximately 1,800 MW, of which 54 percent was hydroelectric and 46 percent was thermal. In addition to company owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources. See “Note 7 of the Notes to Consolidated Financial Statements” for information with respect to Avista Utilities’ resource optimization process.

Avista Utilities – Regulatory Matters

General Rate Cases

In recent years, Avista Utilities has generally not earned its authorized rates of return. Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service and will continue to file for rate adjustments to provide for recovery of its operating costs and capital investments and to more closely align earned returns with those allowed by regulatory agencies. The following table summarizes Avista Utilities’ 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 2006    9.11 %   10.40 %   40 %

Idaho electric and natural gas

   September 2004    9.25 %   10.40 %   43 %

Oregon natural gas

   October 2003    8.88 %   10.25 %   48 %

In December 2005, the WUTC approved Avista Utilities’ combined electric and natural gas general rate case settlement agreement with certain conditions, which were subsequently accepted by the settling parties (Avista Utilities, the WUTC staff, the Northwest Industrial Gas Users and the Energy Project). The WUTC order provided for base rate increases of 7.5 percent for electric and 0.6 percent for natural gas, effective January 1, 2006. The electric base rate increase is designed to increase annual revenues by $21.4 million. The majority of the increase in electric revenues is related to increased power supply costs. As such, a significant portion of the increase will not increase gross margin or net income, because it will be matched by an increase in resource costs. The natural gas base rate increase is designed to increase annual revenues by approximately $1.0 million. The WUTC order also provides for further review of the ERM as discussed at “Power Cost Deferrals and Recovery Mechanisms” below.

As part of the general rate case settlement agreement that was modified and approved by the WUTC order, Avista Utilities has agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. Failure by Avista Utilities to meet those targets could result in a reduction in base rates of 2 percent for each target. The utility equity component was approximately 31 percent as of December 31, 2005.

In January 2005, the WUTC issued its final order with respect to a natural gas general rate case filed by Avista Utilities in Washington. The final order authorized, among other things, an increase in natural gas rates of 3.9 percent, which is designed to increase annual revenues by $5.4 million.

In October 2004, the IPUC issued its final order with respect to electric and natural gas general rate cases filed by Avista Utilities in Idaho. The final order authorized, among other things, Avista Utilities to increase its electric base rates by 16.9 percent, which is designed to increase annual revenues by $24.7 million, and increase its natural gas

 

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base rates by 6.4 percent, which is designed to increase annual revenues by $3.3 million. Due to a decrease implemented concurrently in Avista Utilities’ power cost adjustment (PCA) surcharge and certain other minor adjustments, the net increase in electric rates for Idaho customers was 1.9 percent above rates in effect at that time. Based on the final order, Avista Utilities had to write off a total of $14.4 million of costs in 2004.

Other Regulatory Filings and Rulings

In April 2005, the IPUC issued an order approving the inclusion of the remaining 50 percent of Coyote Springs 2 in base electric rates. The order provides for a 1.9 percent increase in base electric rates, which is designed to increase annual revenues by $3.2 million. At the same time, the IPUC approved a 1.9 percent reduction in the Company’s current PCA rate surcharge. These two requests together resulted in no overall change to customers’ existing rates.

The Oregon Public Utility Commission (OPUC) has issued temporary rules and is in the process of formulating final rules related to Oregon Senate Bill 408 (OSB 408). OSB 408 requires the OPUC to direct the utility to establish an automatic adjustment clause to account for the difference between taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. Taxes paid attributed to Oregon regulated operations are limited to the lesser of consolidated or stand-alone tax payments. 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. Interpretation and application of OSB 408 is complicated by a number of factors, including, but not limited to, the adjustments that are allowed under OSB 408, the Company’s organizational structure, and the fact that the Company provides retail natural gas and electric services in multiple state jurisdictions. At this point in time, the Company cannot predict the effect that OSB 408 may have on revenues or net income related to its Oregon natural gas operations.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future review and the opportunity for recovery through retail rates.

In Washington, the ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM currently provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates, which is referred to as the ERM dead band. Under the ERM, 90 percent of the power supply costs exceeding or below the dead band are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company. The WUTC rejected the proposal in the rate case settlement agreement to reduce the ERM dead band from $9.0 million to $3.0 million. However, Avista Utilities was directed to make a filing with the WUTC by January 31, 2006, with proposed changes to the ERM, including any changes to the ERM dead band. On January 31, 2006, Avista Utilities made its filing with the WUTC proposing that the ERM be continued for an indefinite period of time and that the $9.0 million ERM dead band be eliminated. This filing also satisfied a previous requirement for Avista Utilities to make a filing by the end of 2006 for a review of the ERM. The elimination of the $9.0 million ERM dead band would reduce the volatility of Avista Utilities’ earnings that has been caused by variations in hydroelectric generation, as well as prices for fuel and purchased power. The WUTC has set a procedural schedule that would allow for an order on any changes to the ERM (including any changes to the dead band) to be issued in late June or July of 2006. The WUTC also stated that any changes to the ERM ordered by the WUTC in 2006 would be effective for the full year (beginning January 1, 2006). The Company expensed the entire ERM dead band during 2005, 2004, 2003 and 2002 ($4.5 million in 2002 due to mid-year implementation on July 1, 2002).

The rate case settlement agreement approved by the WUTC increases the ERM surcharge from 9.8 percent to 10.8 percent, which allows Avista Utilities to more rapidly recover deferred power costs.

Under the ERM, Avista Utilities agreed to make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC 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 June 2005, the WUTC issued an order, which approved the recovery of the $10.8 million of deferred power costs incurred for 2004. In March 2006, the Company will make its filing for deferred power costs incurred in 2005.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net

 

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power supply expenses and the authorized level of net power supply expense. As disclosed at “General Rate Cases” above, in October 2004, the IPUC issued its final order with respect to general electric and natural gas rate cases filed by Avista Utilities in Idaho. The IPUC authorized the recovery of remaining deferred power costs over a two-year period through a PCA rate surcharge to customers that was reduced to 4.4 percent. The PCA surcharge was further reduced to 2.5 percent in April 2005 with the approval of the inclusion of the remaining interest in Coyote Springs 2 in base electric rates. The decrease in the PCA rate surcharge extends the recovery period of deferred power costs by an additional year.

The following table shows activity in deferred power costs for Washington and Idaho during 2004 and 2005 (dollars in thousands):

 

     Washington     Idaho     Total  

Deferred power costs as of December 31, 2003

   $ 125,705     $ 30,285     $ 155,990  

Activity from January 1 – December 31, 2004:

      

Power costs deferred

     10,498       15,276       25,774  

Unrealized gain on fuel contracts (1)

     (3,139 )     (1,596 )     (4,735 )

Interest and other net additions

     6,354       532       6,886  

Write-off of deferred power costs

     —         (11,959 )     (11,959 )

Recovery of deferred power costs through retail rates

     (26,210 )     (23,040 )     (49,250 )
                        

Deferred power costs as of December 31, 2004

     113,208       9,498       122,706  

Activity from January 1 – December 31, 2005:

      

Power costs deferred

     4,129       3,938       8,067  

Interest and other net additions

     5,403       278       5,681  

Recovery of deferred power costs through retail rates

     (26,549 )     (5,727 )     (32,276 )
                        

Deferred power costs as of December 31, 2005

   $ 96,191     $ 7,987     $ 104,178  
                        

 

(1) Unrealized gains and losses on fuel contracts are not included in the ERM and PCA mechanism until the contracts are settled or realized.

Purchased Gas Adjustments

Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates. Currently, purchased gas adjustments provide for the deferral and future recovery or refund of 100 percent of the difference between commodity costs and the amount recovered in current retail rates in Washington and Idaho. In Oregon, Avista Utilities has received a tariff revision that provides for 100 percent recovery of known hedges. With respect to the unhedged portion of customer loads, the revised tariff provides for the deferral and future recovery or refund of 90 percent of the difference between actual prices and the amount recovered in current retail rates effective October 1, 2005. The Company has hedged most of its natural gas load requirements in Oregon. During September through November of 2004, natural gas rate increases of 11.7 percent, 14.2 percent and 12.6 percent were implemented in Washington, Idaho and Oregon, respectively. During October and November of 2005, natural gas rate increases of 23.5 percent, 23.8 percent and 22.5 percent were implemented in Washington, Idaho and Oregon, respectively. These natural gas rate increases are designed to pass through increases in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $43.4 million and $28.6 million as of December 31, 2005 and 2004, respectively.

Natural Gas Benchmark Mechanism

See “Natural Gas Benchmark Mechanism” in “Note 1 of the Notes to Consolidated Financial Statements” for a description of the Natural Gas Benchmark Mechanism and related Agency Agreement. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Power Market Issues

Legal and Regulatory Proceedings in Western Power Markets

Avista Energy and Avista Utilities are involved in a number of legal and regulatory proceedings and complaints with respect to power 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 western power markets in 2000 and 2001, which allegedly

 

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contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest, market conduct investigations by the FERC, and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for refunds and damages from Avista Energy and Avista Utilities, which could result in a negative effect on future earnings. Avista Energy and Avista Utilities have joined other parties in opposing these refund claims and complaints for damages. See further information in “Note 26 of the Notes to Consolidated Financial Statements.”

Market Conduct Investigations and Market-Based Rate Authority

As a result of certain revelations about alleged improper practices engaged in by Enron Corporation (Enron) and certain of its affiliates, the FERC initiated investigations in 2002 of many participants in power markets in the western United States, including Avista Corp. doing business as Avista Utilities, and Avista Energy. Avista Utilities and Avista Energy cooperated with the FERC investigation by providing requested documents and other information. Several parties filed documents with the FERC in March 2003 alleging improper market conduct by various parties, including Avista Utilities and Avista Energy, and requesting refunds and other relief. Avista Utilities and Avista Energy filed replies in response to the allegations of the parties.

In March 2003, the FERC policy staff issued its final report on its investigation of western energy markets. In the report, the FERC policy staff recommended the issuance of “show cause” orders to dozens of companies to respond to allegations of possible misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 2003 FERC policy staff report, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. In April 2004, the FERC approved an agreement that resolves the investigation of Avista Corp. and Avista Energy. Other parties filed requests for rehearing and filed motions to intervene in these proceedings. In April 2005, the FERC denied the requests for rehearing and motion to intervene in these proceedings; however, the other parties subsequently filed appeals with the United States Court of Appeals for the Ninth Circuit in response to the FERC’s denial of rehearing requests. See further information under “Federal Energy Regulatory Commission Inquiry” in “Note 26 of the Notes to Consolidated Financial Statements.”

Every three years or more frequently if certain regulatory triggers are met, Avista Corp. doing business as Avista Utilities, and Avista Energy are required to file for renewal of their respective market-based rate authority with the FERC. Avista Utilities and Avista Energy made their respective filings with the FERC in September 2004. By orders issued in March 2005, the FERC approved the renewal of the market-based rate authority of Avista Utilities and Avista Energy.

Wholesale Energy Markets and Development of Regional Transmission Organizations

In July 2005, the FERC announced that it had officially abandoned its efforts commenced in 2002 to create new national standard wholesale power market rules. However, the FERC continues its efforts with respect to the formation of Regional Transmission Organizations. This could significantly change how transmission facilities are regulated and operated. Avista Corp. has participated with other utilities in the western United States on the possible formation of a Regional Transmission Organization (RTO).

The final proposal for any RTO must be filed with the FERC and approved by the boards of directors of the filing companies and regulators in various states. The Company’s decision to move forward with the formation of any RTO serving the Pacific Northwest region, as well as the legal, financial and operating implications of such decisions, will ultimately depend on the terms and conditions related to the formation of the entities and conditions established in the regulatory approval process. The Company cannot predict these implications.

Energy Policy Act of 2005

In August 2005, the Energy Policy Act of 2005 (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 the Company include, but are not limited to, reform of the hydroelectric licensing process, tax credits for incremental hydroelectric production and the implementation of 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. Finally, the Energy Policy Act repealed the Public Utility Holding Company Act of 1935 (PUHCA) 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.

 

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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. In particular, the FERC has initiated rules that, among other things, implement new reliability standards, require that open access be provided to non-regulated transmission utilities, and implement new provisions relating to the repeal of PUHCA.

The Company continues to analyze and implement certain provisions of the Energy Policy Act. Such activities include the proposed formation of a holding company under the new provisions relating to the repeal of the PUHCA.

Results of Operations

Overall Operations

The following provides an overview of changes in the Company’s Consolidated Statements of Income. More detailed explanations are provided, particularly with respect to operating revenues and operating expenses in the business segment discussions (Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other) that follow this section.

2005 compared to 2004

Utility revenues increased $188.7 million due to increases in electric revenues of $71.0 million and natural gas revenues of $117.7 million. The increase in natural gas revenues was primarily due to increased natural gas wholesale sales and increases in retail natural gas sales as a result of rate increases. The increase in electric revenues primarily reflects an increase in wholesale revenues and a slight increase in retail revenues, partially offset by a decrease in sales of fuel.

Non-utility energy marketing and trading revenues increased $9.6 million primarily due to increased revenues for Avista Energy Canada, partially offset by decreased net trading margin on contracts accounted for under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Other non-utility revenues increased $9.7 million to $50.3 million as a result of increased revenues from Avista Advantage of $8.3 million and increased revenues from the Other business segment of $1.4 million. The increase in revenues from Avista Advantage was primarily due to customer growth and the increase from the Other business segment was primarily due to increased sales at AM&D.

Utility resource costs increased $150.6 million primarily due to increased purchased power costs of $41.4 million and increased purchased natural gas costs of $109.9 million. The increase in purchased power and natural gas costs was primarily due to an increase in prices, as well as an increase in the volume of purchases.

Utility other operating expenses increased $1.1 million primarily due to an increase in incentive compensation expenses including performance share payouts, partially offset by a decrease in certain other operating expenses. These decreases in certain other operating expenses include the sale of the South Lake Tahoe natural gas operations and write-offs related the Idaho general rate case incurred in 2004.

Utility depreciation and amortization increased $8.1 million for 2005 compared to 2004 due in part to plant additions and the resulting increase in depreciation expense. Total utility capital expenditures were $213.7 million in 2005. The increase in utility depreciation and amortization was also due to a correction for overstated depreciation expense in prior periods recorded during 2004.

Non-utility resource costs increased $46.4 million primarily due to increased resource costs for Avista Energy Canada and partially due to an increase in transportation and transmission costs.

Other non-utility operating expenses decreased $7.7 million for 2005 compared to 2004 due to asset impairment charges recorded at Avista Power (Energy Marketing and Resource Management segment) in 2004, decreased compensation expense at Avista Energy (Energy Marketing and Resource Management segment), the impairment of goodwill at AM&D, the accrual of environmental liabilities at Avista Development and the write-off of an investment in a natural gas storage project during 2004 (Other business segment). This was partially offset by increased operating expenses for Avista Advantage due to expanding operations.

 

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Interest expense decreased $0.8 million for 2005 compared to 2004 primarily due to a decrease in the effective borrowing rate on long-term debt as a result of previous debt issuances and repurchases, partially offset by an increase in interest expense on short-term borrowings.

Interest expense to affiliated trusts increased $0.4 million due to increasing interest rates and the effect on variable rate debt.

Other income-net increased $1.6 million primarily due to an increase in interest income.

Income taxes increased $4.3 million for 2005 compared to 2004, primarily due to increased income before income taxes. The effective tax rate was 36.4 percent for 2005 compared to 37.7 percent for 2004. The decrease in the effective tax rate was partially due to tax credits for the Kettle Falls Generation Plant that the Company began receiving the benefit from in 2005.

During 2004, the Other business segment recorded as a cumulative effect of accounting change a charge of $0.5 million related to the implementation of Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46), which required Avista Ventures to consolidate several minor entities.

2004 compared to 2003

Income from continuing operations was $35.6 million for 2004 compared to $50.6 million for 2003. This decrease was primarily due to the Idaho general rate case write-offs of $14.4 million ($9.4 million, net of tax) recorded at Avista Utilities, as well as reduced earnings for Avista Energy (Energy Marketing and Resource Management segment) and an increase in the net loss for the Other business segment. This was partially offset by the improved performance of Avista Utilities (excluding the Idaho write-offs) due to general rate increases, as well as net earnings from Avista Advantage for 2004 as compared to a net loss for 2003.

Utility revenues increased $44.4 million due to an increase in natural gas revenues of $43.2 million and an increase in electric revenues of $1.2 million. The increase in natural gas revenues was primarily due to natural gas rate increases and partially due to increased therms sold, primarily as a result of customer growth. The slight increase in electric revenues reflects an increase in retail revenues, partially offset by a decrease in wholesale revenues and sales of fuel.

Non-utility energy marketing and trading revenues decreased $23.3 million primarily due to decreased net trading margin on contracts accounted for under SFAS No. 133 and a settlement with Enron affiliates during 2003, partially offset by increased revenues for Avista Energy Canada.

Other non-utility revenues increased $7.2 million to $40.6 million as a result of increased revenues from Avista Advantage of $3.6 million and increased revenues from the Other business segment of $3.6 million. The increased revenues from Avista Advantage was due to customer growth and the increase for the Other business segment was due to increased revenues from AM&D as well as revenues from entities consolidated in 2004 under FIN 46.

Utility resource costs increased $35.9 million primarily due to an increase in purchased natural gas costs as well as the write-off of $12.0 million of deferred power costs resulting from the Idaho general rate case order. This increase in purchased natural gas costs was primarily due to an increase in prices and partially due to an increase in the volume purchased due to customer growth.

Other utility operating expenses increased $14.9 million due to increased distribution and customer service expenses, an increase in labor costs and other employee related expenses, increased liability and damage claims insurance costs, as well as an increase in outside services. The increase was also partially due to the disallowance in the Idaho general rate case of $2.4 million (net of $0.3 million of accumulated depreciation) of certain capitalized utility plant costs.

Utility depreciation and amortization increased $0.7 million for 2004 compared to 2003 primarily due to plant additions and the resulting increase in depreciation expense as well as the consolidation of WP Funding LP under FIN 46 and the resulting inclusion of depreciation expense of the Rathdrum Power Plant. This was partially offset by a correction for overstated depreciation expense in prior periods recorded during 2004. Coyote Springs 2 was placed into service in mid-2003 and increased depreciation expense for 2004 as compared to 2003.

 

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Utility taxes other than income taxes increased $5.5 million for 2004 compared to 2003 primarily due to increased retail revenues and related taxes, as well as an increase in property taxes.

Non-utility resource costs decreased $2.0 million primarily due to decreased resource costs for Avista Energy Canada.

Other non-utility operating expenses increased $4.4 million for 2004 compared to 2003 due the impairment of goodwill at AM&D, the accrual of an environmental liability at Avista Development, the write-off of an investment in a natural gas storage project, the effects from entities consolidated under FIN 46 (Other business segment) and the settlement of an employment contract at Avista Advantage. This was partially offset by decreased compensation expense and professional fees at Avista Energy (Energy Marketing and Resource Management segment).

Interest expense (including interest expense to affiliated trusts) increased $0.1 million for 2004 compared to 2003 primarily due to the inclusion of the interest expense on $54.6 million of debt of WP Funding LP, which was consolidated for all of 2004 and only the fourth quarter of 2003 as required by FIN 46, as well as an increase in interest on short-term borrowings and the inclusion of preferred stock dividends as interest expense in accordance with SFAS No. 150, partially offset by a decrease in interest expense on long-term debt due to the repurchase of higher cost debt. Preferred stock dividends of $1.1 million, distributed prior to the adoption of SFAS No. 150 on July 1, 2003, were classified as a separate line item in the Consolidated Statement of Income for 2003.

Other income-net increased $2.2 million for 2004 compared to 2003 primarily due to increased income in 2004 on certain investments in the Other business segment and net gains on the disposition of non-operating assets in 2004 compared to net losses in 2003. This was partially offset by the premium paid on the repurchase of Avista Advantage preferred stock, as well as a decrease in interest income and interest on power and natural gas deferrals.

Income taxes decreased $13.7 million for 2004 compared to 2003, primarily due to decreased income before income taxes. The effective tax rate was 37.7 percent for 2004 compared to 41.1 percent for 2003.

During 2004, the Other business segment recorded as a cumulative effect of accounting change a charge of $0.5 million related to the implementation of FIN 46, which required Avista Ventures to consolidate several minor entities.

During 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which effectively required the transition of accounting for energy trading activities from EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” to SFAS No. 133.

Avista Utilities

2005 compared to 2004

Net income for Avista Utilities was $52.5 million for 2005 compared to $32.5 million for 2004. Avista Utilities’ income from operations was $165.4 million for 2005 compared to $134.1 million for 2004. This increase was primarily due to increased gross margin (operating revenues less resource costs) as a result of general rate increases and the IPUC related write-offs of $14.4 million ($9.4 million, net of taxes) in 2004, as well as the $4.1 million pre-tax gain related to the sale of Avista Utilities’ South Lake Tahoe natural gas properties in 2005. This was partially offset by an increase in depreciation expense, taxes other than income taxes and other operating expenses.

The following table presents Avista Utilities’ gross margin for the year ended December 31 (dollars in thousands):

 

     Electric    Natural Gas    Total
     2005    2004    2005    2004    2005    2004

Operating revenues

   $ 723,112    $ 652,081    $ 438,205    $ 320,493    $ 1,161,317    $ 972,574

Resource costs

     343,945      300,958      325,651      218,044      669,596      519,002
                                         

Gross margin

   $ 379,167    $ 351,123    $ 112,554    $ 102,449    $ 491,721    $ 453,572
                                         

Avista Utilities’ operating revenues increased $188.7 million and resource costs increased $150.6 million, which resulted in an increase of $38.1 million in gross margin for 2005 as compared to 2004. The gross margin on electric sales increased $28.0 million and the gross margin on natural gas sales increased $10.1 million. The increase in

 

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electric gross margin was partially due to the IPUC’s disallowance of $12.0 million in deferred power costs in 2004. The increase in electric gross margin was also due to the Idaho electric general rate increase implemented in September 2004, as well as customer growth. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004 and the Washington natural gas general rate increase implemented in November 2004, as well as customer growth in the Washington, Idaho and Oregon service territories. The effects of general rate increases and customer growth were partially offset by the sale of the South Lake Tahoe natural gas operations in April 2005.

The following table presents Avista Utilities’ 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

     2005         2004         2005         2004

Residential

   $ 211,934       $ 209,518       3,420       3,343

Commercial

     203,480         201,775       2,994       2,919

Industrial

     91,552         90,288       2,091       2,076

Public street and highway lighting

     4,898         4,847       25       25
                                

Total retail

     511,864         506,428       8,530       8,363

Wholesale

     151,429         62,399       2,508       1,472

Sales of fuel

     41,831         63,990       —         —  

Other

     17,988         19,264       —         —  
                                

Total

   $ 723,112       $ 652,081       11,038       9,835
                                

Retail electric revenues increased $5.4 million for 2005 from 2004. This increase was primarily due to an increase in total MWhs sold (increased revenues $10.0 million), partially offset by a decrease in revenue per MWh (decreased revenues $4.6 million). The increase in total MWhs sold was primarily due to customer growth and increased use per customer from colder weather during the fourth quarter heating season, partially offset by warmer weather during the first quarter heating season and colder weather during the third quarter cooling season. Total heating degree days at Spokane, Washington for 2005 increased as compared to 2004 with both periods warmer than normal. Total cooling degree days at Spokane, Washington for 2005 decreased as compared to 2004 with both periods warmer than normal. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the Idaho general rate case increased gross margin, income from operations and net income for 2005 as compared to 2004, it did not have a significant effect on operating revenues.

Wholesale electric revenues increased $89.0 million primarily due to an increase in wholesale sales volumes (increased revenues $62.6 million) and partially due to an increase in wholesale sales prices (increased revenues $26.4 million). The increase in wholesale sales volumes reflects added generation capacity, earlier-than-normal and better-than-anticipated runoff to hydroelectric generating assets during 2005 and lower than anticipated retail loads, which resulted in excess resources that were sold in the wholesale market.

Sales of fuel decreased $22.2 million as a greater percentage of fuel purchases were used in generation. Sales of fuel represents natural gas that was not used for generation when electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

Other electric revenues decreased $1.3 million primarily as a result of decreased transmission revenues.

The following table presents Avista Utilities’ 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

     2005    2004    2005    2004

Residential

   $ 229,737    $ 194,470    199,433    201,696

Commercial

     126,648      104,754    122,981    122,852

Industrial

     11,867      9,423    13,534    13,274
                       

Total retail

     368,252      308,647    335,948    337,822

Wholesale

     58,074      152    72,903    305

Transportation

     7,601      8,134    152,990    154,427

Other

     4,278      3,560    466    3,030
                       

Total

   $ 438,205    $ 320,493    562,307    495,584
                       

 

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Natural gas revenues increased $117.7 million for 2005 from 2004 due to an increase in retail natural gas revenues and wholesale natural gas revenues. The $59.6 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $61.7 million), partially offset by a decrease in volumes (decreased revenues $2.1 million). During September through November of 2005 and 2004, retail rates for natural gas were increased in response to an increase in natural gas costs. In September and November 2004, general natural gas rate increases were implemented in Idaho and Washington, respectively. The decrease in total therms sold was primarily due to the sale of the South Lake Tahoe properties, partially offset by customer growth in the other service territories and a slight increase in use per customer. The increase in wholesale revenues reflects the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process that was implemented at Avista Utilities effective April 1, 2005.

The following table presents Avista Utilities’ average number of electric and natural gas customers for the year ended December 31:

 

    

Electric

Customers

  

Natural Gas

Customers

     2005    2004    2005    2004

Residential

   294,036    288,422    265,294    268,571

Commercial

   37,282    36,728    31,652    31,886

Industrial

   1,408    1,416    307    311

Public street and highway lighting

   421    418    —      —  
                   

Total retail

   333,147    326,984    297,253    300,768

Wholesale

   46    43    12    1

Transportation

   —      —      93    81
                   

Total customers

   333,193    327,027    297,358    300,850
                   

The decrease in the average number of natural gas customers from 2004 to 2005 was due to the sale of Avista Utilities’ South Lake Tahoe, California natural gas properties in April 2005. Avista Utilities had approximately 18,750 customers in South Lake Tahoe, California as of December 31, 2004.

The following table presents Avista Utilities’ heating and cooling degree days for the year ended December 31:

 

     2005           2004  

Heating degree days (1):

        

Spokane, Washington actual

   6,538         6,314  

Spokane, Washington 30-year average (2)

   6,820         6,820  

Percent of average

   96 %       93 %

Medford, Oregon actual

   4,185         3,933  

Medford, Oregon 30-year average (2)

   4,533         4,533  

Percent of average

   92 %       87 %

Cooling degree days (3):

        

Spokane, Washington actual

   409         571  

Spokane, Washington 30-year average (2)

   394         394  

Percent of average

   104 %       145 %

 

(1) Heating degree days are a common measure used in the utility industry to analyze the demand for natural gas and electricity during the heating season (generally the first and fourth quarters of a fiscal year and to a lesser extent the second quarter). Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (degree days below historic indicate warmer than average temperatures).

 

(2) Computed for the period from 1971 through 2000.

 

(3) Cooling degree days are used to analyze the demand for electricity during the summer (generally the third quarter) and indicate when a customer would use electricity for air conditioning. Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (degree days above historic indicate warmer than average temperatures).

 

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The following table presents Avista Utilities’ resource costs for the year ended December 31 (dollars in thousands):

 

     2005     2004  

Electric resource costs:

    

Power purchased

   $ 186,703     $ 145,298  

Power cost amortizations, net of deferrals

     24,209       22,950  

Fuel for generation

     93,034       38,406  

Other fuel costs

     36,636       72,602  

Other regulatory amortizations, net

     (6,532 )     (2,529 )

Other electric resource costs

     9,895       24,231  
                

Total electric resource costs

     343,945       300,958  
                

Natural gas resource costs:

    

Natural gas purchased

     335,796       225,908  

Natural gas deferrals, net of amortizations

     (13,912 )     (12,136 )

Other regulatory amortizations, net

     3,767       4,272  
                

Total natural gas resource costs

     325,651       218,044  
                

Total resource costs

   $ 669,596     $ 519,002  
                

Power purchased for 2005 increased $41.4 million compared to 2004 primarily due to an increase in the price of power purchases (increased costs $35.4 million) and partially due to an increase in the volume of power purchases (increased costs $6.0 million). The increase in the price of power represents overall increases in the wholesale energy markets. The increase in the volume of power purchased is consistent with the increase in retail and wholesale sales, partially offset by an increase in thermal generation.

Net amortization of deferred power costs was $24.2 million for 2005 compared to $23.0 million for 2004. During 2005, Avista Utilities recovered (collected as revenue) $26.5 million of previously deferred power costs in Washington and $5.7 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho as compared to 2004, which was primarily due to the reduction of the PCA rate surcharge. During 2005, Avista Utilities deferred $4.1 million and $3.9 million of power costs in Washington and Idaho, respectively. There was a decrease in the deferral of power costs due to lower actual electric resource costs as compared to the amount included in base rates in 2005 as compared to 2004.

Fuel for generation for 2005 increased $54.6 million compared to 2004 due to an increase in fuel prices and greater use of thermal generation, which increased 52 percent for 2005 as compared to 2004, primarily due to the addition of the remaining interest in Coyote Springs 2.

Other fuel costs for 2005 decreased $36.0 million compared to 2004. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Revenues from selling the natural gas exceeded other fuel costs in 2005. This excess revenue is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to a greater percentage of fuel used in generation.

Other electric resource costs for 2005 decreased $14.3 million compared to 2004 primarily due to the disallowance of $12.0 million of deferred power costs in the 2004 Idaho general rate case.

The expense for natural gas purchased for 2005 increased $109.9 million compared to 2004 due to an increase in the cost of natural gas (increased costs $54.5 million) and an increase in total therms purchased (increased costs $55.4 million). The increase in total therms purchased is consistent with an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process. During 2005, Avista Utilities had $13.9 million of net deferrals of natural gas costs compared to $12.1 million of net deferrals for 2004. The increase reflects higher natural gas prices, partially offset by increased natural gas rates to recover deferred natural gas costs.

2004 compared to 2003

Net income for Avista Utilities was $32.5 million for 2004 compared to $36.2 million for 2003. Avista Utilities’ income from operations was $134.1 million for 2004 compared to $146.8 million for 2003. This decrease was primarily due to the write-offs of $14.4 million ($9.4 million, net of tax) related to the 2004 Idaho general rate case. Excluding the write-offs, net income and income from operations increased primarily due to an increase in gross margin as a result of general rate increases, partially offset by an increase in other operating expenses, depreciation and amortization, and taxes other than income taxes.

 

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The following table presents Avista Utilities’ gross margin for the years ended December 31 (dollars in thousands):

 

     Electric    Natural Gas    Total
     2004    2003    2004    2003    2004    2003

Operating revenues

   $ 652,081    $ 650,922    $ 320,493    $ 277,289    $ 972,574    $ 928,211

Resource costs

     300,958      299,428      218,044      183,669      519,002      483,097
                                         

Gross margin

   $ 351,123    $ 351,494    $ 102,449    $ 93,620    $ 453,572    $ 445,114
                                         

Avista Utilities’ operating revenues increased $44.4 million and resource costs increased $35.9 million, which resulted in an increase of $8.5 million in gross margin for 2004 as compared to 2003. The gross margin on natural gas sales increased $8.8 million and the gross margin on electric sales decreased $0.3 million. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004, the Washington natural gas general rate increase implemented in November 2004 and the Oregon natural gas general rate increase implemented in the fourth quarter of 2003. The slight decrease in electric gross margin was primarily due to the disallowance of $12.0 million of deferred power costs in the Idaho general rate case, partially offset by the Idaho electric general rate increase implemented in September 2004 as well as customer growth.

The following table presents Avista Utilities’ electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (dollars and MWhs in thousands):

 

     Electric Operating Revenues    Electric Energy MWh sales
     2004    2003    2004    2003

Residential

   $ 209,518    $ 204,783    3,343    3,298

Commercial

     201,775      201,339    2,919    2,919

Industrial

     90,288      78,276    2,076    1,785

Public street and highway lighting

     4,847      4,770    25    25
                       

Total retail

     506,428      489,168    8,363    8,027

Wholesale

     62,399      73,463    1,472    2,075

Sales of fuel

     63,990      71,456    —      —  

Other

     19,264      16,835    —      —  
                       

Total

   $ 652,081    $ 650,922    9,835    10,102
                       

Retail electric revenues increased $17.3 million for 2004 from 2003. This increase was primarily due to an increase in total MWhs sold (increased revenues $20.4 million), partially offset by a decrease in revenue per MWh (decreased revenues $3.1 million). Although there were differences with respect to quarter-to-quarter comparisons, total heating and cooling degree days at Spokane, Washington for both 2004 and 2003 were similar with both warmer than normal heating and cooling seasons. As such, electric loads and revenues were not significantly affected by weather when comparing 2004 to 2003 results. The increase in total MWhs sold and corresponding revenues was primarily due to customer growth as well as the Potlatch Corporation contract, which was entered into during mid-2003. The decrease in revenue per MWh was primarily due to a slight change in revenue mix with a greater percentage of revenues from industrial sales. The increase in industrial revenues was primarily due to the Potlatch Corporation contract. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the general rate case increased gross margin, income from operations and net income, it did not have a significant effect on operating revenues for 2004 as compared to 2003.

Wholesale electric revenues decreased $11.1 million primarily due to the implementation of EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3” which requires that wholesale revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) should be reported on a net basis as part of operating revenues effective October 1, 2003. The adoption of this EITF Issue resulted in a reduction in wholesale revenues of approximately $26.4 million for 2004 as compared to 2003. The remaining change in wholesale revenues reflects higher average sales prices and an increase in wholesale volumes.

Sales of fuel decreased $7.5 million as a result of the expiration of several higher priced fuel contracts. A greater percentage of fuel purchases were used in generation, which also contributed to the decrease in sales of fuel. Sales of fuel represents natural gas that was not used for generation because electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

 

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Other electric revenues increased $2.4 million primarily due to increased transmission revenues.

The following table presents Avista Utilities’ natural gas operating revenues and therm sales for the years ended December 31 (dollars and therms in thousands):

 

    

Natural Gas

Operating Revenues

       

Natural Gas

Therm Sales

     2004         2003         2004         2003

Residential

   $ 194,470       $ 166,925       201,696       198,471

Commercial

     104,754         90,523       122,852       122,115

Industrial

     9,423         7,475       13,274       12,737
                                

Total retail

     308,647         264,923       337,822       333,323

Wholesale

     152         280       305       675

Transportation

     8,134         8,485       154,427       153,352

Other

     3,560         3,601       3,030       3,124
                                

Total

   $ 320,493       $ 277,289       495,584       490,474
                                

Natural gas revenues increased $43.2 million for 2004 from 2003 primarily due to an increase in retail natural gas revenues, partially offset by a slight decrease in transportation and wholesale revenues. The $43.7 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $39.6 million) and partially due to an increase in volumes (increased revenues $4.1 million). During 2004 and 2003, retail rates for natural gas were increased in response to an increase in current and projected natural gas costs. In September 2004, a general natural gas rate increase was implemented in Idaho. In November 2004, a general natural gas rate increase was implemented in Washington. Also, during the fourth quarter of 2003, a general natural gas rate increase was implemented in Oregon. The increase in total therms sold was primarily a result of customer growth, as a colder first quarter of 2004 was offset by a warmer fourth quarter of 2004 as compared to 2003.

The following table presents Avista Utilities’ average number of electric and natural gas customers for the years ended December 31:

 

    

Electric

Customers

       

Natural Gas

Customers

     2004         2003         2004         2003

Residential

   288,422       283,497       268,571       261,063

Commercial

   36,728       36,279       31,886       31,312

Industrial

   1,416       1,414       311       310

Public street and highway lighting

   418       422       —         —  
                            

Total retail

   326,984       321,612       300,768       292,685

Wholesale

   43       47       1       1

Transportation

   —         —         81       84
                            

Total customers

   327,027       321,659       300,850       292,770
                            

The following table presents Avista Utilities’ heating and cooling degree days for the years ended December 31:

 

     2004          2003  

Heating degree days (1):

       

Spokane, Washington actual

   6,314        6,351  

Spokane, Washington 30-year average (2)

   6,820        6,820  

Percentage of average

   93 %      93 %

Medford, Oregon actual

   3,933        4,046  

Medford, Oregon 30-year average (2)

   4,533        4,533  

Percentage of average

   87 %      89 %

Cooling degree days (3):

       

Spokane, Washington actual

   571        578  

Spokane, Washington 30-year average (2)

   394        394  

Percent of average

   145 %      147 %

 

(1) Heating degree days are a common measure used in the utility industry to analyze the demand for natural gas and electricity during the heating season (generally the first and fourth quarters of a fiscal year and to a lesser extent the second quarter). Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (degree days below historic indicate warmer than average temperatures).

 

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(2) Computed for the period from 1971 through 2000.

 

(3) Cooling degree days are used to analyze the demand for electricity during the summer (generally the third quarter) and indicate when a customer would use electricity for air conditioning. Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (degree days above historic indicate warmer than average temperatures).

The following table presents Avista Utilities’ resource costs for the years ended December 31 (dollars in thousands):

 

     2004     2003  

Electric resource costs:

    

Power purchased

   $ 145,298     $ 147,743  

Power cost amortizations, net of deferrals

     22,950       7,165  

Fuel for generation

     38,406       35,581  

Other fuel costs

     72,602       96,765  

Other regulatory amortizations, net

     (2,529 )     541  

Other electric resource costs

     24,231       11,633  
                

Total electric resource costs

     300,958       299,428  
                

Natural gas resource costs:

    

Natural gas purchased

     225,908       184,014  

Natural gas deferrals, net of amortization

     (12,136 )     (3,336 )

Other regulatory amortizations, net

     4,272       2,991  
                

Total natural gas resource costs

     218,044       183,669  
                

Total resource costs

   $ 519,002     $ 483,097  
                

Power purchased for 2004 decreased $2.4 million compared to 2003 due to the effects of EITF Issue No. 03-11 (decreased costs by $26.4 million), partially offset by an increase in the price of power purchases (increased costs $15.1 million) and an increase in the volume of power purchases (increased costs $8.9 million).

Net amortization of deferred power costs was $23.0 million for 2004 compared to $7.2 million for 2003. During 2004, Avista Utilities recovered (collected as revenue) $26.2 million of previously deferred power costs in Washington and $23.0 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho, which was primarily due to the reduction of the PCA rate surcharge in the Idaho general rate case. During 2004, Avista Utilities deferred $10.5 million of power costs in Washington and $15.3 million in Idaho. The total deferral of power costs decreased in 2004 as compared to 2003 due to an increase in hydroelectric generation and the expiration of higher priced natural gas fuel contracts.

Fuel for generation for 2004 increased $2.8 million compared to 2003 primarily due to an increase in fuel prices and partially due to a slight increase in thermal generation.

Other fuel costs for 2004 decreased $24.2 million compared to 2003. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Other fuel costs exceeded the revenues from selling the natural gas in 2004 and 2003. This excess cost is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to the expiration of higher-priced natural gas fuel contracts. The decrease was also due to a greater percentage of fuel used in generation.

Other electric resource costs for 2004 increased $12.6 million compared to 2003 primarily due to the disallowance of $12.0 million of deferred power costs in the Idaho general rate case.

The expense for natural gas purchased for 2004 increased $41.9 million compared to 2003 due to an increase in the cost of natural gas (increased costs $37.4 million) and an increase in total therms purchased (increased costs $4.5 million) consistent with an increase in natural gas sales from customer growth. During 2004, Avista Utilities had $12.1 million of net deferrals of natural gas costs compared to $3.3 million for 2003. The increase was primarily due to an increase in natural gas prices.

 

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Energy Marketing and Resource Management

Energy Marketing and Resource Management primarily includes the results of Avista Energy, as well as Avista Power.

Avista Energy’s earnings are primarily derived from the following activities:

 

    Taking speculative positions on future price movements within established risk management policies.

 

    Optimization of generation assets owned by other entities.

 

    Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.

 

    Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.

 

    Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.

 

    Marketing natural gas to end-user industrial and commercial customers.

Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in resource costs.

The following table presents Avista Energy’s net realized gains and net unrealized losses for the years ended December 31 (dollars in thousands):

 

     2005     2004     2003  

Net realized gains

   $ 40,142     $ 39,520     $ 82,317  

Net unrealized losses

     (38,126 )     (678 )     (22,128 )
                        

Total gross margin (operating revenues less resource costs)

   $ 2,016     $ 38,842     $ 60,189  
                        

Overall segment results for 2005 compared to 2004

Energy Marketing and Resource Management’s net loss was $8.6 million for 2005 compared to net income of $9.7 million for 2004. The net loss was primarily due to changes in natural gas prices relative to the positions that Avista Energy had taken in the natural gas market. While Avista Energy’s portfolio was within its position limits and in accordance with its risk management practices, losses can and do occur when the market moves contrary to its positions, which occurred during 2005. As markets moved counter to certain contracts, Avista Energy acted to adjust its position consistent with established risk management policies. This process reduced the market risk; however, it had the effect of locking in losses on certain natural gas positions during 2005. While Avista Energy reduced the market risk in its natural gas trading portfolio considerably in the second half of 2005, some losses did continue to occur during the fourth quarter as Avista Energy continued to unwind positions established in earlier periods.

Avista Energy continued to produce positive results on the power side of its business in 2005, which includes trading, marketing and managing the output and availability of generation assets owned by other entities. However, gains from the power side of Avista Energy’s business were less in 2005 as compared to 2004.

Total assets for the Energy Marketing and Resource Management segment increased $1,009.5 million from December 31, 2004 to December 31, 2005 primarily as a result of the increase in commodity prices (particularly natural gas) and the effect on Avista Energy’s derivative commodity assets.

Overall segment results for 2004 compared to 2003

Energy Marketing and Resource Management’s net income was $9.7 million for 2004, compared to net income before the cumulative effect of accounting change of $20.7 million for 2003. During 2003, Avista Energy’s earnings were positively affected by the difference in the economic management and the required accounting for certain contracts and physical assets under management (see discussion below), as well as a settlement with certain Enron affiliates. In addition, Avista Energy’s earnings were decreased due to lower natural gas trading margins in 2004 as compared to 2003. These decreases were partially offset by portfolio valuation adjustments at Avista Energy of approximately $2.9 million, net of tax, the most significant of which related to increases in market liquidity in the Western power markets. Avista Energy’s commodity portfolio was historically valued using third-party broker

 

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market quotes for the first 24 months and using a model for the long-term portion of the portfolio. Increased market liquidity resulted in the availability of reliable and transparent market prices for a longer time period than had previously been available. Based on this change in market liquidity, Avista Energy began utilizing third-party market price quotes for the first 36 months of the portfolio beginning in the fourth quarter of 2004. Avista Energy continues to use a model to estimate forward price curves for the longer-term portion of the portfolio. The Company believes this change in valuation methodology represents the most accurate valuation of the portfolio.

Analysis of differences in the economic management and the required accounting for certain contracts and physical assets under management

The operations of Avista Energy are managed on an economic basis reflecting all contracts and assets under management at estimated market value, which is different from the required accounting for certain contracts and physical assets under management. Under SFAS No. 133, certain contracts, which are considered derivatives and accounted for at market value, economically hedge other contracts and physical assets under management, which are not considered derivatives and are generally accounted for at the lower of cost or market value. The accounting treatment does not affect the underlying cash flows or economics of these transactions. These differences are generally reversed in future periods as market values change or the contracts are settled or realized. These differences primarily relate to Avista Energy’s management of natural gas inventory and Avista Energy’s control of natural gas-fired generation through a power purchase agreement.

Avista Energy is affected by earnings volatility associated with its economic management of natural gas inventory. Generally, injections of natural gas into storage take place in the summer months and natural gas is withdrawn from inventory in the winter months. Avista Energy economically hedges the value of natural gas inventory with financial and physical sales, effectively locking in a margin on the natural gas inventory. However, accounting rules require the natural gas inventory to be carried at the lower of cost or market, while the forward sales contracts (which are derivatives) are marked-to-market using forward price curves. Changes in forward price curves result in income or losses on the derivative sales contracts, but generally do not affect the recorded value for natural gas inventory. Therefore, if Avista Energy enters into a forward contract to sell natural gas as an economic hedge against the value of natural gas inventory, and market prices subsequently increase, a loss with respect to the forward contract is recorded in net income. While the market value of the natural gas inventory has also increased, the natural gas inventory remains recorded at the lower of cost or market value. During 2005, increases in the market price of natural gas and changes in inventory balances had a negative effect on net income of $2.7 million with respect to Avista Energy’s economic management of natural gas inventory. During 2004, this activity and changes in natural gas prices had a positive effect on net income of $0.9 million. During 2003, this activity and changes in natural gas prices had a negative effect on net income of $1.6 million. In early 2006, Avista Energy made the economic decision to sell its natural gas inventory forward for delivery in the first quarter of 2007. This transaction will allow Avista Energy to capture approximately $4 million of after-tax economic value. This forward sale will have to be marked to market in 2006, and it will result in earnings volatility. However, this decision is part of the prudent economic management of Avista Energy’s assets.

Avista Energy controls natural gas-fired generation through a power purchase agreement related to the Lancaster Project. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation, and convert to electricity for a fixed fee. Avista Energy economically hedges the value of this power purchase agreement by entering into contracts to buy and sell natural gas and electricity during certain time periods in the future. Although the power purchase agreement is not a derivative and not marked-to-market, the contracts to buy and sell natural gas and electricity are derivatives that are recorded at estimated market value. Where possible, Avista Energy has designated the natural gas and electricity contracts as accounting hedges in accordance with SFAS No. 133 in order to reduce the earnings volatility associated with these combinations of accounting treatments. However, not all of these contracts qualify for hedge accounting. Avista Energy will continue to recognize changes in the fair value of those contracts in earnings as unrealized gains and losses. In addition, the ineffective portion of the change in the forward value of qualifying hedges will continue to be recognized in earnings. Similar to natural gas inventory, the power purchase agreement is economically managed as if it is recorded at estimated market value. During 2005, changes in natural gas and electricity prices for the future delivery periods in which the contract had been economically hedged (but not hedged in accordance with SFAS No. 133) had a positive effect on net income of approximately $1.8 million. During 2004, this activity and changes in prices had a negative effect on net income of approximately $2.4 million. During 2003, this activity and changes in prices had a positive effect on net income of approximately $4.7 million.

Avista Energy has other differences between the economic management and the required accounting for certain contracts and physical assets under management, which have not been as significant as those described above.

 

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However, these items could become more significant in the future and Avista Energy could enter into new contracts and agreements that could result in significant differences in future periods.

Analysis of operating revenues, resource costs and gross margin for 2005 compared to 2004

Operating revenues decreased $108.2 million and resource costs decreased $71.4 million for 2005 as compared to 2004 resulting in a decrease in gross margin of $36.8 million. Operating revenues decreased primarily due to decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, and decreased net trading margin on contracts accounted for under SFAS No. 133, partially offset by increased revenues for Avista Energy Canada. Resource costs decreased primarily due to decreased resource costs under the Agency Agreement with Avista Utilities, partially offset by increased resource costs for Avista Energy Canada.

Avista Energy’s gross margin (operating revenues less resource costs) was $2.0 million for 2005 compared to $38.8 million for 2004. The decrease in gross margin was primarily due to the increase in natural gas prices and the resulting impact on Avista Energy’s natural gas positions. In addition, unfavorable movements in power prices also had a negative effect on Avista Energy’s gross margin for 2005 as compared to 2004.

Net realized gains increased to $40.1 million for 2005 from $39.5 million for 2004. The slight increase in net realized gains was due to increased net gains on settled financial transactions and physical electric transactions, partially offset by increased net losses on physical natural gas transactions and increased transmission and transportation fees. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $38.1 million for 2005 compared to a net unrealized loss of $0.7 million for 2004. The net unrealized loss for 2005 was primarily due to realization of physical electric transactions and price movements that were unfavorable to Avista Energy’s positions.

Analysis of operating revenues, resource costs and gross margin for 2004 compared to 2003

Operating revenues decreased $31.5 million and resource costs decreased $10.1 million for 2004 as compared to 2003 resulting in a decrease in gross margin of $21.4 million. Operating revenues decreased primarily due to decreased net trading margin on contracts accounted for under SFAS No. 133, a settlement with Enron affiliates during 2003 and decreased revenues under the Agency Agreement with Avista Utilities, partially offset by increased revenues for Avista Energy Canada. Resource costs decreased primarily due to decreased resource costs for Avista Energy Canada and decreased resource costs under the Agency Agreement with Avista Utilities.

Avista Energy’s gross margin (operating revenues less resource costs) was $38.8 million for 2004 compared to $60.2 million for 2003. The decrease in gross margin was primarily due to the 2003 effects of the transition to SFAS No. 133 and the settlement with Enron affiliates. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This has partially mitigated the effects from the transition to SFAS No. 133 and reduced the volatility of reporting earnings on a prospective basis. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive effect of $8.4 million on gross margin for 2003.

Net realized gains decreased to $39.5 million for 2004 from $82.3 million for 2003. Net realized gains represent the net gains on contracts that have settled. The decrease in net realized gains was due to an increase in the net losses on physical natural gas transactions, the settlement with Enron affiliates in the prior year, decreased net gains on settled financial transactions and decreased net gains on settled foreign currency transactions. This was partially offset by increased net gains on settled physical electric transactions and a change in the net gain on the valuation of natural gas inventory. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $0.7 million for 2004 compared to a net unrealized loss of $22.1 million for 2003. The change in the net unrealized loss was primarily due to the effects of the transition to SFAS No. 133. The decrease in the net unrealized loss was also due to the settlement of contracts and the realization of previously unrealized gains during 2003. In 2004, portfolio valuation adjustments at Avista Energy resulting primarily from increases in market liquidity in the Western power markets decreased the net unrealized loss and increased gross margin by $4.5 million.

 

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Energy trading activities and positions

The following table summarizes information with respect to Avista Energy’s trading activities during 2005 (dollars in thousands):

 

    

Electric

Assets net of

Liabilities

   

Natural Gas

Assets net of

Liabilities

   

Total

Unrealized

Gain (Loss)

 

Fair value of contracts as of December 31, 2004

   $ 58,965     $ 11,341     $ 70,306  

Less contracts settled during 2005 (1)

     (86,272 )     46,130       (40,142 )

Fair value of new contracts when entered into during 2005 (2)

     —         —         —    

Change in fair value due to changes in valuation techniques (3)

     —         —         —    

Change in fair value attributable to market prices and other market changes

     45,989       (41,702 )     4,287  
                        

Fair value of contracts as of December 31, 2005

   $ 18,682     $ 15,769     $ 34,451  
                        

 

(1) Contracts settled during 2005 include those contracts that were open in 2004 but settled during 2005 as well as new contracts entered into and settled during 2005. Amount represents net realized gains associated with these settled transactions.

 

(2) Avista Energy did not enter into any origination transactions during 2005 in which dealer profit or mark-to-market gain or loss was recorded at inception.

 

(3) During 2005, Avista Energy did not experience a change in fair value due to changes in valuation techniques.

The following table discloses summarized information with respect to valuation techniques and contractual maturities of Avista Energy’s energy commodity contracts outstanding as of December 31, 2005 (dollars in thousands):

 

    

Less than

one year

   

Greater

than one

and less than

three years

   

Greater

than three

and less than

five years

   

Greater

than

five years

    Total  

Electric assets (liabilities), net

          

Prices from other external sources (1)

   $ 620     $ 34,537     $ —       $ —       $ 35,157  

Fair value based on valuation models (2)

     (1,502 )     (2,121 )     12,892       (25,744 )     (16,475 )
                                        

Total electric assets (liabilities), net

   $ (882 )   $ 32,416     $ 12,892     $ (25,744 )   $ 18,682  
                                        

Natural gas assets (liabilities), net

          

Prices from other external sources (1)

   $ 11,247     $ 4,687     $ —       $ —       $ 15,934  

Fair value based on valuation models (3)

     1,451       (1,421 )     (195 )     —         (165 )
                                        

Total natural gas assets (liabilities), net

   $ 12,698     $ 3,266     $ (195 )   $ —       $ 15,769  
                                        

 

(1) Fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. These market quotes are used through 36 months.

 

(2) Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than 36 months, for which active quotes are not available. These internally developed market curves are determined using a production cost model with inputs for assumptions related to power prices (including, without limitation, natural gas prices, generation on-line, transmission constraints, future demand and weather). Avista Energy performs frequent stress tests on the valuation of the portfolio. While consistent valuation methodologies and updates to the assumptions are used to capture current market information, changes in these methodologies or underlying assumptions could result in significantly different fair values and income recognition. These same pricing techniques and stress tests are used to evaluate a contract prior to taking a position.

 

(3) Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than 36 months, for which active quotes are not available. These internally developed market curves are based upon published New York Mercantile Exchange prices, as well as basis spreads using historical and broker estimates.

Avista Power

The results for Avista Power did not have a significant effect on the results for the Energy Marketing and Resource Management segment for 2005. In 2004 and 2003, the Company recorded impairment charges for a turbine and related equipment owned by Avista Power. This resulted in charges of $5.1 million and $4.9 million for 2004 and 2003, respectively, included in other operating expenses. The effect on net income from these impairment charges was $3.3 million and $3.2 million, net of tax, for 2004 and 2003, respectively.

 

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Avista Advantage

2005 compared to 2004

Net income for Avista Advantage was $3.9 million for 2005 compared to $0.6 million for 2004. Operating revenues for Avista Advantage increased $8.3 million and operating expenses increased $3.1 million as compared to 2004. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage has approximately 350 customers representing approximately 175,000 billed sites in North America. The number of billed sites increased by approximately 33,000, or 24 percent, in 2005. Avista Advantage continues to have strong customer retention with an average 95 percent retention rate over the past three years. The increase in operating expenses over 2004 primarily reflects increased labor costs necessary to serve an expanding customer base, partially offset by increased efficiencies and the settlement of an employment contract during 2004. Avista Advantage’s average cost of processing a bill decreased 6 percent for 2005 as compared to 2004.

2004 compared to 2003

Avista Advantage had net income of $0.6 million for 2004 compared to a net loss of $1.3 million for 2003. Operating revenues for Avista Advantage increased $3.6 million and operating expenses increased $0.5 million as compared to 2003. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had a 29 percent increase in the number of billed sites as of December 31, 2004 as compared to December 31, 2003. The increase in operating expenses reflects the settlement of an employment contract, partially offset by improved efficiencies and a focus on reducing operating expenses. Avista Advantage’s cost of processing a bill decreased by 11 percent for 2004 as compared to 2003.

Other Business Segment

2005 compared to 2004

The net loss from this business segment was $2.6 million for 2005 compared to a net loss of $7.2 million (excluding the cumulative effect of accounting change) for 2004. The decrease in the net loss was primarily due to the impairment of goodwill at AM&D, the write-off of an investment in a natural gas storage project, the accrual of environmental liabilities at Avista Development and Avista Capital’s purchase of Avista Advantage preferred stock at a premium during 2004. Operating revenues from this business segment increased $1.4 million and operating expenses decreased $3.6 million, respectively, for 2005 as compared to 2004. The net loss for AM&D was $0.8 million for 2005 compared to $1.0 million for 2004 (excluding the impairment of goodwill).

2004 compared to 2003

The net loss before the cumulative effect of accounting change from this business segment was $7.2 million for 2004 compared to a net loss of $4.9 million for 2003. The increase in the net loss was primarily due to the impairment of goodwill at AM&D, the write-off of an investment in a natural gas storage project, the accrual of environmental liabilities at Avista Development and Avista Capital’s purchase of Avista Advantage preferred stock at a premium. This was partially offset by a decrease in the loss from AM&D (excluding the impairment of goodwill) as well as certain other investments of Avista Ventures. Operating revenues from this business segment increased $3.6 million and operating expenses increased $6.8 million, respectively, for 2004 as compared to 2003. The consolidation of several minor entities pursuant to FIN 46 contributed to the increase in operating revenues and operating expenses. The net loss from AM&D decreased to $1.0 million for 2004 (excluding the impairment of goodwill), from $2.3 million for 2003.

New Accounting Standards

Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. The Company expects to record compensation expense (net of tax) of approximately $0.4 million in 2006 related to the periodic vesting of stock options granted to employees prior to 2005. The Company also expects to record compensation expense (net of tax) of approximately $1.7 million, $1.1 million and $0.5 million in 2006, 2007 and 2008, respectively, for performance share awards granted to employees in 2004, 2005 and the first quarter of 2006. For further information see “Note 2 of the Notes to Consolidated Financial Statements.”

 

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Critical Accounting Policies and Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management 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 the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that the Company’s 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 Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the 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, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. The estimate of unbilled revenue is based on the number of customers, current rates, meter reading dates, weather (degree days), as well as 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

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires the Company to reflect the effect of regulatory decisions in its 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) are reflected as deferred charges on the Consolidated Balance Sheets and are not reflected in the statement of income until the period during which matching revenues are recognized. The Company has mechanisms in place in each regulatory jurisdiction, and the Company expects to recover its regulatory assets through future rates. These regulatory assets are subject to review for prudence and recoverability and, as such, certain deferred costs may be disallowed by the respective regulatory agencies. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write off its regulatory assets. The Company could also be precluded from the future deferral of costs not recovered through rates when such costs are incurred, even if the Company expects to recover such costs in the future.

Avista Utilities Energy Commodity Derivative Assets and Liabilities

Avista Utilities 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 Avista Utilities’ management of its loads and resources and certain contracts are considered derivative instruments. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Utilities 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. The order provides for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM and the PCA mechanism. Quoted market prices and forward price curves are used to estimate the fair value of Avista Utilities’ derivative commodity instruments. As such, the fair value of Avista Utilities’ derivative commodity instruments, which are recorded on the Consolidated Balance Sheet, are sensitive to market price fluctuations that can occur on a daily basis.

Avista Energy Revenues and Trading Activities

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are marked to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the Consolidated Statements of Income in the period of change. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments, which are reported as assets and liabilities on the Consolidated Balance Sheets. These market prices are used through 36 months. For longer-term positions and certain short-term positions for which market prices are not available, models are used to estimate market values. These models incorporate a variety of estimates and assumptions, the ultimate outcomes of

 

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which are beyond Avista Energy’s control including, among others, estimates and assumptions as to demand growth, fuel price escalation, availability of existing generation and costs of new generation. Actual experience can vary significantly from these estimates and assumptions.

Avista Energy has implemented hedge accounting in accordance with SFAS No. 133. Specific natural gas and electric trading derivative contracts have been designated as hedging instruments in cash flow hedging relationships. The hedge strategies represent cash flow hedges of the variable price risk associated with expected purchases of natural gas and sales of electricity. These designated hedging instruments represent hedges of variable price exposures generated from certain contracts, which do not qualify as derivatives under SFAS No. 133. For all derivatives designated as cash flow hedges, Avista Energy documents the relationship between the hedging instrument and the hedged item (forecasted purchases and sales of power and natural gas), as well as the risk management objective and strategy for using the hedging instrument. Avista Energy assesses whether a change in the value of the designated derivative is highly effective in achieving offsetting cash flows attributable to the hedged item, both at the inception of the hedge and on an ongoing basis. Any changes in the fair value of the designated derivative that are effective are recorded in accumulated other comprehensive income or loss, while changes in fair value that are not effective are recognized currently in earnings as operating revenues. Amounts recorded in accumulated other comprehensive income or loss are recognized in earnings during the period that the hedged items are recognized in earnings.

Pension Plans and Other Postretirement Benefit Plans

The Company has a defined benefit pension plan covering substantially all of its regular full-time employees at Avista Utilities and Avista Energy. As of December 31, 2005, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2005, the pension plan funding deficit increased as compared to the end of 2004. As such, the Company increased the additional minimum liability for the unfunded accumulated benefit obligation by $2.8 million and decreased the intangible asset by $0.7 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in a charge to other comprehensive income of $2.3 million, net of tax, for 2005.

The Finance Committee of the Company’s Board of Directors establishes investment policies, objectives and strategies to seek optimum return for the pension plan, while also keeping with the assumption of prudent risk and the Finance Committee’s composite return objectives. The Finance Committee reviews and approves changes to the investment policy. The Company has contracted with an investment manager who is responsible for managing the individual investment managers. The investment manager’s performance and related individual fund performance is periodically reviewed by the Finance Committee to ensure compliance with investment policy objectives and strategies. Pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real estate and other investments, including hedge funds and venture capital funds. In seeking to obtain the desired return to fund the pension plan, the Finance Committee has established investment allocation percentages by asset classes as disclosed in “Note 12 of the Notes to Consolidated Financial Statements.”

The Company’s pension costs (including its Supplemental Executive Retirement Plan (SERP)) were $13.4 million, $14.9 million and $16.1 million for 2005, 2004 and 2003, respectively. Of these pension costs, approximately 70 percent are expensed and approximately 30 percent are capitalized. The Company’s costs for the pension plan are determined in part by actuarial formulas and are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by actual employee demographics (including age, compensation and length of service by employees), the amount of cash contributions the Company makes to the pension plan and the return on pension plan assets. Changes made to the provisions of the 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, the discount rate used in determining the projected benefit obligation and pension costs, as well as the 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 the Consolidated Statement of Income, but generally are recognized in future years over the remaining average service period of pension plan participants. As such, costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.

The Company has not made any changes to pension plan provisions in 2005, 2004 and 2003 that have had any significant effect on recorded pension plan amounts. The Company has revised the key assumption of the discount rate in 2004 and 2003 and the key assumption of the expected long-term return on assets in 2005. Such change had an effect on reported pension costs in 2005, 2004 and 2003 and may have an effect on future years given the cost recognition approach described above. However, in determining pension obligation and cost amounts, assumptions can change from period to period, and such changes could result in material changes to future pension costs and funding requirements.

 

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In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. The Company used a discount rate of 5.75 percent in 2005 and 2004 for estimating the benefit obligation. The Company reduced the discount rate in 2004 to 5.75 percent from 6.25 percent. The Company reduced the discount rate in 2003 to 6.25 percent from 6.75 percent. These decreases in discount rates have increased the projected benefit obligation, pension liability and pension costs.

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 the plan. The assumed long-term rate of return was 8.5 percent in 2005, and 8 percent in each of 2004 and 2003. For 2005, 2004 and 2003, the actual return on plan assets, net of fees, was a gain of $11.3 million (or 6.1 percent), $16.1 million (or 10.4 percent) and $32.3 million (or 23.3 percent), respectively. The pension plan asset allocation was modified in 2003 to include hedge, real estate and actively managed large cap growth and value funds and decrease fixed income and small cap equities allocations. The estimated long-term rate of return on assets was analyzed based upon the revised investment portfolio. The assumed long-term rate of return on assets was increased in 2005 based upon the analysis.

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 Liability

   

Effect on

Pension Cost

 

Expected long-term return on plan assets

   -0.5 %   $ —       $ —   *   $ 937  

Expected long-term return on plan assets

   +0.5 %     —         —   *     (936 )

Discount rate

   -0.5 %     21,506       15,444       2,057  

Discount rate

   +0.5 %     (19,306 )     (13,964 )     (1,868 )

 

* As the Company has already recorded an additional minimum liability for the unfunded accumulated benefit obligation, changes in the expected return on plan assets would not have an effect on the total pension liability.

The Company also has a SERP that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to 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. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.6 million, $1.8 million and $0.3 million related to the SERP in 2005, 2004 and 2003, respectively. This resulted in a charge to other comprehensive income of $0.4 million, $1.2 million and $0.2 million, net of tax, for 2005, 2004 and 2003, respectively.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2005 by $1.4 million and the service and interest cost by $0.1 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2005 by $1.2 million and the service and interest cost by $0.1 million.

Contingencies

The Company has unresolved regulatory, legal and tax issues for which there is inherent uncertainty with respect to the ultimate outcome of the respective matter. The Company accounts 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, a loss contingency is accrued if it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if it there is a reasonable possibility that a loss may be incurred.

For all material contingencies, the Company has made a judgment as to the probability of the loss occurring and as to whether or not the amount of the loss can be estimated, and, if the loss recognition criteria have been met, liabilities have been accrued or assets have been written down. However, no assurance can be given with respect to the ultimate outcome of any particular contingency.

 

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Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During 2005, positive cash flows from operating activities of $128.5 million, proceeds from property sales (primarily the sale of the Company’s South Lake Tahoe natural gas properties) of $17.2 million and an overall reduction in the Company’s consolidated cash position of $62.4 million were used to fund the majority of the Company’s cash requirements, including utility capital expenditures of $213.7 million and dividends of $26.4 million. To fund the portion of cash needs not met through other sources, total debt increased $37.5 million in 2005. In addition to dividends, the most significant financing transactions in 2005 were long-term debt issuances of $149.6 million and $111.6 million of debt redemptions and maturities. The overall decrease in cash of $62.4 million in 2005 primarily reflects a decrease in cash at Avista Energy primarily due to an increase of $28.7 million in cash deposited with counterparties as collateral funds, as well as Avista Energy’s net loss for the year.

Operating Activities Net cash provided by operating activities was $128.5 million for 2005 compared to $118.0 million for 2004. Net cash used in working capital components was $57.5 million for 2005, compared to net cash used of $79.9 million for 2004. The net cash used during 2005 primarily reflects an increase in accounts receivable and cash deposits with counterparties (representing cash deposited as collateral funds at Avista Energy), partially offset by a net increase in the balance outstanding under the Company’s revolving accounts receivable sales facility, and an increase in accounts payable. The $28.7 million increase in deposits with counterparties was due to high natural gas prices and the posting of cash collateral for margin requirements in addition to letters of credit issued under Avista Energy’s credit line. The significant increase in accounts receivable and accounts payable was primarily due to an increase in energy commodity prices, as well as increased natural gas wholesale sales and purchases at Avista Utilities. The net cash used in 2004 primarily reflects a decrease in deposits from counterparties (representing collateral funds returned), which substituted cash collateral with letters of credit. This was partially offset by an increase in accounts payable. Significant changes in non-cash items included a $37.4 million change in energy commodity assets and liabilities, representing the change to an unrealized loss of $38.1 million on energy trading activities for Avista Energy for 2005 from an unrealized loss of $0.7 million for 2004.

Investing Activities Net cash used in investing activities was $197.6 million for 2005, an increase compared to $129.1 million for 2004. Avista Corp. increased utility capital expenditures in order to meet load growth needs and to continue to provide reliable service to its customers. Utility capital expenditures totaled $213.7 million, the most significant of which were the acquisition of the remaining interest in Coyote Springs 2, transmission system enhancements, and the repurchase of the Company’s corporate headquarters and central operating facility in Spokane. During 2005, the Company received $17.2 million from the sale of properties (primarily the sale of its South Lake Tahoe natural gas properties).

Financing Activities Net cash provided by financing activities was $6.6 million for 2005 compared to net cash used of $28.7 million for 2004. During 2005, short-term borrowings decreased $5.0 million, which reflects a decrease in the amount of debt outstanding under Avista Corp.’s line of credit. In the fourth quarter of 2005, the Company issued $150.0 million (net proceeds of $149.6 million) of 6.25 percent First Mortgage Bonds due in 2035. During 2005, Avista Corp. redeemed a total of $26.0 million of medium-term notes scheduled to mature in future years, repaid $54.6 million of WP Funding LP debt and $31.0 million of long-term debt matured. Cash dividends paid increased to $26.4 million (or 54.5 cents per share) for 2005 from $24.9 million (or 51.5 cents per share) for 2004.

During 2004, short-term borrowings decreased $12.0 million, which primarily reflected a decrease in the amount of debt outstanding under Avista Corp.’s line of credit. During 2004, the Company repurchased $36.6 million of long-term debt scheduled to mature in future years at a total premium of $6.7 million, and $30.3 million of debt matured. In November 2004, the Company issued $90.0 million (net proceeds of $89.8 million) of 5.45 percent First Mortgage Bonds due in 2019. During 2004, the Company had $61.9 million of cash inflows and outflows related to the issuance and redemption of long-term debt to affiliated trusts. In 2004, Avista Capital purchased the preferred stock of Avista Advantage at a total price of $4.3 million (including a premium of $0.9 million).

Overall Liquidity

The Company’s consolidated operating cash flows are primarily derived from the operations of Avista Utilities and Avista Energy. The primary source of operating cash flows for Avista Utilities is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash

 

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flows from operations for Avista Utilities include the purchase of electricity and natural gas, other operating expenses, taxes and interest. The primary source and use of operating cash flows for Avista Energy is revenues and costs from realized energy commodity transactions as well as cash collateral deposited to or held from counterparties. Significant operating cash outflows for Avista Energy also include other operating expenses and taxes.

Operating cash flows do not always fully support the capital expenditure needs of Avista Utilities. As such, from time to time, the Company may need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

The Company designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, the Company has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities. In 2001, the Company incurred substantial levels of indebtedness, both short and long-term, to fund high power and natural gas costs in addition to these continuing requirements and to otherwise maintain adequate levels of working capital. As a result of improved operating cash flow and other sources of funds, since 2002 through 2005, the Company has repurchased $318.7 million of long-term debt.

The general rate increases that have been implemented at Avista Utilities since 2002 are allowing the Company to continue to improve its liquidity. In December 2005, the WUTC approved a settlement agreement (with certain conditions) related to Avista Utilities’ Washington general rate case that provides for electric and natural gas base rate increases, which are designed to increase annual revenues by $22.4 million effective January 1, 2006. See further details in the section “Avista Utilities - Regulatory Matters.”

When Avista Utilities’ power and natural gas costs exceed the levels currently recovered from retail customers, its net cash flows are negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase power in the wholesale markets. Factors beyond the Company’s 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, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts. Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Including 2005, hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year.

The Company monitors on an ongoing basis the potential liquidity impacts of increasing energy commodity prices, particularly with respect to natural gas, for both Avista Utilities and Avista Energy. The Company believes that it has adequate liquidity through current cash and cash equivalents, Avista Corp.’s $350.0 million committed line of credit and Avista Energy’s $145.0 million committed line of credit to meet the increased cash needs of higher energy commodity prices. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of its power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect the Company’s cash flow and liquidity.

Capital Resources

The Company’s consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of December 31 (dollars in thousands):

 

     2005     2004  
     Amount   

Percent

of total

    Amount   

Percent

of total

 

Current portion of long-term debt

   $ 39,524    2.0 %   $ 85,432    4.4 %

Short-term borrowings

     63,494    3.2       68,517    3.5  

Long-term debt to affiliated trusts

     113,403    5.6       113,403    5.8  

Long-term debt

     989,990    49.4       901,556    46.2  
                          

Total debt

     1,206,411    60.2       1,168,908    59.9  

Preferred stock-cumulative (including current portion)

     28,000    1.4       29,750    1.5  
                          

Total liabilities

     1,234,411    61.6       1,198,658    61.4  

Stockholders’ equity

     771,128    38.4       753,205    38.6  
                          

Total

   $ 2,005,539    100.0 %   $ 1,951,863    100.0 %
                          

 

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The Company’s total debt increased $37.5 million from December 31, 2004 to December 31, 2005 due to the issuance of $150.0 million of long-term debt, partially offset by the redemption and maturity of long-term debt and a decrease in short-term borrowings. The increase in total debt was primarily to fund utility capital expenditures that were in excess of operating cash flows. The Company needs to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund working capital, purchased power and natural gas costs, capital expenditures, dividends and other corporate requirements. The Company’s stockholders’ equity increased $17.9 million during 2005 primarily due to net income, partially offset by dividends and other comprehensive loss.

The Company generally funds 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 utility operating activities and cash generated by Avista Energy are expected to be the Company’s primary sources of funds for operating needs, dividends and capital expenditures for 2006. Borrowings under Avista Corp.’s committed line of credit may supplement these funds to the extent necessary and Avista Corp. currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007.

During the fourth quarter of 2005, the Company issued $150.0 million of 6.25 percent First Mortgage Bonds due in 2035. The proceeds from the issuance were used to repay a portion of the borrowings outstanding under the Company’s $350.0 million committed line of credit and for the payment of corporate obligations.

On December 17, 2004, the Company entered into a committed line of credit with various banks in the amount of $350.0 million with an expiration date of December 16, 2009. This committed line of credit replaced a $350.0 million committed line of credit with a 364-day term that had an expiration date of May 5, 2005. The Company can request the issuance of up to $150.0 million in letters of credit under the committed line of credit. As of December 31, 2005 and 2004, the Company had $63.0 million and $68.0 million, respectively, of borrowings outstanding. As of December 31, 2005 and 2004, there were $44.1 million and $32.8 million in letters of credit outstanding, respectively. The committed line of credit is secured by $350.0 million of non-transferable First Mortgage Bonds of the Company 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 the Company defaults on its obligations under the committed line of credit. However, if the Company obtains an investment grade senior unsecured rating with a stable outlook from two nationally recognized rating agencies, it has the option to release such security.

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at the end of any fiscal quarter. As of December 31, 2005, the Company was in compliance with this covenant with a ratio of 60.2 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending December 31, 2005 to be greater than 1.6 to 1. As of December 31, 2005, the Company was in compliance with this covenant with a ratio of 2.46 to 1.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of its significant subsidiaries (including Avista Energy) 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, and could induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for the Company to obtain financing on reasonable terms to pay creditors or fund operations, and the Company would likely be prohibited from paying dividends on its common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2005, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

The Company is restricted under various agreements and its Restated Articles of Incorporation as to the additional preferred stock it can issue. As of December 31, 2005, approximately $398.3 million of additional preferred stock could be issued at an assumed dividend rate of 6.95 percent with a maturity date later than June 1, 2008.

The Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds (including Secured Medium-Term Notes) contains limitations on the amount of First Mortgage Bonds that may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds, and a 2 to 1 net earnings to First Mortgage Bond interest ratio. As of December 31, 2005, the Company could issue $285.5 million of additional First Mortgage Bonds under the Mortgage and Deed of Trust.

 

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In April 2004, the Company filed an amended registration statement on Form S-3 with the Securities and Exchange Commission, which would allow for the issuance of up to $349.6 million of securities (either debt or common stock). This filing amended and combined three previous registration statements filed by the Company. As of December 31, 2005, the Company had remaining availability of $109.6 million under this registration statement.

As further discussed at “Avista Utilities - Regulatory Matters,” in December 2005, the WUTC issued an order approving the settlement agreement reached in the Company’s Washington general rate case with certain conditions. The Company agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. Failure by the Company to meet those targets could result in a reduction in base rates of 2 percent for each target. The utility equity component was approximately 31 percent as of December 31, 2005.

Beyond expected earnings, the Company is evaluating additional ways to increase its utility equity ratio. Such measures could include delivering original issue shares under the Company’s equity compensation and dividend reinvestment plans, as well as possibly making small common stock issuances, from time to time through underwriters or agents. Regulators in each of the Company’s jurisdictions have approved the issuance of up to 2 million shares of common stock, from time to time, over the next two years (not including shares under equity compensation and dividend reinvestment plans, which have been previously approved by regulators).

Inter-Company Debt; Subordination

As part of its on-going cash management practices and operations, Avista Corp. from time to time makes unsecured short-term loans to, and obtains borrowings from, Avista Capital. In turn, Avista Capital from time to time makes unsecured short-term loans to, and obtains borrowings from, its subsidiaries. As of December 31, 2005, Avista Corp. held a short-term subordinated note receivable from Avista Capital in the principal amount of $39.3 million. In addition, Avista Capital from time to time guarantees the indebtedness and other obligations of its subsidiaries. See “Energy Marketing and Resource Management Operations” for further information. The credit arrangements of Avista Capital’s subsidiaries generally provide that any indebtedness owed by such entity to its corporate parent will be subordinated to the indebtedness outstanding under such credit arrangements.

The right of Avista Corp., as a shareholder, to receive assets of any of its direct or indirect subsidiaries upon the subsidiary’s liquidation or reorganization (and the consequent right of the holders of debt securities and other creditors of Avista Corp. to participate in those assets) is subordinated to the claims against such assets of that subsidiary’s creditors. As a result, the obligations of Avista Corp. to its debt securityholders and other unrelated creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments (including trade payables and lease obligations) of Avista Corp.’s direct and indirect subsidiaries. Similarly, the obligations of Avista Capital to its creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments of its direct and indirect subsidiaries.

Pension Plan

As of December 31, 2005, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. The Company does not expect the current pension plan funding deficit to have a material adverse effect on its financial condition, results of operations or cash flows. The Company believes that it has made significant efforts in addressing the pension plan funding deficit since 2002, primarily through cash contributions to the plan in excess of the amounts that are required to be funded under the Employee Retirement Income Security Act. The Company made $15 million in cash contributions to the pension plan in each of 2005 and 2004, which brings total pension plan contributions to $54 million from 2002 through 2005. The Company expects to contribute $15 million to the pension plan in 2006.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those 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. On a consolidated basis, the amount of such fees is included in operating expenses of Avista Corp. As of December 31, 2005, $85.0 million in accounts receivables were sold under this revolving agreement. This agreement provides the Company with cost-effective funds for working capital requirements, capital expenditures and other general corporate needs. The Company expects to renew this facility before the March 21, 2006 expiration.

 

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Spokane Energy, LLC

In December 1998, the Company received cash proceeds of $143.4 million from a transaction in which the Company 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 IPUC, this amount was fully amortized by the end of 2002.

Under this power exchange arrangement, Peaker, LLC (Peaker) purchases capacity from Avista Corp. and sells capacity to Spokane Energy LLC (Spokane Energy), an unconsolidated subsidiary of Avista Corp., 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 $106.5 million as of December 31, 2005) that matures in January 2015 with no recourse to Avista Corp. related to the loan. Peaker is obligated to pay approximately $150,000 per month to Avista Corp. for its capacity purchase. Peaker was formed solely for the purpose of assuming all rights and obligations from Enron Power Marketing, Inc. (EPMI), which assigned the transactions to Peaker in November 2003 as part of its bankruptcy proceedings. Peaker is not affiliated with EPMI.

WP Funding LP

WP Funding LP was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31, 2003 through June 30, 2005. WP Funding LP purchased the Rathdrum CT from Avista Corp. with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. Avista Corp. operated the Rathdrum CT and leased it from WP Funding LP until September 2005. In September 2005, Avista Corp. terminated (by exercise of a purchase option) the lease agreement with, and acquired the Rathdrum CT from, WP Funding LP. As a result of this transaction, Avista Corp. is no longer including WP Funding LP in its consolidated financial statements. This transaction and deconsolidation did not have a material effect on the Company’s total consolidated assets, liabilities, stockholders’ equity or results of operations. From a consolidated perspective, the Company replaced the $56.3 million of WP Funding LP debt and third-party investment with other borrowings by Avista Corp.

Credit Ratings

The following table summarizes the Company’s credit ratings as of March 1, 2006:

 

    

Standard & Poor’s

   Moody’s    Fitch, Inc.

Avista Corporation

        

Corporate/Issuer rating

   BB+    Ba1    BB+

Senior secured debt

   BBB-    Baa3    BBB-

Senior unsecured debt

   BB+    Ba1    BB+

Preferred stock

   BB-    Ba3    BB

Avista Capital II (1)

        

Preferred Trust Securities

   BB-    Ba2    BB

AVA Capital Trust III (1)

        

Preferred Trust Securities

   BB-    Ba2    BB

Rating outlook

   Stable    Stable    Stable

 

(1) Only assets are subordinated debentures of Avista Corporation.

These 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.

Dividends

The Board of Directors considers the level of dividends on the Company’s common stock on a regular basis, taking into account numerous factors including, without limitation, the Company’s results of operations, cash flows and financial condition, as well as the success of the Company’s strategies and general economic and competitive conditions. The Company’s net income available for dividends is derived primarily from the operations of Avista Utilities and Avista Energy.

 

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Covenants under the Company’s 9.75 percent Senior Notes that mature in 2008 limit the Company’s ability to increase its common stock cash dividend to no more than 5 percent over the previous quarter.

On November 11, 2005, the Board of Directors declared a quarterly dividend of $0.14 per common share payable on December 15, 2005 to shareholders of record on November 30, 2005. This was an increase of $0.005 per common share over the previous quarterly dividend declared in August 2005. On February 10, 2006, the Board of Directors declared a quarterly dividend of $0.14 per common share payable on March 15, 2006 to shareholders of record on February 24, 2006.

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheets. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. During 2005, Avista Energy paid $15.1 million in dividends to Avista Capital.

Avista Utilities Operations

Capital expenditures for Avista Utilities were $431.3 million for the years 2003 through 2005. During the years 2006 through 2008, utility capital expenditures are currently expected to be in the range of $160 million to $175 million per year. In addition to continuing needs for Avista Utilities’ distribution system, significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Long-term debt maturities and mandatory redemptions of preferred stock are expected to total approximately $567 million during the period from 2006 through 2008. During 2006, internally generated funds and short-term borrowing arrangements are expected to be sufficient to fund these requirements. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007. In 2007 and 2008, the Company will most likely need to issue additional long-term debt to fund these obligations, which include long-term debt maturities of approximately $500 million. The Company has already locked in the interest rate on $200 million of long-term debt issuances during this period through forward-starting interest rate swap agreements.

Avista Utilities is committed to investment in its generation, transmission and distribution systems with a focus on increasing capacity and improving reliability. Avista Utilities continues to upgrade its hydroelectric plants to increase their availability and capture additional output. Currently, plans call for upgrading one unit each year for the next five years. As outlined in Avista Utilities’ 2005 Electric Integrated Resource Plan, which was filed with regulators in Washington and Idaho, quarterly energy deficits are projected to begin in 2007 and annual energy deficits are projected to begin in 2010. To help meet forecasted increases in electric loads, Avista Utilities issued a request for proposals in January 2006 to consider adding approximately 35 average megawatts of long-term renewable energy supplies to begin in the fourth quarter of 2007. In early 2006, Avista Utilities has also entered into an agreement with Idaho Power to jointly investigate possible future coal-based generation resources.

As of December 31, 2005, Avista Utilities had $3.8 million of restricted cash. The restricted cash relates to deposits for Avista Corp.’s interest rate swap agreements.

Avista Utilities held cash deposits from other parties in the amount of $9.0 million as of December 31, 2005, which is included in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

See “Notes 5, 15, 16, 17, 18, 21, 22 and 23 of Notes to Consolidated Financial Statements” for additional details related to financing activities.

Energy Marketing and Resource Management Operations

On July 13, 2005, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks to increase the aggregate amount from $110.0 million to $145.0 million and to extend the expiration date to July 12, 2007. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties and for cash advances. This facility is secured by the assets of Avista Energy and Avista Energy Canada and guaranteed by Avista Capital and by CoPac Management, Inc., a wholly owned subsidiary of Avista Energy Canada. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The amendment to the credit agreement increased the maximum amount for cash advances from $30.0 million to

 

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$50.0 million. No cash advances were outstanding as of December 31, 2005 and 2004. Letters of credit in the aggregate amount of $125.3 million and $91.3 million were outstanding as of December 31, 2005 and 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $18.2 million and $21.5 million of these letters of credit as of December 31, 2005 and 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets. The increase in letters of credit outstanding is partially due to an increase in commodity prices, particularly with respect to natural gas.

The Avista Energy credit agreement continues to contain covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth,” as well as a covenant limiting the amount of indebtedness that the co-borrowers may incur. The credit agreement also continues to contain covenants and other restrictions related to the co-borrowers’ trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. These covenants, certain counterparty agreements and market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. Avista Energy was in compliance with the covenants of its credit agreement as of December 31, 2005. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

Avista Capital provides guarantees for Avista Energy’s credit agreement (see discussion above) and, in the course of business, may provide performance guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the performance guarantee, which was $37.7 million as of December 31, 2005. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $419.3 million as of December 31, 2005.

As part of its cash management practices and operations, Avista Energy from time to time makes unsecured short-term loans to its parent, Avista Capital. Avista Capital’s Board of Directors has limited the total outstanding indebtedness to no more than $45.0 million. Further, as required under Avista Energy’s credit facility, such loans cannot be outstanding longer than 90 days without being repaid. During 2005, Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $40.2 million including accrued interest. As of December 31, 2005, all outstanding loans including accrued interest had been repaid.

Avista Energy manages collateral requirements with counterparties by providing letters of credit, providing guarantees from Avista Capital, depositing cash with counterparties and offsetting transactions with counterparties. Cash deposited with counterparties totaled $59.4 million as of December 31, 2005, an increase of $28.7 million from December 31, 2004 due to high natural gas prices and the posting of cash collateral for margin requirements in addition to letters of credit issued under Avista Energy’s credit line. Avista Energy held cash deposits from other parties in the amount of $4.8 million as of December 31, 2005, which is included in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

As of December 31, 2005, Avista Energy had $22.9 million in cash, as well as $21.8 million of restricted cash. Avista Energy’s total cash (not including restricted cash) decreased $61.8 million during 2005 primarily due to an increase in cash deposited with counterparties as collateral funds of $28.7 million, dividends to Avista Capital of $15.1 million, which flowed up to Avista Corp. and were used for general corporate purposes, as well as Avista Energy’s net loss for the year.

Capital expenditures for the Energy Marketing and Resource Management companies were $5.0 million for the years 2003 through 2005. Capital expenditures for this segment are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition during the years 2006 through 2008.

Avista Advantage Operations

Capital expenditures for Avista Advantage were $2.4 million for the years 2003 through 2005. Capital expenditures for the years 2006 through 2008 are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition and should be funded by Avista Advantage’s cash flows from operations.

As of December 31, 2005, Avista Advantage had $1.4 million of debt outstanding related to capital leases.

 

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Other Operations

Capital expenditures for these companies were $3.1 million for the years 2003 through 2005. Capital expenditures for the years 2006 through 2008 in this segment are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition.

As of December 31, 2005, this business segment had $7.6 million of debt outstanding which included long-term debt, short-term borrowings and capital leases.

Contractual Obligations

The following table provides a summary of the Company’s future contractual obligations as of December 31, 2005 (dollars in millions):

 

     2006    2007    2008    2009    2010    Thereafter

Avista Utilities:

                 

Long-term debt maturities (1)

   $ 38    $ 176    $ 325    $ —      $ 35    $ 441

Long-term debt to affiliated trusts (1)

     —        —        —        —        —        113

Interest on debt (2)

     95      89      81      77      75      —  

Short-term borrowings (3)

     63      —        —        —        —        —  

Accounts receivable sales (4)

     85      —        —        —        —        —  

Preferred stock redemptions (1)

     2      26      —        —        —        —  

Energy purchase contracts (5)

     364      162      148      144      144      727

Public Utility District contracts (5)

     4      4      4      4      4      64

Operating lease obligations (6)

     2      1      1      1      —        2

Capital lease obligations (6)

     1      1      1      —        —        —  

Other obligations (7)

     14      14      14      14      14      195

Information services contracts

     11      11      12      12      12      26

Pension plan funding (9)

     15      15      15      15      —        —  

Avista Capital (consolidated):

                 

Long-term debt

     —        —        —        —        —        7

Short-term borrowings

     1      —        —        —        —        —  

Energy purchase contracts (8)

     1,010      232      226      205      196      347

Operating lease obligations (6)

     3      3      3      3      1      —  

Capital lease obligations (6)

     1      1      —        —        —        —  
                                         

Total contractual obligations

   $ 1,709    $ 735    $ 830    $ 475    $ 481    $ 1,922
                                         

 

(1) For 2006, the Company expects that cash flows from operations and short-term debt will provide sufficient funds for maturing long-term debt and preferred stock redemptions. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007. In years subsequent to 2006, the Company will most likely need to issue additional long-term debt to fund these obligations.

 

(2) Represents the Company’s estimate of interest payments on debt. The Company will make interest payments beyond 2010; however, the Company has not made an estimate of such payments at this time.

 

(3) Represents $63 million outstanding under a $350 million revolving line of credit.

 

(4) Represents $85 million outstanding under a revolving $85 million accounts receivable sales financing facility.

 

(5) Energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail natural gas and electric customers’ energy requirements. As a result, these 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.

 

(6) Includes the interest component of the lease obligation.

 

(7) 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.

 

(8) Represents Avista Energy’s contractual commitments to purchase energy commodities as well as commitments related to transmission, transportation and other energy-related contracts in future periods. Avista Energy also has sales commitments related to these contractual obligations in future periods.

 

(9) Represents the Company’s estimated cash contributions to the pension plan through 2009. The Company cannot reasonably estimate pension plan contributions beyond 2009 at this time.

 

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

As of December 31, 2005, Avista Corp. did not have any commitments outstanding with equity triggers. Avista Corp. does not expect any material impact from rating triggers; although there are certain rating triggers for Avista Corp. primarily related to changes in pricing under certain financing agreements. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

Competition

Avista Utilities’ retail electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, 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 and are designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return. Avista Utilities competes with various rural electric cooperatives and public utility districts in and adjacent to its service territories in the provision of service to new retail electric customers. Alternate providers of power may also compete for sales to existing customers. Competition for available electric resources can be critical to utilities as surplus power resources are absorbed by load growth. Avista Utilities’ electric and natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

The Energy Policy Act of 1992 (1992 Energy Act) removed certain barriers to a competitive wholesale market. The 1992 Energy Act expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers.

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. Avista Corp. actively monitors and participates as appropriate in energy industry developments to maintain and enhance its ability to effectively participate in wholesale energy markets consistent with its business goals.

The subsidiaries in the non-energy businesses, particularly Avista Advantage, are subject to competition as they develop products and services and enter new markets. It is also a challenge for Avista Advantage to maintain its current customer base. Competition from other companies in these non-energy businesses may mean challenges for a company to be the first to market a new product or service to gain the advantage in market share. Challenges for these businesses include the availability of funding and resources to meet capital needs, rapidly advancing technologies, possibly making some of the current technology quickly obsolete, and requiring continual product enhancement.

Business Risk

The Company’s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural gas, regulatory allowance of the recovery of power and natural gas costs, operating costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Avista Utilities has mechanisms in each regulatory jurisdiction, which provide for the recovery of the majority of the changes in its power and natural gas costs. The majority of power and natural gas costs that exceed the amount currently recovered through retail rates, excluding the ERM dead band in Washington, are deferred on the 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.

 

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Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Including 2005, hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year. The earnings impact of these factors is mitigated by regulatory mechanisms that are intended to defer increased power supply costs for recovery in future periods. Avista Utilities is 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 these costs in future periods. See further information at “Avista Utilities - Regulatory Matters.”

Challenges facing Avista Utilities’ electric operations include, among other things, streamflows to hydroelectric generating facilities, weather conditions, changes in the availability of and volatility in the prices of power and fuel, the timing and approval of the recovery of deferred power costs, generating unit availability, legislative and governmental regulations, potential tax law changes, and customer response to price increases and surcharges.

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $8.13, $6.62 and $5.50 in 2005, 2004 and 2003, respectively. The Company continues to be concerned about the impact that increasing rates have on its customers, which could reduce future demand for natural gas. However, market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. The Company continues to discuss its natural gas purchase and hedging strategies with its regulators. Avista Utilities believes that natural gas should sustain its market advantage over competing energy sources based on the levels of existing reserves and the potential for 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, as well as conversions from competing space and water heating energy sources to natural gas.

Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, increases in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing and approval of recovery for increased natural gas costs. Avista Utilities’ natural gas business also faces the potential for certain natural gas customers to by-pass its natural gas system. To reduce the potential for such by-pass, Avista Utilities prices its natural gas services, including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of individual contracts, subject to state regulatory review and approval. Avista Utilities has long-term transportation contracts with several of its largest industrial customers, which reduces the risk of these customers by-passing the system in the foreseeable future.

In addition to its asset management activities, Avista Energy trades electricity and natural gas, along with derivative commodity instruments, including futures, options, swaps and other contractual arrangements. As a result of these trading activities, Avista Energy is subject to various risks including commodity price risk and credit risk, as well as possible risks resulting from the imposition of market controls by federal and state agencies. The FERC is conducting proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds. As a result, certain parties have asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities, which could result in liabilities for refunding revenues recognized in prior periods. Avista Energy and Avista Utilities have joined other parties in opposing these proposals. The refund proceedings provide that any refunds owed could be offset against unpaid energy debts due to the same party. As of December 31, 2005, Avista Energy’s accounts receivable outstanding related to defaulting parties in California are fully offset by reserves for uncollected amounts and funds collected from defaulting parties. Avista Energy is pursuing recovery of the defaulted obligations. 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.

Avista Utilities and Avista Energy 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. Both Avista Utilities and Avista Energy are subject to energy commodity price risk. Price risk is, in general, the risk of 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 retail loads. In the case of electricity, prices can be affected by the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, availability of streamflows for hydroelectric generation on a regional basis, the price and availability of fuel for thermal generating plants, and disruptions of or constraints on transmission facilities, among other things. Natural gas prices are affected by a

 

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number of factors, including but not limited to, the adequacy of North American production, the level of imports, the level of inventories, the demand for natural gas as fuel for electric generation, global energy markets, and the availability of pipeline capacity to transport natural gas from region to region. In addition, oil prices can influence natural gas and electricity prices, because of the fuel-switching capabilities of certain energy users. Demand changes caused by variations in the weather and other factors can also affect market prices for electricity and natural gas. 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. The FERC imposed a price mitigation plan in the western United States in June 2001 and has subsequently modified various price and market control regulations.

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 the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. Avista Utilities and Avista Energy often extend credit to counterparties and customers and are exposed to the risk that they may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits have been established. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it and the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, Avista Utilities or Avista Energy may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These 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, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty. However, despite mitigation efforts, defaults by counterparties periodically occur.

Avista Energy and Avista Utilities regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. Avista Energy and Avista Utilities have taken a conservative position by reducing or eliminating open (unsecured) credit limits and implemented other credit risk reduction measures for parties perceived to have increased default risk. Counterparty collateral is used to offset the Company’s credit risk where unsettled net positions and future obligations by counterparties to pay Avista Utilities and/or Avista Energy or deliver to Avista Utilities and/or Avista Energy warrant.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including, but not limited to, electric utilities, natural gas distribution companies, and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location, as Avista Energy operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may affect Avista Energy’s overall exposure to credit risk because the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Credit risk also involves the exposure that counterparties perceive related to the ability of Avista Utilities and Avista Energy 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, and, in the case of Avista Energy, parent company (Avista Capital) performance guarantees. In periods of price volatility, the level of exposure can change significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash). Avista Utilities and Avista Energy actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

In conjunction with the valuation of their commodity derivative instruments and accounts receivable, Avista Utilities and Avista Energy maintain credit reserves that are based on management’s evaluation of the credit risk of the overall portfolio. Based on these policies, exposures and credit reserves, the Company does not anticipate a materially adverse effect on its financial condition or results of operations as a result of counterparty nonperformance.

 

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Other Operating Risks. In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases or decreases in load demand, blackouts or disruptions to transmission or transportation systems, fuel quality, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service. Terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including Avista Utilities. Potential disruptions to operations or destruction of facilities from terrorism or other malicious acts are not readily determinable. The Company has taken various steps to mitigate terrorism risks and to prepare contingency plans in the event that its facilities are targeted.

Interest Rate Risk. The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company manages 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. Additionally, amounts borrowed under the Company’s $350.0 million committed line of credit have a variable interest rate.

In 2004, Avista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 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 to fund maturing debt in 2007 and 2008. Under the terms of these agreements, the value of the interest rate swaps are determined based upon Avista Corp. 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 in accordance with SFAS No. 133. As of December 31, 2005, Avista Corp. had a derivative liability of $10.0 million and provided cash collateral of $3.8 million to the interest rate swap counterparties related to these interest rate swaps. The Company estimates that a 10 basis point increase in forward LIBOR interest rates as of December 31, 2005 would have decreased this derivative liability by approximately $1.3 million, while a 10 basis point decrease would have increased the liability by approximately $1.3 million.

Foreign Currency Risk. Avista Energy has investments in Canadian companies through Avista Energy Canada and its subsidiary, CoPac Management, Inc. In addition, Avista Energy enters into Canadian dollar denominated transactions in Canada for natural gas commodity and related services. These transactions in aggregate expose Avista Energy to foreign currency risk. Avista Energy attempts to limit its exposure to changing foreign exchange rates through both operational and financial market actions. This includes entering into forward and swap contracts to hedge existing exposures, firm commitments and anticipated transactions. These arrangements are carried at fair value and were not significant as of December 31, 2005. Also, Avista Utilities has foreign currency risk as natural gas procurement operations have been implemented in 2005 and a significant portion of Avista Utilities’ natural gas supply is obtained from Canadian sources. This has not had a material effect on Avista Utilities’ financial condition, results of operations or cash flows.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for Avista Utilities and Avista Energy. The Company’s Risk Management Committee establishes the Company’s risk management policies and procedures and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is overseen by the Audit Committee of the Company’s Board of Directors. The Company’s Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with the Company’s risk management policies and procedures on a regular basis. 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.

Avista Utilities and Avista Energy 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 the Company’s liquidity as other parties may place credit limits or require cash collateral.

Quantitative Risk Measurements. Avista Utilities measures the monthly, quarterly and annual energy volume of its imbalance between projected power loads and resources. Normal operations result in seasonal mismatches between power loads and available resources. Avista Utilities is able to vary the operation of its generating resources to match

 

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parts of its hourly, daily and weekly load fluctuations. Avista Utilities uses the wholesale power markets to sell projected resource surpluses and obtain resources when deficits are projected. Avista Utilities buys and sells fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating its available generating facilities.

Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions 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 Avista Utilities’ desired transaction size and shape. Therefore, open imbalance positions exist at any given