8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): May 23, 2006

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

Washington	1-3701	91-0462470
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

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

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

Web site: http://www.avistacorp.com

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

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

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

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

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

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

Section 7 – Regulation FD Disclosure

Item 7.01 Regulation FD Disclosure.

The information in this report shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.

On May 24, 2006, management of Avista Corporation (Avista Corp. or the Company) will be participating in meetings with investors and will provide a business update presentation at the 2006 Edison Electric Institute Annual Finance Committee Meeting. A copy of the business update presentation is furnished as Exhibit 99.1.

Section 9 – Financial Statements and Exhibits

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

99.1     Business update presentation dated May 2006, which is being furnished pursuant to Item 7.01.

Neither the furnishing of any presentation as an exhibit to this Current Report nor the inclusion in such presentation of a reference to Avista Corp.’s Internet address shall, under any circumstances, be deemed to incorporate the information available at such Internet address into this Current Report. The information available at Avista Corp.’s Internet address is not part of this Current Report or any other report furnished or filed by Avista Corp. with the Securities and Exchange Commission.

SIGNATURES

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

	AVISTA CORPORATION (Registrant)
Date: May 23, 2006	/s/ Malyn K. Malquist
	Malyn K. Malquist Executive Vice President and Chief Financial Officer

EX-99.1

1

We answer to you.

Business Update

EEI, New York City

May 2006

NYSE: AVA

www.avistacorp.com

Exhibit 99.1

2

We answer to you.

Corporate Summary

Regulated

Non-regulated

Energy company involved in the production,

transmission and distribution of energy as well as

other energy-related businesses

Incorporated in 1889 and headquartered in

Spokane, Washington

Avista Utilities is a company operating division

comprising the regulated utility operations that

provides electric and natural gas service to

customers in Washington, Idaho and Oregon

Avista Advantage is a business process outsourcer

that provides facilities resource management

Avista Energy provides electricity, natural gas and

hydroelectric portfolio optimization and

management, as well as risk management services

3

We answer to you.

Avista Utilities

4

We answer to you.

Electric and Natural Gas Service Areas

5

We answer to you.

Q1 2006 Results

1,885 new electric customers

2,091 new natural gas customers

Extended service to:

589 electric development lots

6,012 in planning stage

1,118 gas development lots

5,291 in planning stage

Customer Growth

Forecasted growth for the next four years:

2.5% for electric customers

4.0% for natural gas customers

0

3,000

6,000

9,000

12,000

15,000

18,000

21,000

2002

2003

2004

2005

Q1 2006

Electric

Gas

6

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Integrated Resource Plan (IRP)

Acquiring additional transmission is critical to the Company’s plans

Over half of future energy needs are met with renewables, plant upgrades and conservation

Energy and capacity deficits begin in 2010 and 2009, respectively

Avista’s 2005 IRP calls for acquisition of 69 MW of conservation, 400 MW of wind, 80 MW of other

renewable resources, 52 MW of hydroelectric efficiency upgrades and 250 MW of coal-based generation

over a period of ten years

2006 Resource Mix

Other

Renewables 2%

Hydro Upgrades

1%

Contract 8%

Coal 11%

Hydro 52%

Gas 26%

2016 Resource Mix

Wind 4%

DSM 3%

Other

Renewables 5%

Hydro Upgrades

2%

Contract 3%

Coal 19%

Hydro 42%

Gas 22%

7

We answer to you.

2006 Utility Capital Expenditures

Total

Utility

capital

expenditures

results

in

an

additional

$80

million

to

net

rate

base

230 kV

Upgrades $29

Other $7

IS/IT & Security

$10

Gas $11

Environmental

$10

Growth $40

Electric

Transmission &

Distribution $26

Generation $27

$160 Million Total CapEx

*

* Excludes Automated Meter Reading

8

We answer to you.

Transmission System Upgrades

19

of

30

projects

fully

commissioned

(63%)

50

of

115

miles

of

230

kV

line

constructed

4

of

6

–

230

kV

substations

energized

90

of

200

miles

of

F/O

cable

installed

Total project cost is approximately $120 million through 2007

230 kV Construction Schedule and Cost Trend

Palouse 230 Line

Lolo Substation

Beacon-Bell 230 Lines

$29,200

2006

$20,835

2007

Benewah Substation

Fiber Optic and C. Fork RAS

$21,926

2004

$27,104

2005

$21,041

230 kV Upgrade Total CapX

Boulder Sub & 230 Lines

Dry Creek Sub & 230 Lines

Beacon-Rathdrum Line

2003

Palouse 230 Line

Lolo Substation

Beacon-Bell 230 Lines

$29,200

2006

$20,835

2007

Benewah Substation

Fiber Optic and C. Fork RAS

$21,926

2004

$27,104

2005

$21,041

230 kV Upgrade Total CapX

Boulder Sub & 230 Lines

Dry Creek Sub & 230 Lines

Beacon-Rathdrum Line

2003

($ thousands)

9

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Hydro Upgrades

Noxon

Rapids Runner Upgrade

Noxon

Rapids is Avista’s largest hydro project

Upgrade Units 1-4 to improve efficiency, reliability and

eliminate operating restrictions

Replace turbine runners on Units 1-4

Requires $31.4 million of capital over the

next seven years

Requires $1.4 million for maintenance over

the same period

Noxon

Rapids capacity improvements

Maximum capacity is 554 MW; currently

at 532 MW due to operating restrictions

Upgrade expected to restore maximum capacity, improve

unit availability and add an additional

16 MW

Total plant increased to 570 MW

Noxon

Rapids Dam

10

We answer to you.

Advanced Meter Reading (AMR)

Oregon

93,000 gas meters installed

Oregon granted a 35% Business Tax Credit on a portion

of the cost of the project

Idaho

Completed installation of 112,000 electric and gas

meters in 2005; additional 60,000 to install through 2008

IPUC pre-approved $16 million, four-year project,

including current return on investment

CapEx Dedicated to AMR

(in millions)

$2.3

$8.4

$8.7

2004

2005

2006

11

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Phase I: Gas service and collections company-wide, gas compliance Oregon

Phase II: Gas compliance in WA/ID, electric service workers company-wide

Phase II: Excludes construction crews & CPCs

Mobile Dispatch

Process improvements unlock expense savings

N/A

$700,000 Approved

Energy Business Tax Credit

$0.4 million

$0.4 million

Expense Increase

$0.8 million

$1.3 million

Average Annual Benefit

$1.6 million

$2.8 million

Capital Expenditures

63

68

Mobile Users

Phase II

Estimate

Phase I

Category

Field worker to dispatcher ratio is currently at 8:1

Phase I target ratio is 14:1

Phase II target ratio is 43:1

12

We answer to you.

Avista Utilities

Regulatory Update

Authorized

48%

10.25%

8.88%

Oregon Natural Gas

(implemented in October 2003)

43%

40%

Common

Equity

Level

Return

on

Equity

Rate of

Return

Jurisdiction and service

10.40%

9.25%

Idaho Electric and Natural Gas

(implemented in September 2004)

10.40%

9.11%

Washington Electric and Natural Gas

(implemented in January 2006)

$67 million

$63 million

$447 million

$136 million

$801 million

Gas

Gas

Electric

Gas

Electric

Oregon

Idaho

Washington

Rate Base

13

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Washington ERM

*

Idaho PCA

Power Supply Costs in Base Rates

$0

+ $9 Million

-

$9 Million

90/10 Sharing

90/10 Sharing

Power Supply Costs in Base Rates

$0

90/10 Sharing

90/10 Sharing

Avista Utilities

Electric Power Cost Mechanism

*

On

January

31,

2006

Avista

filed

with

the

WUTC

to

review

the

ERM

and

eliminate

the

$9

million

deadband.

The Commission has made a commitment to expedite the process. Any changes made to the ERM will be

effective January 1, 2006.

14

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Avista Advantage

15

We answer to you.

Facility Information and Expense Management Services for

Utilities, Telecom and Waste

3

2

1

ENHANCED SERVICES

Post payment analysis, leverage data

and execute strategies.

Rate Optimization, Contract Management, Energy Supply

Management, Network Planning, Usage Trending,

Executive Reporting and EPA Energy Star Measurement.

AUDIT & REPORTING

Validate invoices, identify and resolve

errors, optimize services.

Bill and Service Rate Accuracy, Initial Recovery Audit,

Inventory Tracking and Management, Online Reports and

Measurements.

PROCESS & PAY

Receive, enter and scan invoices, cost

allocate, issue vendor payments.

Bill Receipt, Processing and Payment, Expense

Management

Avista Advantage

16

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Avista Advantage

Avista Advantage has

penetration in

virtually all market

segments; industry

penetration is

approximately 18%.

All Clients by Market Segment

Health & Med

6%

Government

7%

Big Box

9%

Retail Food

17%

Industrial

19%

Financial

Services

4%

Multi-Site

Retail

21%

Hospitality &

Property Mgt

14%

Grocery

3%

Client sampling:

17

We answer to you.

Provides services for more than 175,000 Client sites throughout the United States

Avista Advantage

18

We answer to you.

Avista Advantage

Net Income

Revenue

Avista Advantage’s

revenues increased

by 35% for 2005, as

compared to 2004.

.

$(4,500,000)

$(3,500,000)

$(2,500,000)

$(1,500,000)

$(500,000)

$500,000

$1,500,000

$2,500,000

$3,500,000

$4,500,000

2002

2003

2004

2005

Q1 2006

$-

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

$30,000,000

$35,000,000

2002

2003

2004

2005

Q1 2006

19

We answer to you.

Avista Advantage

Sites Billed

$ Value of Bills Processed

Total Accounts

The number of billed

sites increased by

approximately 33,000,

or 25% in 2005.

$-

$1,000,000,000

$2,000,000,000

$3,000,000,000

$4,000,000,000

$5,000,000,000

$6,000,000,000

$7,000,000,000

$8,000,000,000

$9,000,000,000

$10,000,000,000

2002

2003

2004

2005

Q1 2006

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

5,500,000

2002

2003

2004

2005

Q1 2006

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

2002

2003

2004

2005

Q1 2006

20

We answer to you.

Avista Energy

21

We answer to you.

Saskatchewan

Medford

Mid-Columbia

Malin

COB

Spokane

AECO

Sumas

Stanfield

Lancaster

(270mw)

British Columbia

Alberta

Jackson  Prairie

Storage

John

Day

Chelan

(2.6 BCF)

Kingsgate

Teck

Cominco

Clark Co.

PUD

To Rockies

Montana

Idaho

Oregon

Washington

Saskatchewan

Medford

Mid-Columbia

Malin

COB

COB

Spokane

AECO

Sumas

Stanfield

Lancaster

(270mw)

British Columbia

Alberta

Jackson  Prairie

Storage

John

Day

Chelan

(2.6 BCF)

Kingsgate

Teck

Cominco

Clark Co.

PUD

To Rockies

Montana

Idaho

Oregon

Washington

Electricity

Transmission

BPA

PGE

Hydro facilities

Chelan Co

PUD

Teck

Cominco

Location

Spread

Time

Spread

Gas

Pipeline transport

NEGT

NW Pipeline

Natural gas storage

Jackson Prairie

Natural gas-fired generation

* Lancaster Project

* Clark County PUD

Inter-commodity Spread

Electricity

Transmission

BPA

PGE

Hydro facilities

Chelan Co

PUD

Teck

Cominco

Location

Spread

Time

Spread

Gas

Pipeline transport

NEGT

NW Pipeline

Natural gas storage

Jackson Prairie

Natural gas-fired generation

* Lancaster Project

* Clark County PUD

Inter-commodity Spread

Avista Energy

Energy Marketing and Resource Management

$0.47

2002

$0.43*

2003

$0.20*

2004

$(0.18)

2005

$0.10

Q1 2006

Earnings per

Diluted Share

Long-term contract rights to physical assets in the West

Generation, transmission, pipelines and storage

*

Includes Avista Power asset impairment write-down of

$(0.06) per share in 2003 and $(0.07) in 2004.

22

We answer to you.

Avista Energy

Key Contractual Assets and Strategic Agreements

Power Generation and Transmission

Lancaster 270 MW CCCT power project

250 MW of NW point-to-point transmission (BPA)

200 MW of firm AC intertie transmission capacity

Chelan PUD: real-time management of 2000 MW hydro system

Teck-Cominco: 450 MW hydro optimization

Clark PUD: 280 MW CCCT optimization

Barrick

Goldstrike

Mines: 115 MW thermal optimization

Columbia Power Corporation: 70 MW hydro optimization in 2007

Natural Gas

Jackson Prairie Natural Gas Storage

(2.7 million MMBtu’s working capacity; 100,000 MMBtu’s per day)

Nova/ANG/GTN: long-term natural gas transport

250 plus end-user customers and growing

Clark County PUD: fuel manager (48,000 m/day)

City

of

Ellensburg:

utility

operations

(storage,

transportation,

commodity,

scheduling)

23

We answer to you.

Financial

24

We answer to you.

Cash Flow

First Quarter 2006

($ thousands)

Three Months Ended March 31,

$59,225

$71,090

Ending Cash

88,317

25,917

Beginning Cash

(29,092)

45,173

Increase (Decrease) in Cash

(126)

1,690

Other

(20,459)

(40,425)

Debt Increase (Decrease), Net

(6,544)

(6,803)

Dividends on Common Stock

(1,963)

90,711

Free Cash Flow

(69,911)

(16,377)

Net Investing Activities

67,948

107,088

Cash Flow from Operations

$10,189

$31,572

Net Income

2005

2006

25

We answer to you.

Capital Expenditures

($ millions)

0

50,000

100,000

150,000

200,000

250,000

2002

2003

2004

2005

2006 Target

Avista Utilities

Energy Marketing & Resource Management

Avista Advantage & Other

Coyote Springs 2

$84

$106

$118

$218

$160

26

We answer to you.

Consolidated Earnings

$0.60

$0.89

$0.72

$0.92

$0.64

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

2002

2003

2004

2005

Q1 2006

27

We answer to you.

2006 Earnings Guidance

$(0.05)

Other

$0.10-$0.12

Avista Advantage

$0.20-$0.30

Energy Marketing & Resource Management

$1.00-$1.15

Avista Utilities

$1.30-$1.45

Consolidated

2006

28

We answer to you.

This presentation contains forward-looking statements, including statements regarding the company’s current expectations for future financial performance and cash

flows, capital expenditures, the company’s current plans or objectives for future operations, future hydroelectric generation projections, projected energy deficits in

future

periods

and

other

factors,

which

may

affect

the

company

in

the

future.

Such

statements

are

subject

to

a

variety

of

risks,

uncertainties

and

other

factors,

most

of

which

are

beyond

the

company’s

control

and

many

of

which

could

have

significant

impact

on

the

company’s

operations,

results

of

operations,

financial

condition

or

cash

flows and could cause actual results to differ materially from the those anticipated in such statements.

The following are among the important factors that could cause actual results to differ materially from the forward-looking statements: 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; 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; 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;

changes

in

global

energy

markets;

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; the potential for future terrorist attacks, particularly with

respect to utility plant assets; changes in the long-term climate of the Pacific Northwest; changes in future economic conditions in the Company’s service territory and

the United States in general; 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; 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;

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;

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.

For a further discussion of these factors and other important factors, please refer to the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2005. The

forward-looking statements contained in this presentation speak only as of the date hereof. 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

impact

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.

29

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