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 | ||||
 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 We answer to you. 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 We answer to you. 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 We answer to you. 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 We answer to you. 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 We answer to you. 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 We answer to you. 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.
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 29 We answer to you. |