2009 Avista Natural Gas IRP

2009 Avista Natural Gas IRP Technical Advisory Committee Meeting May 19, 2009 Portland, Oregon

Agenda Introductions & Logistics Avista s IRP Process Demand Forecast Follow Up Supply and Infrastructure Discussion 2009 IRP Schedule

Avista s IRP Process Comprehensive analysis bringing demand forecasting and existing and potential supply and demand-side resources together into a 20-year, risk adjusted least-cost plan Considers: Customer growth and usage Weather planning standard Demand-side management opportunities Existing and potential supply-side resource options Risk Public participation through Technical Advisory Committee meetings (TAC) 2009 IRP completed on or before December 31, 2009

IRP Timeline December 29, 2008 Work Plan filed with WUTC April through July 2009 Technical Advisory Committee meetings. Meeting topics will include: April 28 - Demand Forecast & Demand-Side Management May 19 - Demand Forecast Follow up & Supply/Infrastructure June 16 - DSM follow up & SENDOUT Cases July 16 - SENDOUT results and VectorGas results September 1, 2009 Draft of IRP document to TAC October 30, 2009 Comments on draft due back to Avista November 6, 2009 TAC final review meeting (if necessary) December 31, 2009 File finalized IRP document

Demand Forecast Follow Up

Agenda Demand Model Review Natural Gas Price Forecast Distribution Planning Demand Sensitivities Follow Up Demand Scenarios

Basic Demand Modeling Equation Demand is a function of customer base usage and weather sensitive usage. The SENDOUT model computes daily forecasted demand based on the following general formula: # of customers x Daily base usage / customer Plus # of customers x Daily weather sensitive usage /customer

Dynamic Demand Methodology Demand Influencing Conditions that DIRECTLY affect core customer volume consumed Price Influencing PRICE SENSITIVE conditions that, through price elasticity, INDIRECTLY affect core customer volume consumed

Natural Gas Price Forecast

Henry Hub Pricing Trend Natural Gas the Last Eight Years $14 $12 $10 nominal $/mmbtu $8 $6 $4 $2??? $0 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Source: Wood Mackenzie, ICE

May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 Jan-07 Sep-06 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 Nymex/Sumas/Rockies/AECO Monthly Index 1999 Current May-02 Sep-02 Jan-03 May-03 Sep-03 Jan-04 May-04 Sep-04 Jan-05 May-05 Sep-05 Jan-06 May-06 Henry Hub AECO Sumas Rockies Jan-02 Sep-01 May-01 Jan-01 Sep-00 May-00 Jan-00 Sep-99 Jan-99 May-99

Long Term Gas Price Drivers Economy Industrial Demand Demand for Power Generation US Natural Gas Production Imports from Canada LNG Imports Global Dynamics North American Storage Capacity Oil and Coal Prices Carbon Legislation/Renewable Portfolio Standards

60 Lower-48 Production versus Productive Capacity (Bcf/day) 58 56 54 52 50 48 46 44 42 40 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Productive Capacity Gas Production Forecast Cap Forecast Prod Source: ICF 13

Baker Hughes Rig Counts 1,700 1,600 1,500 Rig counts are down 798 since the peak four months ago. That is a 50% drop! 1,400 Number of Rigs 1,300 1,200 1,100 1,000 900 800 Last time we saw rig counts this low was April 2003. 700 Apr May Jun Jul Aug Aug Sep Oct Nov Dec Jan Feb Mar Month Source: Baker Hughes Previous Year Current Year

Imports from Canada Emerged as an issue in Avista s last IRP Imports were declining faster than anticipated Significant transportation contracts Current Trends Imports declining slower than anticipated BC Shale larger and faster than anticipated Saskatchewan potential Low oil prices have lessened demand for oil sands production Alberta royalties Stimulus related concessions Renegotiation?

LNG Flows: The United States as a Residual Market? LNG Supply Pacific Middle East Atlantic Europe Latin America/ Niche Markets Henry Hub + UK/Belgium NBP/ Zeebrugge Source: CERA Emerging Asia Traditional Asia North America Henry Hub LNG flows to North American and UK/Belgian markets after other higher-priced markets receive their share Source: Cambridge Energy Research Associates. 70201-2

North American Storage North American natural gas demand roughly 70 Bcf/Day Working Gas Capacity by Type of Storage North American storage approximately 4 Tcf MATHEMATICAL days demand to storage = 57 days Source: EIA - 'Natural Gas Storage in the United States 2006' Key question: With production shift to unconventional gas, will attractive new storage opportunities diminish (i.e. are shale gas wells suitable for storage?)

$160 $140 $120 $100 $80 $60 $40 $20 $0 Crude Oil vs. Natural Gas Prices Crude Oil and Natural Gas Prices January 2008 through April 2009 $16 $14 $12 $10 $8 $6 $4 $2 $0 4-2-2009 2-2-2008 3-2-2008 4-2-2008 5-2-2008 6-2-2008 7-2-2008 8-2-2008 9-2-2008 10-2-2008 11-2-2008 12-2-2008 1-2-2009 2-2-2009 3-2-2009 1-2-2008 Crude Oil $/Barrel Natural Gas $/Dekatherm Oil to Gas Ratios: Jan 2008-1 to 12 Mar 2008-1 to 11 July 2008-1 to 12 Nov 2008-1 to 8.5 Jan 2009-1 to 8 Apr 2009-1 to 14 Oil Natural Gas

Carbon Policy/Renewable Portfolio Standards Natural Gas has a critical yet complex role in carbon policy creation and implementation. Numerous complex issues and uncertainties Need to balance economic challenges with policy objectives Complex issues within cap and trade vs. simpler carbon tax Market mechanisms Auctions vs. allowance allocations Offsets Long term role or interim bridge?

$22.00 $20.00 $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- Henry Hub Price Forecasts Nominal $/Dth $/Dth 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Consult1 Consult2 AEO NYMEX NPCC Low NPCC Medium NPCC High

$16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- Henry Hub Price Forecasts 2009$/Dth $/Dth 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Consult1 Consult2 AEO NYMEX NPCC Low NPCC Medium NPCC High

Henry Hub Price Forecasts for IRP Nymex blend first five years* Nominal $/Dth $22.00 $20.00 $18.00 $16.00 $14.00 $/Dth $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- *Nymex weighted 50%, 40%, 30%, 20%, 10% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Consult1 NPCC Low NPCC High

$16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- Henry Hub Price Forecasts for IRP Nymex blend first five years* 2009$/Dth $/Dth 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Consult1 NPCC Low NPCC High *Nymex weighted 50%, 40%, 30%, 20%, 10%

Regional Price Assumptions Regional Price as a percent of Henry Hub Price AECO Sumas Rockies Malin Stanfield Consultant1 Forecast Average Forward Markets Five Yr Average 92.7% 95.2% 85.6% 94.1% 93.7% 88.8% 97.1% 84.5% N/A N/A Prior IRP 86.0% 87.6% 80.5% N/A N/A

Monthly Price Shape Monthly Price as a percent of Average Price Jan Feb Mar Apr May Jun Consult1 107% 108% 103% 93% 93% 94% Prior IRP 113% 113% 110% 93% 92% 93% Jul Aug Sep Oct Nov Dec Consult1 95% 96% 96% 97% 109% 110% Prior IRP 94% 94% 95% 96% 101% 106%

Distribution System Planning

Distribution System Planning Overview Scope of Distribution System Planning Purpose of a Load Study Preparing a Load Study Balancing Model Validating Model Planning Criteria Interpreting Results

5 Variables for Any Given Pipe P up Q L P down D

Scope of Gas Distribution Planning Supplier Pipeline Gate Sta. High Pressure Main Reg. Reg. Reg. Distribution Main and Services

Scope of Gas Distrib. Planning cont. Gate Sta. Gate Sta. Reg. Reg. Reg. Reg. Reg. Gate Sta.

Purpose of a Load Study Simulate distribution behavior Identify low pressure areas Coordinate reinforcements with expansions Measure reliability

Preparing a Load Study Estimating Customer Usage Creating a Pipeline Network Join Customer Loads to Pipes Convert to Load Study

Estimating Customer Usage Gathering Data - Days of service - Degree Days - Usage - Name, Address, Revenue Class, Rate Schedule Peaking Factor - Peaking Factor = 6.25% of daily load - Observed ratio of greatest hourly flow to total daily flow at Gate Stations

Heat Base

Creating a Pipeline Network Elements Pipes, Regulators, Valves, or Reservoirs Length, Internal Diameter, Pipe Roughness Nodes Sources, Customer Usage Points, Transitions, Pipe beginning and end Flow, Pressure

Join Customer Loads to Pipes Geocode Customers Assign Loads to Pipes Industrial Customer Load is assigned to Nodes

Balancing Model Generate loads for any temperature HDD s Solve for pressure at all nodes

35 DD 30 F

Validating Model Simulate recorded condition Pressure Recorders Do calculated results match field data? Gate Station Telemetry Do calculated results match source data? Possible Errors Missing pipe Source pressure changed Industrial loads

Validating Model cont. 41 psig Hi = 35 F Low = 25 F Avg = 30 F = 35 DD Location: N. Orchard, Moscow ID Observation Date: Friday, March 1st

N. Orchard Moscow, ID 35 DD 30 F

Planning Criteria Reliability during Design HDD Spokane 82 HDD Medford 61 HDD Klamath Falls 72 HDD La Grande 74 HDD Roseburg 55 HDD Maintain minimum of 15 psig in system at all times 5 psig in lower MAOP areas

35 DD 30 F

50 DD 15 F

65 DD 0 F

Interpreting Results Identify Low Pressure Areas Number of feeds Proximity to source Looking for Most Economical Solution DSM Length (minimize) Construction obstacles (minimize) Customer growth (maximize)

65 DD 0 F

65 DD 0 F R

82 DD -17 F R

Sensitivities and Proposed Scenarios

Proposed Sensitivities Demand Influencing (Direct) Model Sensitivities INPUT ASSUMPTIONS Customer Growth Rate Residential WA/ID 2.2% Residential Medford 2.6% Residential Roseburg 3.6% Residential Klamath 1.9% Residential La Grande 1.4% Commercial WA/ID 2.3% Commercial Medford 1.2% Commercial Roseburg 2.1% Commercial Klamath 1.9% Commercial La Grande 0.6% DEMAND INFLUENCING - DIRECT Reference Low Cust High Cust CNG 1HDD Lower Cold Day 20yr Northern Stagnant Global Case Growth Growth Vehicles Weather Std Weather Std Migration?? Growth?? Warning?? 50% Decrease in Cust Growth Rates 50% Increase in Cust Growth Rates?????? Use per Customer Flat 15% Growth Cumulative Weather Planning Standard Coldest Day Coldest-1HDD Coldest 20yrs??? Prices Price curve Price curve adder ($/Dth) Expected None Elasticity Carbon Adder ($/Ton) None None RESULTS Gas Years Change - OUT (IN) WA/ID N/A N/A (5) 0 Medford N/A 8 (1) 1 Roseburg N/A N/A 0 Pending 0 Pending Klamath N/A N/A (3) 0 La Grande N/A N/A (4) 1?????????

Proposed Sensitivities Price Influencing (Indirect) Model Sensitivities PRICE INFLUENCING - INDIRECT Reference Expect Low High Low High Carbon Carbon Cdn Imports Drilling Case Elasticity Elasticity Elasticity Prices Prices Mitigate 1 Mitigate 2 Decline Constraints?? INPUT ASSUMPTIONS Customer Growth Rate Residential WA/ID 2.2% Residential Medford 2.6% Residential Roseburg 3.6% Residential Klamath 1.9% Residential La Grande 1.4% Commercial WA/ID 2.3% Commercial Medford 1.2% Commercial Roseburg 2.1% Commercial Klamath 1.9% Commercial La Grande 0.6% Use per Customer Weather Planning Standard Flat Coldest Day Prices Price curve Expected Expected Expected Expected Low High Expected Expected Expected Expected Price curve adder ($/Dth) None $.50-$1.00 Adder $.50-$1.00 Adder $.50 Adder After 5yrs??? Elasticity None Expected Low High Expected Expected Expected Expected Expected Expected Carbon Adder ($/Ton) None $5-$67 $37-$140 RESULTS Gas Years Change - OUT (IN) WA/ID N/A 1 0 1 0 0 0 1 1 Medford N/A 1 0 2 1 1 1 1 1 Roseburg N/A 0 0 0 0 0 0 0 0 Klamath N/A 1 0 2 0 0 1 1 1 La Grande N/A 3 0 4 1 2 2 3 2???

Proposed Scenarios Scenarios Expected High Growth Low Growth Cold Day 20yr High Drilling Case & Low Prices & High Prices Weather Std Carbon Adder Constraints?? Others? INPUT ASSUMPTIONS Customer Growth Rate Reference Case Cust Growth Rates 50% Increase in Cust Growth Rates 50% Decrease in Cust Growth Rates Reference Case Cust Growth Rates Reference Case Cust Growth Rates Use per Customer Flat + Flat + Flat + Flat + Flat + Price Elast. Price Elast. Price Elast. Price Elast. Price Elast. Weather Planning Standard Coldest Day Coldest Day Coldest Day CD 20 yrs Coldest Day?????? Prices Price curve Expected Low High Medium High Price curve adder ($/Dth) None None None None None Elasticity Expected Low High Expected High Carbon Adder ($/Ton) $5-$67 $5-$67 $5-$67 $5-$67 $37-$140

Supply and Infrastructure Discussion

Agenda Supply Resources Avista s needs Procurement plan Storage Resources Transportation Resources Other Potential Resources

Avista s Core Gas Supply Needs Avista s core customers consumed approximately 34 bcf in 2008 Widely varying procurement needs with significant uncertainty Monthly volume variance (plan) high vs. low 193,000 Dth vs. 26,000 Dth Intra month volume variance (e.g. November high vs. low volumes 140,000 Dth vs. 50,000 Dth Planned peak day volume = 351,000 Dth in 2010 Significant price volatility; for example Rockies basin: Gas Daily four year average price $5.72 High $13.10 on December 14, 2005; Low $.08 on November 9, 2007

Total System Average Daily Load (Average, Min, and Max) January 2004 - March 2008 Spokane Avg Actual HDD 6,516 Spokane NOAA Avg HDD 6,820 400,000 Medford Avg Actual HDD 4,047 Medford NOAA Avg HDD 4,539 350,000 300,000 250,000 Dth/d 200,000 150,000 100,000 50,000 - Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Average Load Min Load Max Load Sendout Forecast Peak Day 80% of Average

Natural Gas Procurement Plan Objective Goal To provide reliable supply at stable and competitive prices in navigating a variety of market conditions Premise - Avista cannot accurately predict future natural gas prices, but market conditions and experience help shape our overall approach The Strategic Oversight Group (which is made up of employees in Gas Supply, Risk Management, Rates, Accounting, and Credit) annually reviews and creates the coming year s procurement plan. The procurement plan is approved by Avista s Risk Management Committee. Avista regularly considers plan enhancements.

Procurement Plan Structure The procurement plan incorporates a portfolio approach that is diversified in terms of: Components: The plan utilizes a mix of index, fixed price, and storage transactions. Transaction Timing: Hedge windows are developed to distribute the transactions throughout the plan. Supply Basins: Supplies come from the Rocky Mountain region and Alberta. Sumas is generally used for supply and price optimization. Delivery Periods: Hedges are completed in annual, seasonal and monthly timeframes. Long-term hedges may be included Transactions are executed pursuant to a plan and process; however, the procurement plan allows Avista to be flexible to market conditions and opportunistic when appropriate.

Procurement Options Avista seeks to balance considerations of the portfolio s cost and volatility through its purchasing activities. Procurement options include: Intercontinental Exchange (ICE) & NGX Real-time NYMEX Brokers OTC Telephone & Instant Messaging Index Price (Annual, Seasonal, Monthly, Daily) Fixed Price (Annual, Seasonal, Monthly) Physical Transactions Financial Transactions Derivatives Avista purchases gas in the spot market as well as the forward market. Spot purchases are made on a day for the next day or weekend. Forward purchases are made on a day for a designated future delivery period.

Supply Locations AECO - Canadian gas coming out of Alberta, Canada Rockies - US domestic gas coming from Wyoming and Colorado Sumas - Canadian gas coming out of BC, Canada Malin - South central at the Oregon and California border Stanfield - Intersection of two major pipelines in North central Oregon

Regional Natural Gas Storage Resources Jackson Prairie Mist Plymouth Clay Basin AECO Northern California Jackson Prairie Natural Gas Facility Chehalis, Washington

Avista s Storage Resources Washington and Idaho Owned Jackson Prairie 5.2 Bcf of Capacity with approximately 268,000 Dth/d of deliverability Oregon Owned Jackson Prairie 263,000 Dth of Capacity with approximately 26,000 Dth/d of deliverability Leased Jackson Prairie 95,565 Dth of Capacity with approximately 2,654 Dth/d of deliverability Leased Mist 500,000 Dth of Capacity with approximately 15,000 Dth of deliverability. Contract expires April 2010. In April 2011, we anticipate recalling 3.0 Bcf of Capacity from Shell Energy for use in utility operations, subject to regulatory approval.

Storage A valuable asset Peaking resource Improves reliability Enables capture of price spreads between time periods Inter seasonal spreads Intra seasonal spreads Enables efficient counter cyclical utilization of transportation

Regional Transportation Resources TransCanada Alberta (NOVA) Transporting gas out of Alberta, Canada TransCanada BC (ANG) Transporting gas through BC, Canada to US Spectra Energy (WestCoast) Transporting gas from western BC Canada to US Gas Transmission Northwest (GTN) Transporting gas from Canada/US border to CA Williams Pipeline West (Northwest Pipeline) Transporting gas from western BC and US Rockies Source: NWGA

Connecting Supply and Storage with Customers

Modeling Transportation In SENDOUT Start with a point in time look at each jurisdiction s resources Prior IRP conservative treatment of jurisdictional issues Historical approach vs. operational flexibility Modeling operational flexibility enables significant deferral of new resources

Other Potential Resources Transport capacity release recalls Firm backhauls Contract existing available transportation Expansions of current pipelines Peaking arrangements with other utilities (swaps) Satellite LNG (storage inside service territory) LNG with corresponding pipeline build into our service territory Structured products delivered to city gates Biogas

Supply Projects Proposed to Serve the Northwest LNG Import Terminals Bradwood Landing LNG Jordan Cove LNG Kitimat LNG Oregon LNG WestPac LNG Terminal Pipelines Pacific Connector Pipeline Palomar Pipeline East, West Sunstone Pipeline Blue Bridge Pipeline Oregon LNG Ruby Pipeline Palomar Lancaster Blue Bridge Coyote Springs Sunstone Pacific Connector Ruby Source: NWGA 73

Preview Next TAC Meeting Finalized Demand Scenarios DSM Follow up SENDOUT Model Overview Example results VectorGas Overview Other topics?

IRP Timeline December 29, 2008 Work Plan filed with WUTC April through July 2009 Technical Advisory Committee meetings. Meeting topics will include: April 28 - Demand Forecast & Demand-Side Management May 19 - Demand Forecast Follow up & Supply/Infrastructure June 16 - DSM follow up & SENDOUT Cases July 16 - SENDOUT results and VectorGas results September 1, 2009 Draft of IRP document to TAC October 30, 2009 Comments on draft due back to Avista November 6, 2009 TAC final review meeting (if necessary) December 31, 2009 File finalized IRP document