20080403Kalich Direct.pdf

C¡Vi:n..-... ii. ~.lJ
DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL,
GOVERNNTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220 - 3 7 2 7TELEPHONE: [phone]FACSIMILE: [phone]
REGULATORY200B APR -3 .p.. w12n .: S5
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC AN
NATURAL GAS SERVICE TO ELECTRIC
AN NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
DIRECT TESTIMONY
OF
CLINT G. KAICH
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I. INTRODUCTION
Q.Please state your name, the name of your
3 emloyer, and your business address.
4
5
A.My name is Clint Kalich. I am employed by Avista
Corporation at 1411 East Mission Avenue,Spokane,
6 washington.
7
8
Q.In what capacity are you employed?
A.I am the Manager of Resource Planning & Power
9 Supply Analyses, in the Energy Resources Department of
10 Avista Utilities.
11 Q.Please state your educational background and
12 professional experience.
13 A.I graduated from Central Washington University in
14 1991 with a Bachelor of Science Degree in Business
15 Economics. Shortly after graduation, I accepted an analyst
16 position with Economic and Engineering Services, Inc. (now
17 EES Consulting, Inc.), a Northwest management-consulting
18 firm located in Bellevue, Washington.While employed by
19 EES, I worked primarily for municipalities, public utility
20 districts, and cooperatives in the area of electric utility
21 managemen t .My specific areas of focus were economic
22 analyses of new resource development, rate case proceedings
23 involving the Bonneville Power Administration, integrated
24 (least-cost) resource planning, and demand-side management
25 program development.In late 1995, I left Economic and
Kalich, Di 1
Avista Corporation
1 Engineering Services, Inc. to join Tacoma Power in Tacoma,
2 washington.I provided key analytical and policy support
3 in the areas of resource development, procurement, and
4 optimization, hydroelectric operations and re-licensing,
5 unbundled power supply rate-making, contract negotiations,
6 and system operations.I helped develop, and ultimately
7 managed, Tacoma Power's industrial market access program
8 serving one-quarter of the company's retail load.In mid-
9 2000 I joined Avista Utilities as a Senior Power Resource
10 Analyst.
11 In 2001, I accepted my current position, assisting the
12 Company in resource analysis, dispatch modeling, resource
13 procurement, integrated resource planning, and rate case
14 proceedings.Much of my career has involved resource
15 dispatch modeling of the nature described in this
16 testimony.
17 Q.What is the scope of your testimony in this
18 proceeding?
19 A.My testimony will describe the Company's use of
20 the AURO~ dispatch model, hereinafter referred to as the
21 "Dispatch Model."i will explain the key assumptions
22 dri ving the Dispatch Model's market forecast of electricity
prices.The discussion includes the variables of natural23
24
25
gas,Western Interconnect loads and resources,and
hydroelectric conditions.I will describe how the model
Kalich, Di 2
Avista Corporation
1 dispatches our resources and contracts in a manner that
2 maximizes benefits to customers and tracks their values for
3 use in pro forma calculations. Finally, i will present the
4 modeling results provided to Company Witness Mr. Johnson
5 for his power supply pro forma adjustment calculations.
6 Q.Are you sponsoring any exhibits in this
7 proceeding?
8 A.Yes.I am sponsoring Exhibi t No.5, Schedules 1
9 and 2. Schedule 1 provides a forecast of Company load and
10 resource positions from 2009 through 2018.Schedule 2
11 provides sumary output from the AURO~ dispatch model.
12 All information contained in the exhibit was prepared under
13 my direction.
14
15
16
II. THE DISPATCH MODEL
Q.What model is the Company using to dispatch its
17 portfolio of resources and obligations?
18 A.The Company uses EPIS, Inc.' s AURO~ system
19 dispatch model ("Dispatch Model") for determining power
20 supply cos ts .The model optimizes dispatch of Company-
21 owned resources and contracts in each hour of the pro forma
22
23
year.The pro forma period is January 1, 2009 through
Decemer 31, 2009.It reflects true system operations by
24 evaluating future resource decisions on an hourly basis.
Kalich, Di 3
Avista Corporation
1
2
3
4
5
6
7
8
Q.What AURORA version and database is the Company
using for this case?
A.The Company is using AURO~p version 9.0. ,
released in Novemer 2007,and the latest available
database for it (North_American_DB_2007-02) .
Q.Please briefly describe the Dispatch Model.
A.The AURO~ electric market model was developed
Inc. of Sandpoint,Idaho.AURO~ is aby EPIS,
9 fundamentals-based tool containing demand and resource data
10 for the entire Western Interconnect. It employs multi-area,
11 transmission-constrained dispatch logic to simulate real
12 market conditions. Its true economic dispatch captures the
13 dynamics and economics of electricity markets.On an
14 hourly basis the Dispatch Model develops an available
15 resource stack, sorting resources from lowest to highest
16 It then compares this resource stack with loadcost.
17 obligations in the same hour to arrive at the least-cost
18 market-clearing price for the hour.Once resources are
19 dispatched and market prices are determined, the Dispatch
20 Model singles out Avista resources and loads and values
21 them agains t the marketplace.
22 Wht experience does the Company have usingQ.
23 AURO~?
24
25
The Company purchased a license to use AURO~A.
in April 2002.AURO~ has been used for numerous
Kalich, Di 4
Avista Corporation
1 studies, including the Company's 2003, 2005, and 2007
2 Integrated Resource Plans ("IRPs"), our 2004 general rate
3 case filing in this state, and our 2005, 2007, and 2008
4 general rate case filings before the washington Utilities
5 and Transportation Commission ("WUTC"). The tool is also
6 used for various resource evaluations, including requests
7 for proposals.
8
9
Q.Who else uses AURO~?
AURO~ is used all across North America.InA.
10 the Northwest specifically, AURO~ is used by the
11 Bonneville Power Administration, the Northwest Power and
12 Conservation Council, Puget Sound Energy, Idaho Power,
13 Portland General Electric, Seattle City Light, Grant County
14 PUD, and Tacoma Power, among others.
15 Q.What benefits does the Dispatch Model offer for
16 this type of analysis?
17 A.The Dispatch Model generates hourly electricity
18 prices across the Western Interconnect, accounting for its
19 specific mix of resources and loads.The Dispatch Model
20 reflects the impact of regions outside the Northwest on
21
22
Northwest market prices,limi ted by known transfer
(transmission) capabilities.Ultimately, the Dispatch
23 Model allows the Company to generate price forecasts in-
24 house instead of relying on exogenous forecasts.
Kalich, Di 5
Avista Corporation
1 The Company owns a numer of resources, including
2 hydroelectric plants and natural gas-fired peaking units,
3 which serve customer loads during more valuable on-peak
4 hours.By optimizing resource operation on an hourly
5 basis, the Dispatch Model is able to appropriately value
6 the capabilities of these assets. For example, actual 2006
7
8
on-peak prices were 31.9% higher than off-peak prices.In
2007 the difference was 29.9%.For comparison, Dispatch
9 Model on-peak prices for the pro forma period average 30%
10 higher than off-peak prices.In sumary, the Dispatch
11 Model appropriately values the energy from Avista' s
12 resources during on-peak periods in a manner similar to
13 that recently experienced in the Northwest region.
14 Q.On a broader scale, what calculations are being
15 performed by the Dispatch Model?
16 A.The Dispatch Model's goal is to minimize overall
17 system operating costs across the Western Interconnect,
18 including Avista' s portfolio of loads and resources.The
19 dispatch model generates a wholesale electric market price
20 forecast by evaluating all Western Interconnect resources
21 simultaneously in a least-cost equation to meet regional
22 loads. As the Dispatch Model progresses from hour to hour,
23 it "operates" those least-cost resources necessary to meet
24 load.With respect to the Company's portfolio, the
25 Dispatch Model tracks the hourly output and fuel costs
Kalich, Di 6
Avista Corporation
1 associated with portfolio generation.It also calculates
2 hourly energy quantities and values for the Company's
3 contractual rights and obligations.In every hour the
4 Company's loads and obligations are compared to determine a
5 net position.This net position is balanced using the
6 simulated wholesale electricity market. The cost of energy
7 purchased from or sold into the market is determined based
8 on the electric market-clearing price for the specified
9 hour and the amount of energy necessary to balance loads
10 and resources.
11 Q.How does the Dispatch Model determine electric
12 market prices, and how are prices used to calculate market
13 purchases and sales?
14 A.The Dispatch Model calculates electricity prices
15 for the entire Western Interconnect, separated into various
16 geographical areas such as the Northwest and Northern and
17 Southern California. The load in each area is compared to
18 available resources, including resources available from
19 other areas that are linked by transmission corridors, to
20 determine the electricity price in each hour. Ultimately,
21 the market price for an hour is set based on the last
22
23
resource in the stack to be dispatched.This resource is
referred to as the "marginal resource. "Given the
24 prominence of natural gas-fired resources on the margin,
Kalich, Di 7
Avista Corporation
1 this fuel is a key variable in the determination of
2 wholesale electricity prices.
3 Q.How does the Dispatch Model operate regional
4 hydroelectric projects?
5
6
A.The model begins by "peak shaving" loads using
sys tem hydro resources.When peak shaving, the Dispatch
7 Model determines which hours contain the highest loads and
8 allocates to them as much hydroelectric energy as possible.
9 Remaining loads are then met with other available
10 resources.
11 Q.Has the Comany made any modifications to the
12 database for this case?
13 A.Yes. Avista' s portfolio of resources is modified
14 to reflect actual operating characteristics, natural gas
15 prices are modified to match projected forward prices over
16 the pro-forma period, regional resources are modified where
17 better information is known, and northwest hydro data is
18 replaced with Northwest Power Pool data.
19 Q.Please describe your update to pro form period
20 natural gas prices.
21 A.Natural gas prices for this filing are based on a
22 3-month average of 2009 monthly forwards from October 1,
23 2007 to Decemer 31, 2007. This method is consistent with
24 our present case before the WUTC.Prices are fitted to a
25 daily shape based on daily spot market prices at AECO
Kalich, Di 8
Avista Corporation
1 between January 2003 and December 2007. Daily and monthly
2 gas price shapes at AECO are shown in Chart No.1.Other
3 basins retain the same daily shape.
4 Chart No. 1 - Daily Natural Gas Price Shape at AECO
$9.00
_DailyPóee
$8.50 -Monthly Aig Póee
$8.0
E $7.50.c-"C-$7.004R
$6.50
$6.00
$5.50
2 3 4 5 6 7 8 9 10 11 12
5
6 Natural gas prices are modified to ensure prices
7 across the Western Interconnect are consistent with changes
8 made to the Northwes t .Anual average natural gas prices
9 at the various trading hubs are presented below in Table
10 No. 1.
11 Table No. 1 - Pro Form Natural Gas Prices
12
13
14
15
16
Price Price
Basin ($/dth)Basin ($/dth)
AECO 7.55 Stanfield 7.92
Malin 7.99 Sumas 8.15
Spokane 8.28 Hen Hub 8.36
Rockies 7.02 Topock 7.97
Kalich, Di 9
Avista Corporation
1 Q.What hydro record is the Company using in this
2 filing?
3
4
A.The Company bases this case on the 50-year
hydrological record beginning in 1929.As with natural
5 gas, this method is consistent with our present case before
6 the WUTC.The Dispatch Model is run one time for each
7 hydroelectric year, with the average of all 50 being used
8 to set power supply expenses.
9 Data is sourced from the Northwest Power Pool's (NWPP)
10 2006-07 Headwater Benefits Study. This study is the latest
11 available.
12 Q.How does Coyote Springs 2 dispatch relate to
13 historical dispatch?
14
15
16
A.Coyote Springs 2 was modified from the default
database to more accurately simulate actual plant
operations.Chart No. 2 shows actual Coyote Springs 2
17 dispatch for calendar year 2007.
18 Chart No. 2 - CS2 Dispatch (Calendar Year 2007 Actual)
100
350
300
250
l 200
l 150
50
o
2 3 4 5 6 7 8 9 10 11 12
19 Month
Kalich, Di 10
Avista Corporation
1 Chart No. 3 shows Coyote Springs 2 during the 2009 pro
2 forma period prior to modifying database assumptions.
3
4 Chart No. 3 - CS2 Dispatch (2009 Pro Form with AUR0RA
5 default logic)
50
300
250
200
t 150::
100
o
2 3 4 5 6 7 8 9 10 11 12
Month
6
7 The Dispatch Model using EPIS' default database starts and
8 shuts down Coyote Springs 2 nearly every day (269 starts),
9 and the plant generates 121 aMW. This operational pattern
10 is not realistic and is beyond the operational capability
i 1 of Coyote Springs 2.To resolve this modeling challenge,
12 the Company modified the start-up cost, start-up fuel,
13 minimum up and minimum down times for the plant. This same
14 methodology was tested for all Western Interconnect
15 combined cycle plants, but such modification had an adverse
16 effect on the overall on/off peak price spread, resulting
17 in a much higher differential than witnessed historically
Kalich, Di 11
Avista Corporation
1 or that is present in the forward markets. Avista continues
2 to work with EPIS, the developer of AURO~, to address
3 our concerns with overall CCCT plant dispatch across the
4 Western Interconnect.
5 Start-up costs were identified as a key driver to the
6 incorrect dispatch behavior of Coyote Springs 2. The EPIS
7 default start-up cost for Coyote Springs 2 is $12.61 per MW
8
9
start-up cost, or $3,429.Based on our experience, this
cost is low by orders of magnitude.Based on Company
10 experience each cold start at Coyote Springs 2 includes
11 1,891 decatherms of fuel and $10,000 of estimated O&M
12 costs.Assuming the average annual Stanfield natural gas
13 price of $7.92 per decatherm, the start up costs is
14 estimated to be $24,977 (1,891 x $7.92 + $10,000).
15 The second modification made by the Company was to
16 change the minimum up and minimum down times from 16 hours
17 and 8 hours respectively, to 20 hours up an 20 hours down.
18 Minimum up time, not only indicates how long the unit must
19 stay on-line, but also is used to allocate start-up costs
20 for commitment decisions.
21 These two changes, when taken together, provide for a
22 much more reasonable dispatch of Coyote Springs 2, as shown
23 in Chart NO.4.
24
25
Kalich, Di 12
Avista Corporation
1 Chart No. 4 - CS2 Dispatch (2009 Pro Form Average Hydro)
50
300
250
200i
~ 150
gi::
100
o
2 3 4 5 6 7 8 9 10 11 12
Month
2
3 Q.How does the Dispatch Model Operate Company-
4 controlled hydroelectric generation resources?
5 A.The Dispatch Model treats all hydroelectric
6 generation plants wi thin a load area as a single large
7 plant. The Company's hydroelectric plants are on average,
8 however, more flexible than the average plant used in each
9 load area. To account for this additional flexibility, the
10 Company algebraically extracts its plants from the region
11 and develops individual hydro operations logic for them.
12 Company-controlled hydroelectric resources are separated
13 into three river systems:the Spokane River, the Clark
14 Fork River, and individually separate the Mid-Columia
15 projects.This separation ensures that the flexibility
16 inherent in these resources is credited to customers in the
17 pro forma exercise.
Kalich, Di 13
Avista Corporation
1 Q.Please compare the operating statistics from the
2 Dispatch Model to recent historical hydroelectric plant
3 operations.
4 A.Over the pro forma period the Dispatch Model
5 generates 66.9% of the Company's hydro generation during
6 on-peak hours (based on average water).Since on-peak
7 hours represent only 57% of the year, this demonstrates a
8 substantial shift of hydro resources to the more expensive
9 on-peak hours.This is nearly identical to the 5-year
10 average of on-peak hydroelectric generation through 2007:
11 66.4%.
12 Q.What is the Company assuming for natural gas
13 prices in the pro form period for Company-owned gas-fired
14 resources?
15
16
A.Natural gas prices are a function of average
commodi ty cos t,transportation,and applicable taxes.
17 Consistent with our last general rate case filing, natural
18 gas prices were set using an average of witnessed forward
19 prices, specifically the three-month period ending December
20 31, 2007. The average price for the pro forma year equals
21 $7.92 per decatherm at Rathdrum and CS2, and $8.28 per
22 decatherm for Northeast, Boulder Park, and the Kettle Falls
23 CT.
Kalich, Di 14
Avista Corporation
1 Q.Please provide a sumry of the monthly and
2 average Northwest Forward natural gas and electricity
3 prices?
4 A.Table No. 2 presents modeled natural gas and
5 electrici ty prices.
6
7 Table No. 2 - Dispatch Model Prices Comparison
CSII&NElBPI CSII &NElBP/
Rathdrum KFCT Rathdrum KFCT
Gas Gas Mid-C Gas Gas Mid-e
Month ($Idth)($Idth)($IMWh)Month ($Idth)($/dth)($IMWh)
Jan-09 8.594 8.988 57.95 Jul-09 7.574 7.927 57.90
Feb-09 8.599 8.993 62.66 AUQ-09 7.626 7.981 65.3
Mar-09 8.357 8.741 58.97 5eo-09 7.643 7.999 61.49
Aor-09 7.497 7.846 52.12 Oct-09 7.688 8.046 59.02
Mav-09 7.455 7.803 47.25 Nov-09 8.068 8.441 63.09
Jun-09 7.508 7.858 41.33 Dec-09 8.393 8.779 62.04
Average 7.92 8.28 57.39
8
9 Q.Are Mid-Columia electric prices from the
10 Dispatch model the same as the Forward Market?
11 A.No,Mid-Columia electric prices from the
12 Dispatch Model differ from the forward market for a variety
13 of reasons. The forward market prices are not only an
14 expectation of future prices,but they contain an
15 adjustment for risk or unknown future conditions, based on
16 the premise you can "lock in" prices.The Dispatch Model
17 is a spot market model that forecasts prices for a specific
18 time in the future given load, hydro, and fuel price
19 conditions. Average annual Mid-Columia prices in the
20 forward market are $68. 38/MW on-peak and $54. 25/MW off-
Kalich, Di 15
Avista Corporation
1 peak (based on average forwards between 10/1/2007 and
2 12/31/2007). The average Mid-Columia price from the
3 Dispatch Model is $63. 68/MW on-peak and $48. 99/MW off-
4 peak.
5 Q.You stated earlier in your testimony that you are
6 using the NWP hydro study as the basis for your hydro
7 dataset. Does the NWP study include the Cabinet Unit 4 or
8 the Noxon Rapids 4 upgrade?
9
10
A.No, the NWPP study does not include the Cabinet
Uni t 4 or Noxon Rapids 4 upgrades.The data will be
11 included in our next data submittal to the NWPP. I expect
12 the upgrade to be reflected in the 2008 NWPP study.
13 Q.How have you accounted for the Cabinet Unit 4 and
14 Noxon Rapids 4 upgrades in the pro form?
15 A.The Cabinet Unit 4 upgrade is expected to
16 generate 1.98 average megawatts and Noxon Rapids 4 is
17 expected to generate 2.33 average megawatts of additional
18 energy in an average water year.To account for this
19 energy in the pro forma, the unit sizes are increased from
20 55.2 MW to 59.7 MW and 105 MW to 111.4 MW, respectively.
21 The Dispatch Model then generates at the upgraded energy
22 and capacity levels when the units are dispatched.
23 Q.Please explain how the upgrades to Colstrip Units
24 3 and 4 are reflected in the Dispatch Model.
Kalich, Di 16
Avista Corporation
1 A.The Company increased the generation capability
2 of each unit from 740 MW to 768 MW. This change allows the
3 Dispatch Model to correctly value the entirety of each
4 plant in the wholesale marketplace. Our resource portfolio
5 tracked in the Dispatch Model contains a 15% share of each
6 unit.With the overall capacity of each resource
7 increased, our 15% allocation increases proportionally and
8 lowers the overall cost of our generation portfolio.
9
10
11
III. RATE PERIOD LOAD ADJUSTM
Q.Why is the company proposing using 2009 pro form
12 retail loads in this case?
13 A.The intent of each rate proceeding is to develop
14 a reasonable proj ection of costs the company expects to
15 incur during the period over which rates are set.Though
16 historical data are used as the starting point, adjustments
17 are made where that history does not provide accurate
18 revenues and expenses for the period new rates will be in
19 effect.For example, in the power supply category alone,
20 pro forma adjustments are included to reflect expected
21 conditions in 2009 for hydroelectric plant upgrades, fuel
22 prices, and contracts that were not in the historical test
23 year.
24 Q.Please explain the source used for 2009 pro form
25 loads?
Kalich, Di 17
Avista Corporation
1
2
3
A.Each year the Company develops a 25-year load
forecast by rate class (residential,commercial,
industrial, and street lighting).The load proj ection is
4 used by many departments throughout the utility. It is the
5 basis for power supply budgeting, revenue forecasting by
6 our finance department, and for our Integrated Resource
7 Plans ( IRPs) .During the natural gas and electric IRP
8 processes the forecast is reviewed both internally by
9 senior management as well as by external parties that
10 include Idaho and Washington Commission staff members.
11 The rate period loads used in this case are taken from
12 the Company's 2008 load forecast completed in July 2007.
13 The 2009 load value is 1,061. 2 aMW.As this load is
14 generated using "normal weather, II it eliminates the need
15 for any weather-normalization adjustment.
16 Q.Are Avista' s rate period loads based on
17 quantitative methods?
18 A.Yes.For the residential, small and large
19 general service, pumping and street light customers, the
20 methodology is based on mathematical relationships between
21 growth in the economy of the service area and the energy
22 used by customers.Very large general service customer
23 (e.g., hospitals, universities, manufacturers) forecasts
24 rely on trends in these segments combined with regular
Kalich, Di 18
Avista Corporation
1 discussion with the individual customers regarding
2 expansion (or contraction) plans.
3 Q.How does Avista acquire service area economic
4 forecasts?
5 A.Avista contracts with Global insight, Inc., a
6 national economic forecasting consulting company also used
7 by agencies in the states of Idaho, Oregon and Washington
8 to provide county-level projections of job, population, and
9 personal income growth rates. These have been shown to be
10 the primary drivers of electricity consumption. Global
11 Insights, Inc. also provides proj ections for interest
12 rates, oil prices, the consumer price index, and other
13 factors used to project customer growth and customer
14 consumption.
15 Q.Does Avista include the impact of conservation
16 and electricity prices when projecting future electricity
17 load?
18
19
20
A.Yes.The load forecast incorporates changes to
mathematical relationships for conservation programs,
changes in electricity prices, and other factors.As
21 efficiency standards for building shells, motors, glazing,
22 appliances and lighting have changed over time, they are
23 incorporated in the forecast. Net growth in Avista i s load
24 occurs not only by newly constructed buildings, but also by
Kalich, Di 19
Avista Corporation
1 increases and decreases in the amount of equipment or
2 intensity of use of the existing customer base.
3 Q.How do 2009 pro form period loads compare with
4 recent results?
5 A.Chart No. 5 shows historical and forecast utility
6 load changes. As the table illustrates, our 2008 forecast
7 of retail load follows a trend line consistent with recent
8 history.
9 Chart No. 5 - System Loads Absent potlatch cogeneration
1,075 -....... -_.__."-,._-----.._.._-'..,.....'-----.-.. ..__.-,'--'-'--'.'--'-'--'-'---- --_..._....._..__....._----_.._--,._-~-- - - '. ."."--,.__.., ..._- ....._.. ..-.."-
2008 LoadForecast,¥
,.
1,050
i 1,025
l 1,000 Weather-AdjustedHistorial Load
975
950
2003 2004 2005 2006 2007 2008 2009
10
11 Q.What is the significance of using the forecasted
12 pro form load estimate for ratemking purposes?
13
14
15
A.Chart No. 6 builds on information presented in
Chart NO.5.It illustrates why 2007 load levels should
not be used to set rates for calendar year 2009:using
16 2007 weather-adjusted actual loads would assume the Company
17 will experience no load growth for two calendar years.
Kalich, Di 20
Avista Corporation
1 This would be at odds with recent history and any
2 reasonable load growth assumption, especially given the
3 continued growth in the economy in our Company's service
4 area.Pro forma load levels will be approximately 28 aM
5 above 2007 historical loads.
6 Chart No.6-System Loads Absent Potlatch Cogeneration,
7 with 2007 Load
1,075
1,050
I
1,025
l 1,000
975
950
8
9
2008 Load ,"Forecast _~- ' 27.8.' _ ... aMW----
2007 Load Level
Weather-Adjusted
Historial Load
2003 2004 2005 2006 2007 2008 2009
10 loads get tracked through the Power Cost Adjustment (PCA)
Q.Does the difference between pro form and actual
11 mechanism?
12 A.Yes.As explained more fully by Mr. Johnson,
13 when actual 2009 loads differ from the pro forma, the
14 difference between the two values is tracked through the
15 PCA, with additional or reduced sales being adjusted
16 through the Retail Revenue Credit.
Kalich, Di 21
Avista Corporation
1 The use of 2009 pro forma loads in this case, together
2 with the production property adjustment (discussed by
3 Company witness Ms. Knox), provides a more accurate basis
4 to set retail rates for the period that new retail rates
5 will be in effect.
6 Q.What is the Company's present loads and resources
7 position?
8 A.The Company's latest energy and capacity loads
9 and resources tabulations ("L&Rs") are attached in Exhibit
10 No.5, Schedule 1.As the L&Rs show, 2009 loads are
11 expected to equal 1,118.5 aM. For this filing the figure
12 is reduced by the 5-year average of self-generation of the
13 Potlatch Corporation. This adjustment lowers the pro forma
14 load to 1,061.2 aM.
15 Chart No. 7 below details the Company's load and
16 resource energy position from 2009 through 2018. The chart
17 excludes 57.3 aM of Potlatch load, as well as its 57.3 aM
18 of PURPA generation.
Kalich, Di 22
Avista Corporation
1 Chart No. 7 - Avista 2009-2018 Load and Resource Energy
2 Posi tion (aM)
1,800
1,600
1
1,400
1,200
1,000
l
800
600
400
200
0
~
0 ,.N M o:It (Ø "'co
~~~~~~~~~
3
4 Chart No. 8 presents the Company's load and resource
5 capacity position from 2009 through 2018.As wi th Chart
6 No.7, a 57. 3-MW reduction is applied both to load and
7 contracts to reflect Potlatch.
8 Chart No. 8 - Avista 2009-2018 Load and Resource Capacity
9 Posi tion (MW)
2,500
2,250
2,000
1,750
l 1,500
1,250
1,000
750
500
250
0
~
0 ,.N M o:an CD "'co
10 ~~~~~~~~~
Kalich, Di 23
Avista Corporation
1
2
iv. RESULTS
Q.Please sumrize the results from the Dispatch
3 Model that are used for ratemking.
4
5
A.The Dispatch Model tracks the Company's portfolio
during each hour of the pro forma study.Fuel costs and
6 generation for each resource are sumarized by month.
7 Total market sales and purchases, and their revenues and
8 costs, are also determined and sumarized by month. These
9 values are contained in Exhibit No.5, Schedule 2 and was
10 provided to Mr. Johnson for use in his calculations.Mr.
11 Johnson adds resource and contract revenues and expenses
12 not accounted for in the Dispatch Model (e.g., fixed costs)
13 to determine net power supply expense.
14 Q.Company witness Mr. Morris explains in his pre-
15 filed testimony that the Company has included a special
16 "rate mitigation adjustment" to power supply expenses. How
17 did you account for this adjustment in your results?
18 A.As Mr. Morris explains in his testimony, the
19 purpose of this adjustment is to reduce the overall rate
20 increase resulting from this rate filing.
21 The "rate mitigation adjustment" is achieved through
22 increasing the amount of hydroelectric energy available to
23 the Company in the Dispatch Model during the proforma
24 period.Exhibit No.5, Schedule 2 contains an "Avista
25 Hydro Adjustment" of 26.5 aM, as can be seen on line 23 of
Kalich, Di 24
Avista Corporation
1 the applicable page.This energy is included in the
2 proforma at zero cost, thereby increasing the Company's
3 energy sales into the wholesale marketplace.The total
4 cost reduction is $12.8 million on a system basis.
5 During the period that new retail base rates will be
6 in place from this general rate case, 90% of this
7 mitigation adjustment will be tracked through the PCA, and
8 the Company will absorb 10%.
9 Q.Does this conclude your pre-filed direct
10 testimony?
11 A.Yes, it does.
Kalich, Di 25
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL, REGULATORY ~nÛaAPR -3 Pi'U2 SS
GOVERNENTAL AFFAIRS
AVISTA CORPORATIONP.O. BOX 3727 ION
1411 EAST MISSION AVENE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-08-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AN CHAGES FOR ELECTRIC AN )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 5
AN NATURA GAS CUSTOMERS IN THE )STATE OF IDAHO ) CLINT G. KAICH
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Exhibit 5
Avista Utities Loads and Resources Position-Energy Tabulation
AVERAGE LOAD & HYDRO PLANNING
REQUIREMENTS 2009 ~2011 2012 2013 2014 2015 2016 2017 2018--------
1 System Load -1,118 -1,141 -1,161 -1,182 -1,202 -1,229 -1,274 -1,299 -1,316 -1,333
2 Contract Obligations -141 -140 -140 -139 -139 -139 -64 -64 -12 -12
3 Total Requirements -1,259 -1,281 -1,300 -1,322 -1,342 -1,369 -1,338 -1,364 -1,328 -1,345
RESOURCES
4 Contract Rights 387 625 542 508 516 495 441 431 389 366
5 Hydro 537 523 521 505 505 505 505 505 505 502
6 Thermal Resources 522 523 523 522 521 537 512 521 523 514
7 Total Resources 1,447 1,671 1,586 1,535 1,543 1,536 1,459 1,457 1,417 1,382
8
CONTINGENCY PLANNING
9 Contingency Total -191 -191 -191 -187 -187 -187 -187 -187 -187 -187
10 Peaking Resources 142 142 142 142 133 142 142 142 142 142
11ICON11NGENCXNETPOSITI(lN 139 341 237 168 147 123 76 49 .44 -81
A vista Utities Loads and Resources Position-Capacity Tabulation
PEAK LOAD AND RESOURCE PLANNING
REQUIREMENTS
1 Native Load
2 Contracts Obligations
3 Total Requirements
2009 2010 2011 ~ ~ 2014 2015 2016 ~ 2018
-1,764 -1,800 -1,831 -1,865 -1,900 -1,944 -2,010 -2,052 -2,081 -2,109
-242 -242 -242 -242 -242 -242 -167 -167 -17 -17
-2,006 -2,042 -2,073 -2,107 -2,141 -2,186 -2,177 -2,218 -2,097 -2,125
RESOURCES
4 Contracts Rights
5 Hydro Resources
6 Base Load Thermals
7 Peaking Units
8 Total Resources
427
971
602il
2,210
708
1,013
597
211
2,529
608
917
602il
2,336
590
989
602
211
2,391
590
1,003
602
211
2,406
590
1,003
602
211
2,406
515
1,003
602
211
2,331
515
1,003
602il
2,331
515
976
602
211
2,303
515
1,003
602il
2,33191_",_11I1--1u___
RESERVE PLANNING
1 0 Planning Reserve Margin
111RESERVEPEA POSITION
-266 -270 -273 -277 -280 -284 -291 -295 -298 -301
-63 217 .9 8 .16 -65 .137 .183 -92 ,.961
Exhbit No. 5
Case No. A VU-E-08-01
C. Kalich, A vista
Schedule 1, p. 1 of 1
Exhibit 5
AURORAXM Summary Output-Project Generation (GWh)
6i .i fm .r åR b iI .i &i ~g¡~J2
Hydro Project
Clark Fork 2,838.1 181.8 190.7 174.3 262.5 479.0 485.3 335.6 181.7 119.7 103.9 118.205.
Cabinet Gorge 912.3 58.5 61.3 56.0 84.4 154.0 156.0 107.9 58.4 38.5 33.4 38.1 65.9
Noxon Rapids 1,925.8 123.129.4 118.3 178.1 325.0 329.3 227.7 123.3 81.2 70.5 80.4 139.1
TOTAL 2,838.1 181.8 190.7 174.3 262.5 479.0 485.3 335.6 181.7 119.7 103.9 118.6 205.0
Spokane River 1,113.0 104.1 97.5 120.1 123.6 127.6 113.8 73.8 41.0 56.1 71.5 86.3 97.6
Lilie Falls 223.7 20.9 19.6 24.1 24.8 25.6 22.9 14.8 8.2 11.3 14.4 17.3 19.6
Long Lake 445.5 41.7 39.0 48.1 49.5 51.1 45.5 29.5 16.4 22.5 28.6 34.5 39.1
Monroe Street 92.1 8.6 8.1 9.9 10.2 10.6 9.4 6.1 3.4 4.6 5.9 7.1 8.1
Nine Mile 176.5 16.5 15.5 19.0 19.6 20.2 18.0 11.7 6.5 8.9 11.3 13.7 15.5
Post Falls 111.8 10.5 9.8 12.1 12.4 12.8 11.4 7.4 4.1 5.6 7.2 8.7 9.8
Uppe Falls 63.4 5.9 5.6 6.8 7.0 7.3 6.5 4.2 2.3 3.2 4.1 4.9 5.6
TOTAL 1,113.0 104.1 97.5 120.1 123.6 127.6 113.8 73.8 41.0 56.1 71.5 86.3 97.6
Mid-Colmbia- Contrcts 602.2 69.3 51.1 45.8 55.9 65.8 71.3 67.5 48.8 37.3 43.7 21.1 24.7
Prst Rapids 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rocky Reach 178.6 19.3 13.3 12.0 15.8 16.7 19.1 18.7 16.0 10.1 11.7 12.0 14.0
Wanapum 288.3 35.9 27.6 24.6 29.1 35.1 37.9 34.8 20.6 19.5 23.1 0.0 0.0
Wells 135.3 14.1 10.2 9.1 11.0 14.0 14.3 13.9 12.2 7.7 8.9 9.1 10.7
TOTAL 602.2 69.3 51.1 45.8 559 65.8 71.3 67.5 48.8 37.3 43.7 21.1 24.7
lvista Hydro Adjustment 232.3 18.3 17.3 17.3 22.3 33.5 33.5 24.1 13.8 10.9 11.3 12.3 17.6
TOTAL 4,785.7 373.5 356.7 357.4 464.3 705.9 703.9 501.0 285.4 224.1 230.4 238.2 34.9
Thermals
Bolder Park 6.5 0.2 0.2 0.1 0.5 0.5 0.2 1.2 1.8 1.4 0.2 0.1 0.1
Colstr 1,729.7 155.5 142.9 152.2 126.0 105.8 115.9 154.7 158.1 152.9 156.9 153.1 155.6
Coyote Spóngs 2 1.298.5 77.2 88.7 84.5 67.3 46.9 51.2 120.2 166.2 159.9 153.9 159.2 123.2
Kettle Falls 333.5 32.1 31.1 34.0 32.3 1.1 0.0 31.8 34.8 33.1 35.0 33.9 34.5
Kettle Falls CT 5.0 0.1 0.1 0.1 0.3 0.3 0.2 0.9 1.3 1.1 0.3 0.2 0.1
Norteast 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rathdnim 15.7 0.0 0.0 0.0 0.1 0.2 0.1 6.6 7.7 0.5 0.5 0.0 0.0
TOTAL 3,388.265.2 263.2 271.0 226.4 154.9 167.6 315.3 369.9 348.8 346.6 346.6 313.5
RESOURCE TOTAL 7,942.2 620.4 602.5 611.1 668.5 827.3 837.9 792.2 641.5 561.9 565.7 572.5 64.8 I
Contracts
Black Creek 3.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.7 0.0 0.0
DOPD 33.6 1.9 1.8 2.6 3.8 4.9 5.1 3.9 3.0 1.6 1.9 1.6 1.6
Market Contrct 1 219.0 18.6 16.8 18.6 18.0 18.6 18.0 18.6 18.6 18.18.6 18.0 18.6
Can Ent Return (35.9)(3.1)(2.8)(3.0)(3.0)(3.0)(3.0)(3.1)(3.0)(3.0)(3.1)(2.9)(3.1)
Grant County 155.6 16.0 12.0 10.0 8.9 6.7 9.4 10.7 10.4 8.9 10.3 23.7 28.5
Clark Fork LLC 1.4 0.1 0.1 0.1 0.2 0.2 0.2 0.1 0.1 0.0 0.0 0.1 0.1
Market Contract 2 657.0 55.8 50.4 55.8 54.0 55.8 54.0 55.8 55.8 54.0 55.8 54.0 55.8
Grant Displacement 194.1 13.0 11.8 13.1 18.23.7 22.8 20.5 14.6 13.7 13.9 13.9 14.3
Stmson Lumber 37.2 3.2 3.0 3.4 3.1 2.9 2.8 3.1 3.3 3.2 3.1 3.2 2.9
Ji m Ford Creek 3.7 0.5 0.6 0.8 0.7 0.4 0.2 0.0 0.0 0.0 0.0 0.2 0.4
John Day Creek 2.0 0.1 0.0 0.1 0.1 0.4 0.4 0.3 0.2 0.1 0.1 0.1 0.1
Meyers Falls 7.8 0.7 0.8 0.9 0.9 1.0 0.8 0.5 0.2 0.3 0.4 0.6 0.6
Nichols Pumping (67.9)(5.8)(5.2)(5.8)(5.6)(5.8)(5.6)(5.8)(5.8)(5.6)(5.8)(5.6)(5.8)
PGECapExch 1.8 (0.3)0.0 0.9 (0.3)0.9 0.0 (0.6)0.6 (0.3)0.3 1.2 (0.6)
Philips Ranch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
PoUatch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Wind Contract 69.3 6.2 4.6 6.6 5.8 6.1 6.9 6.1 6.2 5.6 6.0 6.4 2.7
Load F oIlowin g Contra ct 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Sheep Creek 7.3 0.4 0.5 0.9 1.1 1.2 1.1 0.7 0.2 0.2 0.2 0.4 0.4
Uprier 52.2 5.6 6.3 7.3 7.6 7.7 5.8 1.9 (1.6)0.6 2.3 3.1 5.6
WNp.3 368.7 76.1 68.8 37.6 36.4 0.0 0.0 0.0 0.0 0.0 0.0 73.7 76.1
ST Purchases 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
SMUD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Thompson River Co-Gen 92.2 8.4 7.7 8.4 7.0 6.9 5.4 8.3 8.5 8.2 7.6 7.4 8.5
TOTAL 1,803.0 197.5 177.1 158.5 157.7 128.6 124.4 121.0 111.4 105.6 115.6 198.9 20.7
Market Transactions
Market Purchases 744.7 137.8 61.2 67.9 19.7 4.1 5.3 25.9 61.6 75.8 107.0 82.6 95.9
Market Sales (1426.5\(37.6\(57.5\(81.8\119.0\(300.3\(30.01 (174.9\(69.0\(62.9\(49.8\(66.3\(47.3\
TOTAL (681.7)100.2 3.7 (13.9)(159.4)(296.2)(294.7)(149.0)(7.5)12.9 57.2 16.3 48.6
SYSTEM LOAO 9,295.8 936.4 800.7 n3.0 689.1 693.2 701.2 788.3 759.2 691.4 749.8 800.0 913.7
Exhbit No. 5
Case No. A VU-E-08-01
C. Kalich, Avista
Schedule 2, p. 1 of 3
Exhibit 5
AURORAXM Summary Output-Project Generation (aMW
å!.!f!M!A2 .r ii :W A!.§2!.t !l
Hydro Projects
Clark Fork 324.0 244.4 283.9 234.3 364.6 643.8 674.0 451.1 244.3 166.3 139.6 164.7 275.5
Cabinet Gorge 104.1 78.6 91.2 75.3 117.2 206.216.7 145.0 78.5 53.4 44.9 52.9 88.6
Noxon Rapids 219.8 165.8 192.6 159.0 247.4 436.8 457.3 306.1 165.8 112.8 94.7 111.7 186.9
TOTAL (aMW) 324.0 244.4 283.9 234.3 364.6 643.8 674.0 451.1 244.3 166.3 139.6 164.7 275.5
Spokane Rive 127.1 139.9 145.1 161.4 171.7 171.5 158.0 99.2 55.1 78.0 96.1 119.8 131.2
liie Falls 25.5 28.1 29.2 32.4 34.5 34.5 31.8 19.9 11.1 15.7 19.3 24.1 26.4
Long Lake 50.9 56.0 58.1 64.6 68.7 68.7 63.2 39.7 22.1 31.2 38.5 48.0 52.5
Monroe Steet 10.5 11.6 12.0 13.4 14.2 14.2 13.1 8.2 4.6 6.5 8.0 9.9 10.9
Nine Mile 20.1 22.2 23.0 25.6 27.2 27.2 25.1 15.7 8.7 12.4 15.2 19.0 20.8
Post Falls 12.8 14.1 14.6 16.2 17.3 17.2 15.9 10.0 5.5 7.8 9.7 12.0 13.2
Upper Falls 7.2 8.0 8.3 9.2 9.8 9.8 9.0 5.6 3.1 4.4 5.5 6.8 7.5
TOTAL (aMW) 127.1 139.9 145.1 161.4 171.7 171.5 158.0 99.2 55.1 78.0 96.1 119.8 131.2
Mid-Colmbia- Conacts 68.7 93.1 76.0 61.5 77.6 88.4 99.1 90.7 65.6 51.8 58.7 29.3 33.2
Priest Rapids 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rocky Reach 20.4 25.9 19.8 16.1 21.9 22.5 26.25.2 21.5 14.0 15.7 16.6 18.8
Wanapum 32.9 48.3 41.1 33.1 40.4 47.2 52.7 48.8 27.7 27.1 31.0 0.0 0.0
Wells 15.4 18.9 15.2 12.3 15.3 18.8 19.8 18.7 16.4 10.7 12.0 12.7 14.4
TOTAL (aMW) 68.7 93.1 76.0 61.5 776 88.4 99.1 90.7 65.6 51.8 58.7 29.3 33.2
lvista Hydro Adjustment 26.5 24.6 25.8 23.2 30.9 45.0 46.6 32.4 18.6 15.2 15.2 17.1 23.6
TOTAL 546.3 502.1 530.7 480.4 644.8 948.7 977.7 673.4 383.6 311.2 309.6 330.9 463.6
Thennals
Bou Ider Park 0.7 0.2 0.4 0.1 0.7 0.7 0.3 1.7 2.4 1.9 0.2 0.1 0.1
Colstrip 197.5 209.0 212.6 204.6 175.0 142.2 161.0 207.9 212.5 212.4 210.9 212.6 209.2
Coyote Spnngs 2 148.2 103.8 132.0 113.93.5 63.1 71.1 161.5 223.4 222.1 206.8 221.2 165.5
Kettle Falls 38.1 43.2 46.4 45.7 44.8 1.5 0.0 42.7 46.7 46.0 47.0 47.1 46.3
Kele Falls CT 0.6 0.2 0.2 0.2 0.4 0.4 0.2 1.2 1.7 1.5 0.3 0.3 0.2
Northeast 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rathrum 1.8 0.0 0.0 0.0 0.1 0.3 0.1 8.9 10.3 0.6 0.7 0.1 0.0
TOTAL 386.9 356.4 391.6 364.2 314.5 208.2 232.7 423.8 497.1 484.5 465.9 481.3 421.3
RESOURCE TOTAL 906.6 833.8 896.821.4 928.4 1,111.9 1,163.8 1,064.8 862.2 780.5 760.3 795.1 861.3
Contracts
Black Creek 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.0 0.0 0.0
DOPO 3.8 2.6 2.6 3.5 5.3 6.6 7.1 5.2 4.1 2.2 2.5 2.2 2.1
Market Contract 1 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0
can Ent Return (4.1)(4.2)(4.1)(4.0)(4.1)(4.0)(4.1)(4.2)(4.0)(4.1)(4.2)(4.0)(4.2)
Grant County 17.8 21.6 17.9 13.5 12.4 9.0 13.1 14.4 13.9 12.4 13.9 32.9 38.3
Clark Fork LLC 0.2 0.1 0.2 0.1 0.3 0.3 0.3 0.2 0.1 0.1 0.1 0.1 0.1
Market Co ntract 2 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0
Grant Displacement 22.2 17.5 17.5 17.6 26.2 31.8 31.6 27.6 19.7 19.0 18.7 19.3 19.2
Stimson Lumber 4.2 4.3 4.5 4.6 4.3 3.9 3.9 4.1 4.4 4.5 4.1 4.4 3.9
Jim Ford Creek 0.4 0.7 0.8 1.1 1.0 0.5 0.2 0.0 0.0 0.0 0.0 0.2 0.5
John Day Creek 0.2 0.1 0.0 0.1 0.1 0.5 0.6 0.4 0.2 0.2 0.2 0.2 0.1
Meyers Falls 0.9 1.0 1.2 1.3 1.3 1.3 1.2 0.6 0.3 0.4 0.6 0.9 0.8
Nichols Pumping (7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)
PGECapExch 0.2 (0.4)0.0 1.2 (0.4)1.2 0.0 (0.8)0.8 (0.4)0.4 1.7 (0.8)
Philip Ranch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Potlatch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Wind Contract 7.9 8.3 6.9 8.9 8.1 8.2 9.6 8.1 8.4 7.8 8.1 8.9 3.7
Load Following Contracts 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Sheep Creek 0.8 0.5 0.7 1.2 1.6 1.6 1.6 1.0 0.3 0.2 0.3 0.5 0.5
Upriver 6.0 7.5 9.4 9.8 10.6 10.4 8.0 2.5 (2.1)0.9 3.1 4.2 7.5
WNP-3 42.1 102.3 102.3 50.5 50.5 0.0 0.0 0.0 0.0 0.0 0.0 102.3 102.3
ST Purchases 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
SMUD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Thompson River Co-Gen 10.5 11.3 11.4 11.3 9.7 9.3 7.5 11.2 11.4 11.4 10.3 10.3 11.4
TOTAL 205.8 265.4 263.6 213.0 219.0 172.9 172.8 162.7 149.7 146.7 155.4 276.2 277.9
Mar\et Transactions
Market Purchases 85.0 185.2 91.0 91.2 27.3 5.6 7.4 34.8 82.7 105.3 143.8 114.8 128.9
Market Sales (162.8)(50.5)(85.5)(110.0)(248.7)(403.7)(416.6)(235.1)(92.8)(87.4)(66.9)(92.1)(63.5)
TOTAL (17.8)134.7 5.5 (18.7)(221.3)(398.1)(409.3)(200.3)(10.)17.9 76.9 22.7 65.4
Sytem Load 1,061.2 1,258.5 1,191.5 1,038.9 957.0 931.7 973.9 1,059.6 1,020.4 960.2 1,007.8 1,111.1 1,228.1
Exhbit No. 5
Case No. A VU-E-08-01
C. Kalich, Avista
Schedule 2, p. 2 of 3
Exhibit 5
AURORAXM Summary Output-Project Costs ($OOOs)
&!.w .E Mi &i li .i .i ål bi .2 ~~
Hyro Projecs
Clark Fork 0 0 0 0 0 0 0 0 0 0 0 0 0
Cabinet Gorge 0 0 0 0 0 0 0 0 0 0 0 0 0
Noxon Rapids 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
SpokaneRi_0 0 0 0 0 0 0 0 0 0 0 0 0
Ulle Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
Long Lake 0 0 0 0 0 0 0 0 0 0 0 0 0
Monroe Street 0 0 0 0 0 0 0 0 0 0 0 0 0
Nine Mile 0 0 0 0 0 0 0 0 0 0 0 0 0
Post Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
Upper Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
Mid-Columbia- Contracts 0 0 0 0 0 0 0 0 0 0 0 0 0
Priest Rapids 0 0 0 0 0 0 0 0 0 0 0 0 0
Rocky Reach 0 0 0 0 0 0 0 0 0 0 0 0 0
Wanapum 0 0 0 0 0 0 0 0 0 0 0 0 0
Wells 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
Avlsta Hydro Adjustment 0 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
Thennals
Sou Idar Park 468 14 20 7 38 36 13 88 129 98 12 7 7
Coltrip 19,388 1,742 1,600 1,705 1,411 1,189 1.307 1,734 1,771 1,713 1,757 1,714 1.743
Coyte Spnngs 2 70,663 4.576 5,248 4,875 3,455 2,398-2,647 6,297 8,722 8,400 8,112 8,788 7.146
Kettle Falls 11,811 1,143 1,102 1,202 1,145 41 0 1,130 1,228 1,171 1,234 1,196 1,219
Kettle Falls cT 354 9 11 9 20 21 12 60 90 76 18 18 10
Norteast 0 0 0 0 0 0 0 0 0 0 0 0 0
Rathdrum 1.373 0 3 0 5 19 7 578 676 41 40 4 0
TOTAL 104,056 7,485 7,984 7,798 6,074 3,705 3,986 9,887 12,617 11,498 11,173 11,727 10,125
RESOURCE TOTAL 104,056 7,485 7,984 7,798 6,074 3,705 3,986 9,887 12,617 11,498 11,173 11,7ZT 10,125
Contracts
Black Creek 197 0 0 0 0 0 0 0 0 0 197 0 0
DOPD 737 42 38 57 83 108 111 85 66 35 42 35 35
Market Contract 1 7,556 642 580 642 621 642 621 642 642 621 642 621 642
Can Ent Return 0 0 0 0 0 0 0 0 0 0 0 0 0
Grant County 8,473 818 663 525 408 274 333 547 612 491 552 1,498 1,751
Clark Fork LLC 117 9 10 9 16 17 17 11 6 4 3 6 9
Market Contrct 2 20,192 1,715 1,549 1.715 1,660 1,715 1,660 1,715 1,715 1,660 1,715 1,660 1,715
Grant Displacement 5.824 389 354 394 565 711 683 616 439 410 418 416 429
Stimson Lum ber 2,079 194 182 159 145 136 131 186 196 195 185 193 177
Ji m Ford Creek 234 44 49 37 32 18 7 0 0 0 1 15 32
John Day Creek 82 4 2 3 3 12 14 11 7 6 5 8 6
Meyers Falls 375 35 38 45 44 46 40 22 10 13 21 30 30
Nichols Pumping (3.394)(291)(284)(296)(253)(237)(201)(291)(327)(299)(296)(307)(312)
PGECapExeh 0 0 0 0 0 0 0 0 0 0 0 0 0
Philips Ranch 1 0 0 0 0 0 1 0 0 0 0 0 0
Potlatch 0 0 0 0 0 0 0 0 0 0 0 0 0
Win d Cont ra ct 2,743 245 182 262 230 242 275 240 247 222 238 253 108
Load Following Cotract 0 0 0 0 0 0 0 0 0 0 0 0 0
Sheep Creek 426 27 34 51 54 51 45 43 23 19 22 30 29
Upriver 2,017 246 277 249 262 264 197 83 (68)28 101 134 245
WNP-3 13,333 2.753 2,487 1,359 1,316 0 0 0 0 0 0 2,664 2,753
ST Purch ases 0 0 0 0 0 0 0 0 0 0 0 0 0
SMUD (8,561)(737)(574)(652)(658)(836)(987)(828)(688)(666)(661)(609)(664)
Thom pson River Co-Gen 5,119 466 425 467 387 382 301 461 470 455 424 410 471
TOTAL 57,55 6,602 6,012 5,025 4,915 3,545 3,247 3,543 3,350 3,194 3,610 7,056 7,456
Market Transactions
Market Purchases 51,397 8,817 4,175 4,464 1,274 296 334 2,134 5.110 5,586 7,105 5.625 6,476
Market Sales (65,050)(2,046)(3,382)(4,426)(8,207) (12,494)(10,414)(8,31)(3,643)(3,056)(2,496)(3,771)(2,684)
TOTAL (13,653)6,772 793 38 (6,933) (12, 198)(10,079)(6,297)1,467 2,530 4,609 1,854 3,792
I Fuel and Market Only 90,403 14,256 8,777 7,835 (859)(8,493)(6,093)3,590 14,084 14,OZT 15,782 13,581 13,9161
Fuel Transport Adjustment (1,748)(123)(140)(135)(85)(60)(65)(151)(207)(198)(189)(226)(170)
Startu p Fuel Adu stm en!482 52 36 41 37 23 39 75 52 23 46 37 21
Total 89,137 14,185 8,673 7,740 (906)(8,530)(6,119)3,514 13,929 13,852 15,39 13,392 13,768
Exhbit No. 5
Case No. A VU-E-08-01
C. Kalich, Avista
Schedule 2, p. 3 of 3