HomeMy WebLinkAbout20090123Kalich Direct.pdfDAVID J. MEYER
VICE PRESIDENT AN CHIEF COUNSEL OF
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220 - 3 7 2 7TELEPHONE: (509) 495-4316FACSIMILE: (509) 495-8851
\f ()
(009 JMl 23 Pl112: 4 t
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AN CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AN NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-09-01
DIRECT TESTIMONY
OF
CLINT G. KALICH
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I. INTRODUCTION
Q.Please state your name, the name of your
3 employer, 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 management.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.
Kalich, Di 1
Avista Corporation
1 In late 1995,I left Economic and Engineering
2 Services, Inc. to join Tacoma Power in Tacoma, Washington.
3 i provided key analytical and policy support in the areas
4 of resource development, procurement, and optimization,
5 hydroelectric operations and re-licensing, unbundled power
6 supply ra te-making ,contract negotiations,and system
7 operations.I helped develop, and ultimately managed,
8 Tacoma Power's industrial market access program serving
9 one-quarter of the company's retail load.
10 In mid-2000 I joined Avista Utilities and accepted my
11 current position assisting the Company in resource
12 analysis,dispatch modeling,resource procurement,
13 integrated resource planning, and rate case proceedings.
14 Much of my career has involved resource dispatch modeling
15 of the nature described in this testimony.
16 Q.What is the scope of your testimony in this
17 proceeding?
18 A.My testimony will describe the Company's use of
19 i willthe AURO~ dispatch model, or "Dispatch Model. 11
20 explain the key assumptions driving the Dispatch Model's
21 market forecast of electricity prices.The discussion
22 includes the variables of natural gas, Western Interconnect
23 loads and resources, and hydroelectric conditions.I will
24 describe how the model dispatches our resources and
25 contracts in a manner that maximizes benefits to customers
Kalich, Di 2
Avista Corporation
1 and tracks their values for use in pro forma calculations.
2 Finally, i will present the modeling results provided to
3 Company Witness Mr. Johnson for his power supply pro forma
4 adjustment calculations.
5 Q.Are you sponsoring any exhibits in this
6 proceeding?
7 A.Yes.I am sponsoring Exhibit No.5, Schedules 1
8 and 2. Schedule 1 provides a forecast of Company load and
9 resource positions from 2009 through 2019.Schedule 2
10 provides sumary output from the Dispatch Model.All
11 information contained in the exhibits was prepared under my
12 direction.
13
14
15
II. THE DISPATCH MODEL
Q.What model is the Company using to dispatch its
16 portfolio of resources and obligations?
17
18
A.The Company uses EPIS, Inc.' s Dispatch Model for
determining power supply cos ts .The model optimizes
19 dispatch of Company-owned resources and contracts in each
20
21
hour of the pro forma year.The pro forma period is JUlY
1, 2009 through June 30, 2010.It reflects true system
22 operations by evaluating future resource decisions on an
23 hourly basis.
24 Q.What AURORA version and database is the Company
25 using for this case?
Kalich, Di 3
Avista Corporation
1 A.The Company is using AURO~ version 9.3.1004,
2 and the latest available database for it
3 (North_American_DB_2008-03) .
4
5
6
Q.Please briefly describe the Dispatch Model.
A.The Dispatch Model was developed by EPIS, Inc. of
Sandpoint,Idaho.It is a fundamentals-based tool
7 containing demand and resource data for the entire Western
Interconnect.It employs mul ti -area,transmission-8
9 constrained dispatch logic to simulate real market
10 condi tions .Its true economic dispatch captures the
11 dYnamics and economics of electricity markets-both short-
12 term (hourly, daily, monthly) and long-term. On an hourly
13 basis the Dispatch Model develops an available resource
14 stack, sorting resources from lowest to highest cost.It
15 then compares this resource stack with load obligations in
16 the same hour to arrive at the least-cost market-clearing
17 price for the hour.Once resources are dispatched and
18 market prices are determined, the Dispatch Model singles
19 out Avista resources and loads and values them against the
20 marketplace.
21 Q.What experience does the Company have using
22 AURO~?
23
24
A.The Company purchased a license to use the
Dispatch Model in April 2002.AURO~ has been used for
25 numerous studies, including the Company's 2003, 2005, 2007,
Kalich, Di 4
Avista Corporation
1 2009 integrated Resource Plans ("IRPs"), our 2005, 2007,
2 and 2008 rate filings in the State of Washington and our
3 2004 and 2008 general rate case filings before this
Commission.The tool is also used for various resource4
5 evaluations,market forecasting,and requests for
6 proposals.
7
8
Q.Who else uses AURO~?
A.AURO~p is used all across North America.In
9 the Northwest specifically, AURO~ is used by the
10 Bonneville Power Administration, the Northwest Power and
11 Conservation Council, Puget Sound Energy, Idaho Power,
12 Portland General Electric, Seattle City Light, Grant County
13 PUD, Snohomish County PUD, and Tacoma Power, among others.
14 Q.What benefits does the Dispatch Model offer for
15 this type of analysis?
16 A.The Dispatch Model generates hourly electricity
17 prices across the Western Interconnect, accounting for its
18 specific mix of resources and loads.The Dispatch Model
19 reflects the impact of regions outside the Northwest on
20
21
Northwest market prices,limited by known transfer
(transmission) capabilities.Ul timately, the Dispatch
22 Model allows the Company to generate price forecasts in-
23 house instead of relying on exogenous forecasts.
24 The Company owns a numer of resources, including
25 hydroelectric plants and natural gas-fired peaking units,
Kalich, Di 5
Avista Corporation
1 which serve customer loads during more valuable on-peak
2 hours.By optimizing resource operation on an hourly
3 basis, the Dispatch Model is able to appropriately value
4 the capabilities of these assets. For example, actual 2008
5 on-peak prices through mid-December were 23% higher than
6 off-peak prices.In 2007 the difference was 25%. Forward
7 prices for 2010 were 28% at the time this case was
8 prepared.For comparison, Dispatch Model on-peak prices
9 for the pro forma period average 28% higher than off-peak
10 prices.In sumary, the Dispatch Model appropriately
11 values the energy from Avista' s resources during on-peak
12 periods in a manner similar to that recently experienced in
13 the Northwest region.
14 Q.On a broader scale, what calculations are being
15 perfor.ed 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 with available
5 resources to determine a net position.This net position
6 is balanced using the simulated wholesale electricity
7 market. The cost of energy purchased from or sold into the
8 market is determined based on the electric market-clearing
9 price for the specified hour and the amount of energy
10 necessary to balance loads 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 resource in the stack to be dispatched.This resource is
23 referred to as the "marginal resource. 11 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 electrici ty prices.
3 Q.How does the Dispatch Model operate regional
4 hydroelectric projects?
5
6
A.The model begins by "peak shaving
11 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 Company 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 proj ected 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 wi th Northwes t Power Pool data.
19 Q.Please describe your update to pro for.a period
20 natural gas prices.
21 A.Natural gas prices for this filing are based on a
22 3-month average from September 1, 2008 to November 30, 2008
23 of July 2009 through June 2010 monthly forward prices.
24 Natural gas prices used in the Dispatch Model are
25 presented below in Table No 1.
Kalich, Di 8
Avista Corporation
1 Table No. i - Pro For.a Natural Gas Prices
Price Price
Basin ($/dth)Basin ($/dth)
AECO 7.31 Stanfield 7.67
Malin 7.75 Sumas 7.83
Spokane 8.03 Henry Hub 8.08
Rockies 5.59 Topock 7.49
2
3 Q.What hYdro record is the Company using in this
4 filing?
5
6
A.The Company bases this case on the 50-year
hydrological record beginning in 1929.Da ta are sourced
7 from the Northwest Power Pool's (NWPP) 2006-07 Headwater
8 Benefits Study. This study is the latest available.
9 Q.What is the Company's assumption for rate period
10 loads?
11 A.Rate period loads (July 2009 through June 2010)
12 used in this case are taken from the Company's 2009 load
13 forecast completed in July 2008. As this load is generated
14 using "normal weather, 11 it eliminates the need for a
15 weather-normalization adjustment.The Company's latest
16 energy and capacity loads and resources tabulations (L&Rs)
17 are attached in Exhibit No.5, Schedule 1.As the L&Rs
18 show, system loads are expected to equal 1,134 aMW
19 including a large co-generator's entire load.For this
20 filing, system loads are reduced by 49 aM of co-generation
21 by the large industrial customer load located in Idaho.
22 This adjustment lowers the rate period loads to 1,085 aMW.
Kalich, Di 9
Avista Corporation
1 Q.How does the Dispatch Model Operate Company-
2 controlled hydroelectric generation resources?
3 A.The Dispatch Model treats all hydroelectric
4 generation plants wi thin a load area as a single large
5 plant. The Company's hydroelectric plants are on average,
6 however, more flexible than the average plant used in each
7 load area. To account for this additional flexibility, the
8 Company algebraically extracts its plants from the region
9 and develops individual hydro operations logic for them.
10 Company-controlled hydroelectric resources are separated
11 into three river systems:the Spokane Ri ver , the Clark
12 Fork River, and individually separate the Mid-Columia
13 projects.This separation ensures that the flexibility
14 inherent in these resources is credited to customers in the
15 pro forma exercise.
16 Q.Please compare the operating statistics from the
17 Dispatch Model to recent historical hydroelectric plant
18 operations.
19 A.Over the pro forma period the Dispatch Model
20 generates 70% of Clark Fork hydro generation during on-peak
21 hours (based on average water).Since on-peak hours
22 represent only 57% of the year, this demonstrates a
23 substantial shift of hydro resources to the more expensive
24 on-peak hours. This is identical to the 5-year average of
25 on-peak hydroelectric generation at the Clark Fork through
Kalich, Di 10
Avista Corporation
1 2008. Similar performance is achieved for the Spokane and
2 Mid-Columia proj ects.
3 Q.Please provide a sumry of the monthly and
4 average Northwest Forward natural gas and electrici ty
5 prices?
6 A.Table No. 2 presents modeled natural gas and
7 electricity prices.
8 Table No. 2 - Dispatch Model Prices Sumry
CSII &:NE/BP/Flat CSII &:NE/BP/Flat
Rathdru KFC'(7 x 24)Rathdru KFC'7 x 24)
Gas Gas Mid-C Gas Gas Mid-C
Month ($/dth)($/dth)($/MW)Month ($/dth)($/dth)($/MW)
Jul-09 7.18 7.51 57.01 Jan-10 8.38 8.76 67.51
Aug-09 7.29 7.63 63.09 Feb-10 8.36 8.74 62.47
Sep-09 7.29 7.64 60.64 Mar-10 8.12 8.50 57.69
Oct-09 7.34 7.68 55.47 Apr-10 7.41 7.76 49.74
Nov-09 7.75 8.11 59.58 May-10 7.36 7.70 39.36
Dec-09 8.13 8.50 71. 66 Jun-10 7.44 7.79 34.74
Average 7.67 8.03 56.59
9
10 Q.Are Mid-Columia electric prices from the
11 Dispatch model the same as the Forward Market?
12 A.No,Mid-Columia electric prices from the
13 Dispatch Model differ from the forward market for a variety
14 of reasons. The forward market prices are not only an
15 expectation of future prices,but they contain an
16 adjustment for risk or unknown future conditions, based on
17 the premise you can "lock in
11 prices. The Dispatch Model
18 is a spot market model that forecasts prices for a specific
19 time in the future given load, hydro, and fuel price
Kalich, Di 11
Avista Corporation
1 conditions. Average annual Mid-Columia prices in the
2 forward market are $63. 01/MW on-peak and $49. 26/MW off-
3 peak (based on average forwards between 9/1/2008 and
4 11/30/2008). The average Mid-Columia price from the
5 Dispatch Model is $62. 52/MW on-peak and $48. 68/MW off-
6 peak.
7 Q.You stated earlier in your testimony that you are
8 using the NWP hydro study as the basi s for your hydro
9 dataset. Does the NWP study include the Cabinet unit 4 or
10 any of the recent Noxon Rapids upgrades?
11 A.NO, the NWPP study does not include the Cabinet
12 Unit 4 or the Noxon Rapids 1 and 3 upgrades. The data will
13 be included in our next data submittal to the NWPP.I
14 expect the upgrade to be reflected in the 2009 NWPP study.
15 Q.How have you accounted for the upgrades in the
16 pro form?
17 A.The Cabinet Unit 4 upgrade is expected to
18 generate an additional 1.98 aM in an average water year;
19 Noxon Rapids Units 1 and 2 are expected to generate 3.3
20 average megawatts of additional energy in an average water
21 year.To account for this energy in the pro forma, the
22 unit sizes are increased to reflect the corrected amount of
23 energy. The Dispatch Model then generates at the upgraded
24 energy and capacity levels when the units are dispatched.
Kalich, Di 12
Avista Corporation
1 Q.Company witness Storro discusses a new generation
2 resource that will enter Avista's supply portfolio in 2010.
3 Is this resource included in the Dispatch Model and the
4 Proform?
5 A.The 270-MW gas-fired combined-cycle generation
6 resource you are referring to entered commercial service in
7 2001, though it was not owned or operated by the utility
8
9
arm of Avista Corporation.It has been in our Dispatch
Model since we began using the tool in 2002.However, we
10 have never included the resource in our portfolio of
11 resources that are tracked for ratemaking purposes. Though
12 we assume operational control over the facility in January
13 2010, we have not elected to include it in this filing
14 because the resource doesn' t become available to us until
15 the midpoint of the proforma period.As Company witness
16 Johnson explains in more detail in his testimony, the
17 Company is proposing to track the costs and benefits of
18 this resource through the PCA mechanism when it enters our
19 resource portfolio in January 2010.
20
21
22
iv. RESULTS
Q.Please sumrize the results from the Dispatch
23 Model that are used for ratemking.
24 A.The Dispatch Model tracks the Company's portfolio
25 during each hour of the pro forma study.Fuel costs and
Kalich, Di 13
Avista Corporation
1 generation for each resource are sumarized by month.
2 Total market sales and purchases, and their revenues and
3 costs, are also determined and sumarized by month.These
4 values are contained in Exhibit No.5, Schedule 2 and were
5 provided to Mr. Johnson for use in his calculations.Mr.
6 Johnson adds resource and contract revenues and expenses
7 not accounted for in the Dispatch Model (e.g., fixed costs)
8 to determine net power supply expense.
9 Q.Does this conclude your pre-filed direct
10 testimony?
11 A.Yes, it does.
Kalich, Di 14
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AN CHIEF COUNSEL OF 2009 JAN 23 PM 12: 4 l
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-8851
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-09-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHAGES FOR ELECTRIC AN )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 5
AN NATURA GAS CUSTOMERS IN THE )STATE OF IDAHO ) CLINT G. KALICH
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
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1
Dispatch Model Proforma Costs ($OOOS)
1 Ann il Feb !d ~~Jun Jul &m ~Oct Nov Q!
2 Hydro Projec
3 Clark Fork 0 0 0 0 0 0 0 0 0 0 0 0 0
4 Cabinet Gorge 0 0 0 0 0 0 0 0 0 0 0 0 0
5 Noxon Rapids 0 0 0 0 0 0 0 0 0 0 0 0 0
6 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
7
8 Spokane River 0 0 0 0 0 0 0 0 0 0 0 0 0
9 Uttle Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
10 Lon9 Lake 0 0 0 0 0 0 0 0 0 0 0 0 0
11 Monroe Street 0 0 0 0 0 0 0 0 0 0 0 0 0
12 Nine Mile 0 0 0 0 0 0 0 0 0 0 0 0 0
13 Post Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
14 Upper Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
15 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
16
17 Mid-Golumbia. Contract 0 0 0 0 0 0 0 0 0 0 0 0 0
18 Priest Rapids 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Rocky Reach 0 0 0 0 0 0 0 0 0 0 0 0 0
20 Wanapum 0 0 0 0 0 0 0 0 0 0 0 0 0
21 Wells 0 0 0 0 0 0 0 0 0 0 0 0 0
22 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
2324 Therals
25 Boulder Park 37 0 0 0 0 5 0 15 16 0 0 0 0
26 Colstrip 18,106 1,719 1,573 1,727 1,551 1,028 1,063 1,582 1,601 1,549 1,588 1,549 1,575
27 Coyote Sprin9s 2 70,099 7,260 6,781 6,895 3,724 1,672 2,171 6,176 7,154 6,740 6.41 7,131 7,754
28 Kette Falls 11,075 1,279 1,206 1,318 305 0 0 1,166 1,175 1,138 1,176 1,138 1,175
29 Kettle Falls CT 76 2 5 1 4 13 4 23 21 1 0 1 0
30 Lancaster 0 0 0 0 0 0 0 0 0 0 0 0 0
31 Norteast 40 0 0 0 0 0 0 17 23 0 0 0 0
32 Rathdrum 249 0 0 0 0 20 3 108 118 0 0 0 0
33 TOTAL 99,682 10,261 9,565 9,941 5,584 2,739 3,241 9,087 10,107 9,428 9,404 9,820 10,505
34
351 RESOURCE TOTAL 99,682 10,261 9,565 9,941 5,584 2,739 3,241 9,087 10,107 9,428 9,404 9,820 10,505
36
37 Contract
38 Black Creek 162 0 0 0 0 0 0 0 0 0 162 0 0
39 DOPD 783 45 41 62 82 119 126 92 66 37 44 34 35
40 Markel Contract 1 7,55 642 580 642 621 642 621 642 642 621 642 621 642
41 Can Ent Return 0 0 0 0 0 0 0 0 0 0 0 0 0
42 Grant County 0 0 0 0 0 0 0 0 0 0 0 0 0
43 Clark Fork LLC 101 8 8 8 13 16 15 11 6 3 3 5 7
44 Market Contract 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
45 Grant Displacement 5,449 397 385 364 504 522 431 516 438 434 454 473 510
46 Stimson Lumber 2,084 191 182 161 148 144 139 181 198 187 178 193 182
47 Jim Ford Creek 228 39 49 38 33 19 9 0 0 0 1 11 30
48 John Day Creek 81 4 2 2 3 11 14 12 8 6 5 8 6
49 Meyers Falls 409 36 41 50 49 51 46 24 12 14 23 30 32
50 Nichols Pumpin9 (3,346)(339)(283)(290)(242)(198)(169)(286)(317)(295)(279)(290)(360)
51 Colstrip Start Ener9Y 0 0 0 0 0 0 0 0 0 0 0 0 0
52 PGE CapExch 0 0 0 0 0 0 0 0 0 0 0 0 0
53 Phillps Ranch 1 0 0 0 0 0 0 1 0 0 0 0 0
54 Potlatch 0 0 0 0 0 0 0 0 0 0 0 0 0
55 Wind Contract 2,933 258 201 302 265 256 304 245 246 206 229 236 185
56 Load Follown9 Contracts 0 0 0 0 0 0 0 0 0 0 0 0 0
57 Sheep Creek 396 28 30 44 50 45 40 42 22 19 21 26 28
58 Upriver 2,090 271 266 265 255 25 191 66 (40)28 105 169 263
59WNP.3 14,347 2,963 2,676 1,463 1,415 0 0 0 0 0 0 2,867 2,983
60 ST Purchase 30,994 0 0 0 0 0 0 6,010 5,943 5,807 4,472 4,290 4,472
61 STSaies (12,721)0 0 0 0 0 0 (3,573)(3,492)(3,447)(755)(699)(755)
62SMUD (5,818)(179)(130)(163)(173)(58)(746)(752)(662)(642)(619)(567)(585)
63 Thompson River Co-Gen 0 0 0 0 0 0 0 0 0 0 0 0 0
64 TOTAL 65,919 6,077 5,596 4,683 4,68 3,032 2,680 4,94 4,765 4,638 6,402 9,049 9,369
65
66 Market Transactions
67 Market Purchases 51,202 8,765 5,690 4,443 2,640 732 582 1,763 6,521 4,646 5,563 4,588 5,269
68 Market Sales (53,641)(2,242)(2,309)(4,341)(M65)(5,736)(6,962)(9,794)(2,504)(2,817)(2,664)(4,475)(4,731)
69 TOTAL (2,439)6,523 3,381 102 (2,426)(5,00)(6,380)(8,031)4,017 1,828 2,899 113 538
70
711Fuel and Marlet Only 97,243 16,785 12,946 10,043 3,158 (2,265)(3,139)1,056 14,124 11,257 12,303 9,932 11,03 I
72
73 Adlustments
74 Coyote Sprin9s 2 Start Fuel 125 13 10 4 5 21 54 12 2 0 1 3 1
75 Rathdrum Start Fuel 26 0 0 0 0 2 1 11 11 0 0 0 0
76 Lancaster Start Fuel 0 0 0 0 0 0 0 0 0 0 0 0 0
77 Northeast Lost Margin 21 1 5 0 1 4 1 0 6 0 1 2 1
78 Coyote Sprin9s 2 Fuel Cost (1,810)(174)(149)(127)(101)(46)(60)(193)(251)(214)(159)(155)(181)
79 Lancaster Fuel Cost 0 0 0 0 0 0 0 0 0 0 0 0 0
80 Total Adjustments (1,639)(161)(134)(123)(95)(19)(5)(170)(231)(214)(157)(151)(179)
81
821Adjusted Fuel &.Màrket 95,604.16,624 12,812 . 9,920 3,063 .2,284 ~3,143 886 ;\13,893 11,043 12,146 .9,782 10,8631
Exhibit NO.5
Case No. A VU-E-09-01
C. Kalich, A vista
Schedule 2, p. 1 of 3
Dispatch Model Proforma Generation (aMW
1 Ann .l .E Mar Al ~Jun Jut AY .§Qi Nov ~
2 Hydro Projects
3 Clark Fork 325.9 246.0 284.9 236.2 367.2 648.681.2 450.7 244.4 166.9 140.8 166.3 275.8
4 Cabinet Gorge 125.3 100.4 118.0 98.2 146.7 226.3 228.3 178.1 99,9 67.9 58.0 68.2 111.3
5 Noxon Rapids 200.6 145.6 167.0 137.9 218.5 422.2 452.9 272.7 144.4 99.0 82.8 98.1 164.6
6 TOTAL(aMW 325.9 246.0 284.9 236.2 367.2 648.5 681.2 450.7 244.4 166.9 140.8 166.3 275.8
7
8 Spokane River 125.138.4 143.5 158.7 169.1 167.9 155.98.8 55.0 77.3 95.9 119.0 130.4
9 Litte Falls 23.5 27.4 27.9 30.6 32.4 32.2 29.6 17.5 9.7 13.0 16.3 21.5 24.0
10 Long Lake 58.7 66.5 67.1 75.4 82.7 83.3 74.7 43.9 25.4 33.2 40.9 52.8 59.5
11 Monroe Street 11.7 11.9 12.6 13.4 13.6 13.6 13.2 10.6 5.9 9.4 11.2 12.2 12.6
12 Nine Mile 13.3 13.7 15.4 16.7 17.7 16.6 16.2 11.2 5.8 8.3 10.9 13.2 14.5
13 Post Falls 9.8 10.3 11.5 13.4 13.7 13.5 12.9 7.1 2.8 5.3 7.3 9.9 10.4
14 Upper Falls 8.6 8.7 9.0 9.2 8.9 8.7 9.0 8.5 5.4 8.2 9.2 9.3 9.4
15 TOTAL(aMW 125.6 138.4 143.5 158.7 169.1 167.9 1556 98.8 550 77.3 95.9 119.0 130.4
16
17 Mid-Columbia- Contracts 101.7 126.1 102.3 81.5 96.5 104.0 119.3 128.2 99.8 77.4 87.5 91.7 105.6
18 Priest Rapids 19.2 30.6 25.3 19.1 17.5 12.7 18.5 14.4 13.9 12.4 13.9 24.5 28.4
19 Rocky Reach 20.3 25.8 19.7 16.1 21.8 22.4 26.5 25.1 21.5 14.0 15.7 16.6 18.8
20 Wanapum 27.5 27.4 23.3 18.8 22.9 26.7 29.9 46.8 27.7 27.1 31.0 22.2 26.1
21 Wells 34.6 42.3 33.9 27.4 34.2 42.1 44.5 41.9 36.7 23.9 26.9 28.4 32.3
22 TOTAL(aMW 101.7 126.1 102.3 81.5 96.5 104.0 119.3 128.2 99.8 77.4 87.5 91.7 105.6
23
24 TOTAL 553.2 510.5 530.7 476.3 632.8 920.4 956.1 6778 399.1 321.6 324.2 377.0 511.8
25
26 Thermals
27 Boulder Park 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.3 0.3 0.0 0.0 0.0 0.0
28 Colstri 190.5 203.6 206.3 204.6 189.9 121.7 130.2 203.9 206.3 206.3 204.6 206.3 203.0
29 Coyote Springs 2 148.7 163.0 170.2 161.6 99.6 43.8 58.0 166.1 189.7 185.0 1773 185.0 185.4
30 Kettle Falls 34.9 42.4 44.4 43.8 10.5 0.0 0.0 46.0 46.4 46.4 46.4 46.4 46.4
31 Kettle Falls CT 0.1 0.0 0.1 0.0 0.1 0.3 0.1 0.5 0.4 0.0 0.0 0.0 0.0
32 Lancaster 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
33 Northeast 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.3 0.0 0.0 0.0 0.0
34 Rathdrum 0.3 0.0 0.0 0.0 0.0 0.3 0.0 1.8 1.9 0.0 0.0 0.0 0.0
35 TOTAL 374.7 409.1 421.0 410.0 300.0 166.3 188.3 418.7 445.2 437.7 428.3 437.7 434.7
36
371 RESOURCE TOTAL 927.9 919.6 951.7 886.3 932.8 1,086.7 1,144.4 1,096.5 844.4 759.3 752.5 814.7 946.5
38
39 Contracts
40 Black Creek 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.4 0.0 0.0
41 DOPD 3.7 2.4 2.4 3.3 4.8 6.7 7.3 5.3 3.8 2.0 2.4 2.0 1.8
42 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
43 Can Ent Retum (3.9)(3.5)(3.6)(3.7)(3.6)(3.5)(3.6)(4.2)(4.0)(4.1)(4.2)(4.0)(4.2)
44 Grant County 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
45 Clark Fork LLC 0.1 0.1 0.1 0.1 0.2 0.3 0.3 0.2 0.1 0.1 0.0 0.1 0.1
46 Market Contract 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
47 Grant Displacement 22.2 17.4 17.6 17.7 26.2 31.8 31.6 27.6 19.7 19.0 18.7 19.3 19.2
48 Stimson Lumber 4.2 4.2 4.4 4.5 4.3 4.0 4.0 4.0 4.4 4.3 4.0 4.5 4.0
49 Jim Ford Creek 0.4 0.6 0.8 1.2 1.0 0.6 0.3 0.0 0.0 0.0 0.0 0.2 0.4
50 John Day Creek 0.2 0.1 0.0 0.1 0.1 0.4 0.6 0.4 0.3 0.2 0.2 0.1 0.1
51 Meyers Falls 1.0 1.0 1.2 1.4 1.4 1.4 1.3 0.7 0.3 0.4 0.6 0.9 0.9
52 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)
53 Colstrip Start Energy 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
54 PGECapExch 0.1 2.4 0.0 (2.8)(0.4)1.2 0.0 (0.8)0.8 (0.4)0.4 1.7 (0.8)
55 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
56 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
57 Wind Contract 8.4 8.6 7.4 10.0 9.1 8.5 10.4 8.3 8.3 7.2 7.8 8.3 6.3
58 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
59 Sheep Creek 0.8 0.4 0.6 1.1 1.5 1.6 1.6 1.0 0.3 0.2 0.3 0.5 0.4
60 Upriver 6.1 8.3 9.0 10.4 10.3 9.8 7.8 2.0 (1.2)0.9 3.2 5.4 8.0
61 WNp.3 43.8 106.106.6 52.6 52.6 0.0 0.0 0.0 0.0 0.0 0.0 106.6 106.
62 ST Purchases 51.3 0.0 0.0 0.0 0.0 0.0 0.0 114.5 114.0 114.4 89.5 88.9 89.5
63 ST Sales (17.1)0.0 0.0 0.0 0.0 0.0 0.0 (54.0)(53.0)(53.9)(14.5)(13.9)(14.5)
64 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
65 Thompson River Co-Gen 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
66 TOTAL 214.0 240.8 238.9 188.1 199.8 155.2 153.7 197.3 186.1 182.5 205.1 312.6 310.3
67
68 Market Transactions
69 Market Purchases 83.7 156.8 122.2 93.3 61.2 15.5 15.5 31.6 113.3 90.4 121.3 95.4 89.5
70 Market Sales (141.8)(49.6)(60.1)(109.8)(161.1)(263.9)(347.0)(267.1)(64.0)(83.8)(74.3)(118.3)(99.1)
71 TOTAL (58.0)107.3 62.1 (16.5)(99.9)(248.4)(331.5)(235.5)49.3 6.6 47.1 (22.9)(9.5)
72
73 System Load 1,083.9 1,267.7 1,252.7 1,057.9 1,032.7 993.4 966.6 1,058.3 1,079.8 948.4 1,00.7 1,104.4 1,247.3
Exhbit No. 5
Case No. AVU-E-09-01
C. Kalich, Avista
Schedule 2, p. 2 of 3
Dispatch Model Proforma Generation (GWh)
1 A!.l f.!1 åi Mn .!,I &!~~!:Q!
2 Hydro Projects
3 Clark Fork 2,854.5 183.0 191.5 175.7 264.4 482.5 490.5 335.181.8 120.1 104.8 119.7 205.2
4 Cabinet Gorge 1,097.6 74.7 79.3 73.1 107.1 168.164.4 132.5 74.4 48.9 43.2 49.1 82.8
5 Noxon Rapids 1,756.9 108.3 112.2 102.6 157.3 314.1 326.1 202.9 107.4 71.2 61.6 70.6 122.4
6 TOTAL 2,B54.5 1B3.0 191.5 175.7 264.4 4B2.5 490.5 335.4 1B1.B 120.1 104.B 119.7 205.2
7
8 Spokane River 1,100.3 103.96.4 118.1 121.7 125.112.0 73.5 40.9 55.7 71.3 85.7 97.0
9 Uttle Falls 205.4 20.4 18.7 22.7 23.3 24.0 21.3 13.0 7.2 9.3 12.1 15.4 17.9
10 Long Lake 514.2 49.4 45.1 56.1 59.6 62.0 53.8 32.7 18.9 23.9 30.4 38.0 44.3
11 Monroe Street 102.3 8.8 8.5 10.0 9.8 10.1 9.5 7.9 4.4 6.7 8.3 8.8 9.4
12 Nine Mile 116.10.2 10.4 12.4 12.8 12.4 11.7 8.3 4.3 6.0 8.1 9.5 10.8
13 Post Falls 86.0 7.7 7.7 10.0 9.9 10.0 9.3 5.3 2.0 3.8 5.4 7.2 7.7
14 Upper Falls 75.5 6.5 6.1 6.9 6.4 6.5 6.5 6.3 4.0 5.9 6.9 6.7 7.0
15 TOTAL 1,100.3 103.0 96.4 11B.1 121.7 125.0 112.0 73.40.9 55.7 71.3 B5.7 97.0
16
17 Mid-Columbia. Contract 890.9 93.8 68.7 60.6 69.5 77.4 85.9 95.4 74.3 55.7 65.1 66.0 78.5
18 Priest Rapids 168.6 22.7 17.0 14.2 12.6 9.5 13.3 10.7 10.4 8.9 10.3 17.7 21.1
19 Rocy Reach 178.1 19.2 13.3 12.0 15.7 16.7 19.1 18.7 16.0 10.1 11.6 11.9 14.0
20 Wanapum 241.3 20.4 15.7 14.0 16.5 19.9 21.5 34.8 20.6 19.5 23.1 16.0 19.4
21 Wells 303.0 31.5 22.8 20.4 24.6 31.3 32.0 31.2 27.3 17.2 20.0 20.5 24.0
22 TOTAL B90.9 93.B 6B.7 60.6 69.5 77.4 B5.9 95.4 74.3 55.7 65.1 66.0 78.
23
24 TOTAL 4,B45.B 379.B 356.6 354.4 455.6 684.B 6BB.4 504.3 297.0 231.5 241.2 271.4 3BM
25
26 Thermls
27 Boulder Park 0.5 0.0 0.0 0.0 0.0 0.1 0.0 0.2 0.2 0.0 0.0 0.0 0.0
28 Colstrip 1,668.7 151.5 138.6 152.2 136.7 90.6 93.7 151.7 153.5 148.5 152.2 148.5 151.0
29 Coyote Springs 2 1,302.9 121.3 114.4 120.2 71.7 32.6 41.8 123.5 141.1 133.2 131.9 133.2 137.9
30 Kettle Falls 306.1 31.6 29.8 32.6 7.5 0.0 0.0 34.2 34.5 33.4 34.5 33.4 34.5
31 Kelle Falls CT 1.1 0.0 0.1 0.0 0.1 0.2 0.1 0.4 0.3 0.0 0.0 0.0 0.0
32 Lancaster 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
33 Northeast 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.2 0.0 0.0 0.0 0.0
34 Rathdrum 3.0 0.0 0.0 0.0 0.0 0.2 0.0 1.3 1.4 0.0 0.0 0.0 0.0
35 TOTAL 3,2B2.B 304.4 2B2.9 305.0 216.0 123.7 135.6 311.5 331.3 315.2 31B.7 315.2 323.4
36
371 RESOURCE TOTAL B,12B.6 684.2 639.5 659.4 671.6 B08.5 B240 B15.B 62B.2 546.7 559.9 5B6.6 704.2 I
38
39 Contracts
40 Black Creek 3.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.3 0.0 0.0
41 DOPD 32.3 1.8 1.6 2.4 3.5 5.0 5.3 3.9 2.8 1.5 1.8 1.4 1.4
42 Market Contract 1 219.0 18.6 16.8 18.6 18.0 18.6 18.0 18.6 18.6 18.0 18.6 18.0 18.6
43 Can Ent Return (33.8)(2.6)(2.4)(2.7)(2.6)(2.6)(2.6)(3.1)(3.0)(3.0)(3.1)(2.9)(3.1)
44 Grant County 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
45 Clark Fork LlC 1.2 0.1 0.1 0.1 0.2 0.2 0.2 0.1 0.1 0.0 0.0 0.0 0.1
46 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
47 Grant Displacement 194.2 13.0 11.8 13.1 18.8 23.7 22.8 20.5 14.6 13.7 13.9 13.9 14.3
48 Stimson Lumber 37.0 3.1 2.9 3.4 3.1 3.0 2.9 3.0 3.3 3.1 3.0 3.2 3.0
49 Jim Ford Creek 3.7 0.4 0.5 0.9 0.8 0.4 0.2 0.0 0.0 0.0 0.0 0.1 0.3
50 John Day Creek 1.9 0.1 0.0 0.1 0.1 0.3 0.4 0.3 0.2 0.1 0.1 0.1 0.1
51 Meyers Falls 8.4 0.7 0.8 1.0 1.0 1.0 0.9 0.5 0.2 0.3 0.5 0.6 0.7
52 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)
53 Colstrip Start Energy 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
54 PGE CapExch 0.9 1.8 0.0 (2.1)(0.3)0.9 0.0 (0.6)0.6 (0.3)0.3 1.2 (0.6)
55 Phillps 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
56 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
57 Wind Contract 73.2 6.5.0 7.5 6.6 6.3 7.5 6.2 6.2 5.2 5.8 6.0 4.7
58 Load Following Contrcts 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
59 Sheep Creek 6.9 0.3 0.4 0.8 1.1 1.2 1.1 0.7 0.2 0.2 0.2 0.3 0.3
60 Upriver 53.8 6.2 6.1 7.8 7.4 7.3 5.6 1.5 (0.9)0.6 2.4 3.9 6.0
61 WNp.3 384.0 79.3 71.6 39.1 37.9 0.0 0.0 0.0 0.0 0.0 0.0 76.7 79.3
62 ST Purchases 449.6 0.0 0.0 0.0 0.0 0.0 0.0 85.2 84.8 82.4 66.6 64.0 66.6
63 ST Sales (150.0)0.0 0.0 0.0 0.0 0.0 0.0 (40.2)(39.4)(38.8)(10.8)(10.)(10.8)
64SMUD 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
65 Thompson River Co-Gen 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
66 TOTAL 1,B74.7 179.1 160.5 139.9 143.9 115.4 110.7 146.B 13B.4 131.4 152.6 225.1 230.B
67
68 Market Transactions
69 Market Purchases 733.116.7 82.1 69.4 44.1 11.5 11.1 23.5 84.3 65.1 90.3 68.7 66.6
70 Market Sales (1,241.8)(36.9)(40.4)(81.7)(116.0)(196.)(249.8)(198.7)(47.6)(60.3)(55.2)(85.2)(73.7)
71 TOTAL (508.)79.B 41.B (12.3)(71.9)(184.B)(23B.7)(175.2)36.7 4.B 35.0 (16.5)(7.1)
72
73 SYSTEM LOAD 9,494.9 943.1 B41.B 7B7.1 743.5 739.1 696.0 7B7.4 B03.4 6B2.9 747.5 795.1 92B.0
Exhbit NO.5
Case No. AVU-E-09-01
C. Kalich, A vista
Schedule 2, p. 3 of 3