20080403Johnson Direct.pdf

r-,f\DDAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220 - 3 727TELEPHONE: [phone]FACSIMILE: [phone]
REGULA~rAi§ - 3 Pt" 12: 56
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 AN
NATURAL GAS SERVICE TO ELECTRIC
AND NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
DIRECT TESTIMONY
OF
WILLIAM G. JOHNSON
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I.INTRODUCTION
Q.Please state your name, business address, and
3 present position with Avista Corporation.
4 A.My name is william G. Johnson.My business
5 address is 1411 East Mission Avenue, Spokane, Washington,
6 and I am employed by the Company as a Wholesale Marketing
7 Manager in the Energy Resources Department.
8
9
Q.What is your educational background?
A.I graduated from the University of Montana in
10 1981 with a Bachelor of Arts Degree in Political
11 Science/Economics.I obtained a Master of Arts Degree in
12 Economics from the University of Montana in 1985.
13 Q.How long have you been employed by the Company
14 and what are your duties as a Wholesale Marketing Manager?
15
16
A.I started working for Avista in April 1990 as a
Demand Side Resource Analyst.I joined the Energy
17 Resources Department as a Power Contracts Analyst in June
18 1996.My primary responsibilities involve power contract
19 origination and management and power supply regulatory
20 issues.
21 Q.Wht is the scope of your testimony in this
22 proceeding?
23 A.My testimony will 1) identify and explain the
24 proposed normalizing and pro forma adjustments to the 2007
25 test period power supply revenues and expenses, and 2)
Johnson, Di 1
Avista Corporation
1 describe the new base level of power supply costs for Power
2 Cost Adjustment (PCA) calculation purposes, using the pro
3 forma costs proposed by the Company in this filing.
4 Q.Are you sponsoring any exhibits to be introduced
5 in this proceeding?
6 A.Yes.I am sponsoring Exhibit No.6, Schedules 1
7 through 4, which were prepared under my supervision and
8 direction.
9 Q.Are other company witnesses providing testimony
10 regarding issues you are addressing?
11 A.Yes.Company witness Mr.Kalich provides
12 detailed testimony on the AURORA model used by the Company
13 to develop short-term power purchase expense, fuel expense
14 and short-term power sales revenue included in my exhibits.
15
16
17
II. SUMY
Q.Please provide an overview of your direct
18 testimony.
19 A.My testimony will identify and explain the
20 proposed normalizing and pro forma adjustments to the 2007
21 test period power supply revenues and expenses, and
22 describe the new base level of power supply costs for Power
23 Cost Adjustment (PCA) calculation purposes, using the pro
24 forma costs proposed by the Company in this filing.This
25 involves the determination of revenues and expenses based
Johnson, Di 2
Avista Corporation
1 on the generation and dispatch of Company resources and
2 expected wholesale market power prices as determined by the
3 AURORA model simulation. In addition, adjustments are made
4 to reflect contract changes between the 2007 test period
5 and the 2009 pro forma period. The table below shows total
6 net power supply expense during the 2007 test period and
7 the proposed 2009 pro forma period.For information only
8 purposes, the power supply expense currently in rates,
9
10
11
12
13
14
15
16
17
18
which is based on a Septemer 2004 through August 2005 pro
forma period, is also shown.
........ .. .. Powèr Supply Exp$.
ot Including DJrectly Assigned Potlatch.
Idaho
AllocationSystem
$82,643,000Power Supply Expense in Current Base Rates
(Sep 04 - Aug 05 pro forma)
Actual 2007 Power Supply Expense
Adjustment to Test Period
2009 Pro forma Power Su I Ex ense
$175,939,000
$971,000
$176,910,000
$343,831
The net effect of my adjustments to the 2007 test year
is an increase of $971,000supplyexpensepower
19 ($176,910,000 - $175,939,000) on a system basis. The Idaho
20 allocation of this adjustment of $343,831 is incorporated
21 into the revenue requirement calculation for the Washington
22 jurisdiction by Company witness Ms. Andrews.
23 What are the major factors driving the increasedQ.
24 power supply expense in the pro form year over the level
25 of power supply exense currently in base rates?
Johnson, Di 3
Avista Corporation
1
2
A.The level of power supply expense currently in
base rates is $82,643,000 (system numer).This expense
3 level is based on a Septemer 2004 through August 2005 pro
4
5
forma period and 2002 retail loads.This compares to the
proposed 2009 pro forma power supply expense of
6 $176,910,000, an increase of approximately $94.3 million on
7 a system basis and an Idaho allocation of approximately
8 $33.4 million.
9 This significant increase in pro forma power supply
10 expense over the expense currently in base rates is based
11 on numerous factors, including higher retail loads, reduced
12 hydro generation,increased fuel costs and increased
13 transmission expense.
14
15
Higher retail loads are the most significant factor
contributing to higher power supply expense.Pro forma
16 retail loads are 128.6 aM higher than 2002 loads that
17 current rates are based on. Hydro generation is also lower
18 than the level in current base rates.Pro forma hydro
19 generation is 546.3 aMW compared to 553.1 aMW in current
20 base rates, a reduction of 6.8 aMW.The pro forma hydro
21 generation includes the uhydro rate mitigation adjustment"
22 of 26.5 aM.without the urate mitigation adjustment"
23 (described later in my testimony), the reduction in hydro
24 generation would be 33.3 aM.This reduction in hydro
25 generation is due to the reduction in Mid Coiumia
Johnson, Di 4
Avista Corporation
1 purchased hydro generation resulting from the expiration of
2 the Priest Rapids contract in 2005 and the Wanapum contract
3 in 2009.
.4 Fuel expense is significantly higher in the 2009 pro
5 forma compared to the fuel expense in current base rates.
6 Total thermal fuel expense for coal, wood fuel and natural
7 gas is approximately 50 percent higher on a dollars per MW
8 basis in the 2009 pro forma, increasing from $20.26 per MW
9 in current base rates to $30.33 per MW in the 2009 pro
10 forma.
11 Finally,transmission expense has increased by
12 approximately $2.9 million on a system basis, approximately
13 $1.0 million Idaho allocation.This is primarily due to
14 the purchase of an additional 125 MW of BPA point-to-point
15 transmission for Coyote Springs 2.
16 Q.What are the major factors driving the increased
17 power supply expense in the pro form year over the 2007
18 test year?
19 A.The primary factors increasing power supply
20 expense from the 2007 test year to the 2009 pro forma year
21 are the cost of serving additional retail load, fuel costs
22 and increased purchased power cos ts .
23 Retail loads in the 2009 pro forma period are
24 approximately 27 aMW higher than 2007 weather adjusted
25 retail load.Increased retail load creates higher power
Johnson, Di 5
Avista Corporation
1 supply expense and also puts upward pressure on retail
2 rates because the marginal cost of power exceeds the
3 embedded cost of power.The increase in power supply
4 expense due to increased retail loads is approximately $4.8
5 million (Idaho allocation) .
6 In addition to higher loads, some of the. Company's
7 purchased power contract costs have increased, particularly
8 the Company's Mid-Columia purchases from the Priest Rapids
9 and Wanapum hydro generation developments.The cost for
10 the Company's share of Wanapum and Priest Rapids is
11 approximately $1. 7 million (Idaho allocation) higher in
12 2009 than in 2007.The Company's contract for Priest
13 Rapid's power expired October 31, 2005. While the Company
14 still gets power from Priest Rapids, the majority of the
15 power is now priced at market prices rather than the low
16 proj ect cost.The Wanapum contract expires October 31,
17 2009. Beginning November 1, 2009 the Company will receive
18 approximately half of much energy from these two plants as
19 before the expiration of the contracts, and only a small
20 portion of the power will be priced at project cost. Under
21 the new contract for these plants, the plant's owner, Grant
22 County PUD, gets more of the physical output of the plants
23 and also keeps more of the financial value of the
24 purchaser's share of the plants.Effectively, as Grant's
25 loads grow they keep some of the financial value of the
Johnson, Di 6
Avista Corporation
1 purchasers' share of the plants in order to serve their
2 loads with proj ect cost power.Due to the very high load
3 growth in Grant County, less of the value of Priest Rapid's
4 power is going to the purchasers, and with the expiration
5 of the Wanapum contract in October 2009, less of the value
6 of that plant will go to the purchasers.
7 Finally, thermal fuel expense for Colstrip and Kettle
8 Falls has also increased significantly, increasing by
9 approximately $2.2 million (Idaho allocation) from 2007 to
10 2009. This is based primarily on increasing unit costs for
11 coal and wood fuel.
12 Q.Given the increased costs describe above, please
13 explain why there is almost no increase in the overall
14 power supply expense between the 2009 pro form year and
15 the 2007 test year.
16 A.The reason that the overall increase in power
17 supply expense from the 2007 year to the 2009 pro forma
18 year is very small is because the hydro generation urate
19 mitigation adjustment" offsets almost all of the increased
20 power supply expense.The hydro generation urate
21 mitigation adjustment", explained by Mr. Kalich, decreases
22 system power supply expense by approximately $12.8
23 (system), $4.5 million (Idaho allocation) .
24 After incorporating the urate mitigation adjustment",
25 the total power supply adjustment from 2007 actual to 2009
Johnson, Di 7
Avista Corporation
1 pro forma power supply expense is only $343,831 (Idaho
2 allocation), as shown in the previous table.
3
4 III. PRO FORM POWER SUPPLY COSTS
5 Overview
6 Q.Please identify the specific power supply cost
7 items that are covered by your testimony and the total
8 adjustment being proposed.
9 A.Exhibit No.6, Schedule 1 identifies the power
10 supply expense and revenue items that fall within the scope
11 of my testimony.These revenue and expense items are
12 related to power purchases and sales, fuel expenses,
13 transmission expense, and other miscellaneous power supply
14 expenses and revenues.
15 Q.What is the basis for the adjustments to the 2007
16 test period power supply revenues and expenses?
17 A.The purpose of the adjustments to the 2007 test
18 period is to normalize power supply expenses for normal
19 weather and hydroelectric generation and to reflect known
20 and measurable changes for the 2009 pro forma period that
21 rates will be in effect.Adjustments are also made to
22 reflect contract changes from 2007 to 2009.
23 The AURORA Model dispatches Company resources on an
24 hourly basis and calculates the level of generation from
25 the Company's thermal resources, fuel costs for thermal
Johnson, Di 8
Avista Corporation
1 resources, and the short-term purchases and sales necessary
2 to serve system requirements.
3 Q.Have any changes been made in the calculation of
4 power supply costs from the prior general rate case?
5 A.Yes.The primary change made in this general
6 rate case is the use of loads that match the pro forma
7 period. The use of pro forma retail loads together wi th a
8 production property adjustment, provides a better matching
9 of revenues and expenses, and properly reflects the costs
10 of providing services to retail customers during the pro
11 forma period that rates will be in effect.Mr. Kalich
12 describes the pro forma retail loads used in this case, and
13 Company wi tness Ms. Knox explains the production property
14 adjustment.
15 The power supply pro forma in this case also includes
16 a urate mitigation adjustment" to hydroelectric generation
17
18
to decrease pro forma power supply expense.This
adjustment increased hydro generation above normal
19 generation levels, which decreased power supply expense by
20 $12.8 million (system numer). This adjustment was made in
21 the AURORA model and is explained in Mr. Kalich' s
22 testimony.
23 Other than the use of pro forma retail loads and the
24 hydro rate mitigation adjustment, the process to develop
Johnson, Di 9
Avista Corporation
1 the pro forma net power supply expense in this case is the
2 same as in the 2004 general rate case.
3 A brief description of each adjustment is provided in
4 Exhibit No.6, Schedule 2.Detailed workpapers have been
5 provided to the Commission coincident to this filing to
6 support each of the pro forma revenues and expenses.The
7 detailed workpapers for each adjustment show the actual
8 revenue or expense in 2007, and the pro forma revenue or
9 expense for 2009.
10
11 Long-Term Contracts
12 Q.How are long-term power contracts included in
13 the pro form?
14 A.Long-term power contracts are included in the pro
15 forma by including the energy receipt or obligation
16 associated with the contract in the AURORA model and
17 including the cost or revenue in the pro forma net power
18 supply expense.
19 Q.Are there any new power purchases or sales in the
20 pro form that were not in place during the 2007 test year?
21 A.Yes, there is one new long-term purchase.The
22 Company has entered into a 10-year purchase agreement with
23 Thompson River Cogen, a cogeneration plant in Thompson
24 Falls, Montana.The plant is expected to be on-line
25 sometime during early 2008 and produce approximately 11
Johnson, Di 10
Avista Corporation
1 average megawatts. The purchase price of $58.50 per MW is
2 very close to the forward power market prices in the AURORA
3 model for the 2009 pro forma period, so the contract has
4 minimal impact on power supply expense.
5
6 Short-Term Power Purchases and Sales
7 Q.How are short-term transactions included in the
8 pro form?
9
10
A.Short-term electric power purchases and sales are
an output of the AURORA model.The model calculates both
11 the volumes and price of short-term purchases and sales
that balance the system's generation and long-term12
13 purchases with retail load and long-term obligations.The
14 price of the short-term transactions represents the price
15 of spot market power as determined by the AURORA model.
16
17 Therml Fuel Expense
18 Q.How are therml fuel expenses determined in the
19 pro form?
20 A.Thermal fuel expenses include Colstrip coal
21 costs, Kettle Falls wood waste costs and natural gas
22 expense for the Company's gas-fired resources including
23 Coyote Springs 2, Rathdrum, Northeast, Boulder Park, and
24 the Kettle Falls combustion turbine.Uni t coal cos ts at
25 Colstrip are based on the long-term coal supply and
Johnson, Di 11
Avista Corporation
1 transportation agreements. unit wood fuel costs at Kettle
2 Falls are based on multiple shorter-term contracts with
3 fuel suppliers and inventory.Total fuel costs for each
4 plant are based on the unit fuel cost and the plant's level
5 of generation as determined by the AURORA model.Exhibit
6 No.6, Schedule 3 shows the pro forma fuel costs by month
7 for each plant. Mr. Kalich provides details and supporting
8 workpapers regarding the fuel costs for the Company's
9 thermal plants.
10
11 Transmission Expense
12 Q. What changes in transmission expense are in the
13 2009 pro form compared to the actual 2007 transmission
14 expense?
15 A.Transmission expense in the 2009 pro forma is
16 approximately $.5 million (system) higher than the 2007
17 actual expense.The primary reason for this increase is
18 that beginning August 1, 2007 the Company began purchasing
19 an additional 50 MW of transmission for Coyote Springs 2
20 (CS2) .
21 Q.What is the change in transmission for CS2
22 between the 2007 test year and the 2009 pro form period?
23 A.Until August 1, 2007 the Company purchased 222 MW
24 of firm point-to-point (PTP) transmission from BPA and had
25 a 125 MW exchange agreement to meet the remaining
Johnson, Di 12
Avista Corporation
1 transmission requirements for CS2. The exchange agreement
2 expired at the end of 2007.To meet the transmission
3 requirements of CS2 the Company purchased an additional 50
4 MW of firm PTP transmission from BPA, for a total of 272 MW
5 of firm transmission for CS2.This resul ts in total PTP
6 purchases of 468 MW (196 MW for Colstrip and 272 MW for
7 CS2) .
8
9
Q.Are there any new transmission contracts?
A.Yes, there is a new transmission expense, labeled
10 Sagle-Northern Lights, for the purchase of transmission
11 from Northern Lights Utility to serve Avista customers in
northern Idaho.This transmission purchase began May 1,12
13 2007.Purchasing transmission from Northern Lights was
14 less expensive then building what would have been a
15 duplicative transmission line.
16
17
18
iv. PCA CALCULTIONS
Q.What effect will this case have on the PCA?
19 A.This case will update the authorized power supply
20 expenses and revenues, retail load, and the retail revenue
21 credit. PCA entries will continue to be calculated in the
22 same manner as current calculations.The final order in
23 this case will determine the new authorized level of power
24 supply expense, retail load and the retail revenue credit,
Johnson, Di 13
Avista Corporation
1 and Potlatch generation and revenues used in the PCA
2 calculation.
3 Q. Wht is the authorized power supply expense and
4 sales proposed by the Company for the PCA?
5
6
A.The proposed authorized level of annual system
power supply expense is $161,669,734.This is the sum of
7 Accounts 555 (Purchased Power), 501 (Thermal Fuel), 547
8 (Fuel), less Account 447 (Sale for Resale) in the Company's
9 filed pro forma.
10
11
The level of retail sales and the retail revenue
credit will also be updated.Because the Company has
12 included a Production Property Adjustment in its revenue
13 requirement the proposed authorized level of retail sales
14 to be used in the PCA is the 2009 pro forma retail sales
15 Q.What value is the Company proposing as the retail
16 revenue credit in the PCA?
17 A.Because the Company is using pro forma retail
18 load to develop pro forma power supply expense, the Company
19 is proposing to use the marginal power cost from the AURORA
20 model as the value for the retail revenue credit in the
21 PCA.The proposed retail revenue credit is $53. 63/MW.
22 This is the average market purchases and sales price shown
23 on line 9 of Exhibit No.6, Schedule 3. This value is the
24 average market price for short-term transaction, which
Johnson, Di 14
Avista Corporation
1 represents the marginal cost of power in the pro forma
2 period.
3 Absent the use of pro forma retail loads in the
4 development of power supply expense the Company would
5 propose that the correct value to use as the retail revenue
6 credi t in the PCA is the average production cost.The
7 average production cost represents the power commodity
8 component of retail rates and is the revenue collected from
9 cus tomers to recover power cos ts .Using the average cost
10 of production as the retail revenue credit in the PCA
11 ensures that the actual revenue collected from customers
12 when retail sales increase is credited back against the
13 increased power supply expense and only the difference
14 between the actual cost of power and the amount of revenue
15 collected from customers is included in the PCA.
16 The use of pro forma retail loads in the development
17 of power supply expense, however, makes the choice of what
18 value to use as the retail revenue credit less critical.
19 This is because the difference in actual sales and
20 authorized sales in 2009 is expected to be small since the
21 load is for the same year.The use of pro forma loads in
22 developing the pro forma power supply expense mitigates the
23 potential impact of load growth in the PCA.
24
25
The proposed PCA authorized monthly power supply
expense,retail sales,and Potlatch generation that
Johnson, Di 15
Avista Corporation
1 determines the Potlatch power purchase expense and revenue
2 related to the portion of Potlatch's load equal to their
3 generation is shown in Exhibit No.6, Schedule 4.
4 Q.Does that conclude your pre-filed direct
5 testimony?
6 A. Yes.
Johnson, Di 16
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
'ìnrm
REGULATORY l.~iJU
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 )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 6
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) WILLIAM G. JOHNSON
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avista Corp;
Power Supply Pro forma. Idaho Jurisdiction
System Numbers. 2007 Actual and 2009 Pro forma (Hydro Adjusted)
2009 Loads
Line Jan 07 - Dec 07 Jan 09 - Dec 09
No.Actuals Adjustment Proforma
555 PURCHASED POWER
1 Short-Term Market Purchases $94,024 -$42,627 $51,397
2 Rocky Reach 2,181 119 2,300
3 Wanapum 4,430 1,238 5,668
4 Wells 1,275 78 1,353
5 Priest Rapids Project 3,924 3,459 7,383
6 Grant Displacement 5,610 -190 5,420
7 Douglas Settlement 617 16 633
8 WNP-3 11,870 1,708 13,578
9 Deer Lake-IP&L 8 0 8
10 Small Power 1,091 58 1,149
11 Stimson 1,990 107 2,097
12 Spokane-Upriver 1,913 104 2,017
13 Douglas Exchange Capacity 1,536 -1,536 0
14 Seattle Exchange Capacity 1,681 -1,681 0
15 Black Creek Index Purchase 144 46 190
16 Non-Monetary 241 -241 0
17 Contract A 6,789 0 6,789
18 Contract B 6,745 0 6,745
19 Contract C 6,658 0 6,658
20 Contract D 7,556 0 7,556
21 CS2 Exchange 1,533 -1,533 0
22 TRC Purpa Purchase 0 5,403 5,403
23 NWestem Load Following Deviation Energy 1,286 -1,286 0
24 BPA NT Deviation Energy 3,074 -3,074 0
25 Grant Transmission Losses 276 -276 0
26 Potlatch Co-Gen Purchase 19,861 -19,861 0
27 BPA Spinning Reserve 980 0 980
28 Ancilary Services 662 -662 0
29 PPM Wind Purchase 3,173 -123 3,050
30 Total Accunt 555 191,128 -60,754 130,374
557 OTHER EXPENSES
31 Broker Commission Fees 52 0 52
32 REC Purchases 301 49 350
33 Bankruptcy Write-Off 23 -23 0
34 Natural Gas Fuel Purchases 16,575 -16,575 0
35 Total Account 557 16,951 -16,549 402
501 THERMAL FUEL EXPENSE
36 Kette Falls - Wood Fuel 8,714 3,097 11,811
37 Kettle Falls - Gas 38 -38 0
38 Colstrip - Coal 16,207 3,181 19,388
39 Colstip - Oil 308 0 308
40 Total Accunt 501 25,267 6,240 31,507
547 OTHER FUEL EXPENSE
41 Coyote Springs Gas 88,084 -18,687 69,397
42 Gas Transportation Charge 7,729 0 7,729
43 Rathdrum Gas 1,774 -401 1,373
44 Northeast CT Gas 238 -238 0
45 Boulder Park Gas 1,811 -1,343 468
46 Kette Falls CT Gas 140 214 354
47 Total Account 547 99,776 -20,456 79,320
Exhbit No.6
565 TRANSMISSION OF ELECTRICITY BY OTHERS Case No. A VU-E-08-01
W. Johnon, Avista
Schedule 1, p. 1 of 2
Avista Corp.
Power Supply Pro forma. Idaho Jurisdiction
System Numbers. 2007 Actual and 2009 Pro forma (Hydro Adjusted)
2009 Loads
Line Jan 07 - Dec 07 Jan 09 - Dec 09
No.Actuals Adjustment Proforma
48 WNP-3 790 3 793
49 Grant Transmission 512 -512 0
50 Sand Dunes-Warden 11 0 11
51 Black Creek Wheeling 18 4 22
52 Wheeling for System Sales & Purchases 1,278 0 1,278
53 PTP for Colstrip & Coyote 7,822 653 8,475
54 BPA Townsend-Garrison Wheeling 1,173 0 1,173
55 Avista on BPA - Borderline 1,098 237 1,335
56 Kootenai for Worley 32 48 80
57 Sagle-Northern Lights 89 45 134
58 Garrison-Burke 388 0 388
59 PGE Firm Wheeling 643 0 643
60 Total Account 565 13,854 478 14,332
536 WATER FOR POWER
61 Headwater Benefits Payments 651 8 659
549 MISC OTHER GENERATION EXPENSE
62 Rathdrum Municipal Payment 155 5 160
63 ITOTAL EXPENSE 347,782 -91,027 256,7551
447 SALES FOR RESALE
64 Short-Term Market Sales 87,895 -22,845 65,050
65 Peaker (PGE) Capacity Sale 1,800 0 1,800
66 Nichols Pumping Sale 2,900 996 3,896
67 Sovereign/Kaiser DES 536 -475 61
68 Pend Oreile DES & Spinning 709 -319 390
69 NorthWestern Load Following 3,138 -324 2,814
70 SMUDSale 39,393 -33,816 5,577
71 Ancilary Services 662 -662 0
72 Spokane Energy Service Fee - Peaker Sale -57 0 -57
73 BPA NT Deviation Energy 1,634 -1,634 0
74 Total Accunt 447 138,610 -59,079 79,531
456 OTHER ELECTRIC REVENUE
75 Renewable Energy Credit Sales 11 -11 0
76 Gas Not Consumed Sales Revenue 13,031 -13,031 0
77 Total Accunt 456 13,042 -13,042 0
453 SALES OF WATER AND WATER POWER
78 Upstream Storage Revenue 309 -19 290
454 MISC RENTS
79 Colstrip Rents 21 2 23
80 ITOTAL REVENUE 151,982 -72,138 79,8441
81 ITOTAL NET EXPENSE 195,800 -18,890 176,9101
82 Potlatch Purchase Assigned to Idaho 19,861
83 Total Adjustment Including Potlatch 971
Exhibit No.6
Case No. A VU-E-08-01
W. Johnon, Avista
Schedule 1, p. 2 of2
1 A vista Corp.
2 Brief Description of Power Supply Adjustments
3
4 Line No.
5 1 Short-term Market Purchases - Short-term purchases are normalized
6 through use of the AURORA Dispatch Simulation ModeL. The proforma
7 value reflects the short-term purchases durng the proforma period from the
8 dispatch simulation study.
9
10 2 Rocky Reach - The proforma cost for Rocky Reach is based on Chelan
11 PUD's budgeted expenses. Avista's costs are based on the Company's 2.9%12 share of total cost.
13
14 3 Wanapum - Proforma costs are based on Grant County PUD's Power Cost
15 Forecast for Wanapum. Avista's costs are based on the Company's 8.2% share
16 of total Wanapum costs for Janua 2009 through October 2009. The
17 Wanapum contract expires October 31, 2009. Beginnng November 2009
18 Wanapum becomes par of the Priest Rapids Project and Wanapum costs are
19 included in the Priest Rapids Project costs for November and December 2009.
20
21 4 Wells - Wells' costs are based on Douglas PUD's Power Purchaser's Pro-
22 Forma Statement. Avista's costs are based on the Company's 3.5% share of23 total cost.
24
25 5 Priest Rapids Project - Priest Rapids Project expense includes the expense
26 related to the purchased power from the Priest Rapids development for the
27 entire pro forma year and purchased power from the Wanapum development
28 for the months of November and December 2009.
29
30 6 Grant Displacement - Grant Displacement is scheduled energy from Grant
31 PUD that is priced at the Grant's cost.
32
33 7 Douglas Settlement - Douglas Settlement is for a small (approx. 4 aM of
34 power Avista purchases from Douglas PUD.
35
36 8 WNP-3 - Pro forma costs are based on the amount of energy and the lesser of
37 the actual rate or the midpoint. The pro forma uses the actual rate for contract
38 year 2007 though 2008 escalated at the 5-year average escalation rate to the39 pro forma perod.
40
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 1 of 8
1 9 Deer Lake-IP&L - Proforma expense is for power purchased from Inand
2 Power to serve A vista customers.
3
4 10 Small Power - Proforma costs are based on an expected generation and
5 proforma perod contract rates. (Contract details are provided in a
6 CONFIDENTIA workpaper).
7
8 11 Stison - Ths purchase is from the cogeneration plant at Plumer, Idaho.
9 Proforma costs are based on expected generation and proforma period contract10 rates.
11
12 12 Spokane-Upriver - Proforma expense is based on the new contract effective
13 July 2004. Proforma expense is based on a purchase on the net of pumping (at
14 the plant) generation at a rate equal to the 8 year levelized avoided cost
15 included in the Company's 2003 hitegrated Resource Plan.
16
17 13 Douglas Exchange Capacity - Proforma is $0 because A vista bids anually
18 for this capacity.
19
20 14 Seattle Exchange Capacity - Proforma is $0 because contract terminates Sep.
21 30,2008.
22
23 15 Black Creek Index Purchase - Expense is for an October purchase at index
24 prices less tranmission expense and a margin.
25
26 16 Non-Monetary - Expense is normalized to $0 in the proforma.
27
28 17 Contract A - Ths is a power purchase for the perod Januar 2007 though
29 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
30
31 18 Contract B - Ths is a power purchase for the period Januar 2007 though
32 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
33
34 19 Contract C - Ths is a power purchase for the period Januar 2007 though
35 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
36
37 20 Contract D - This is a power purchase for the perod Januar 2007 though
38 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
39
40 21 CS2 Exchange - Proforma is $0 because contract terminates Dec. 31, 2007.
41
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 2 of 8
1 22 TRC Purpa Purchase - The TRC (Thompson River Cogen) purchase is an
2 agreement to purchase power from a qualifyng cogeneration facility.
3
4 23 NorthWestern Load Following Deviation Energy - Proforma expense is $0
5 because deviation energy is priced at market and is not included In AURORA6 modeL.
7
8 24 BP A NT Deviation Energy - Proforma expense is $0 because deviation
9 energy is priced at market and is not included In AURORA modeL.
10
11 25 Grant Transmission Losses - Proforma expense is $0 because losses energy
12 is priced at market and is not included In AURORA modeL. Contract ended
13 October 2007.
14
15 26 Potlatch Co-Gen Purchase - Pro forma expense is $0 because Potlatch
16 purchase expense is directly assigned to the Idaho jursdiction and is not
17 included in system power supply expense.
18
19 27 BPA Spinning Reserve - Pro forma expense is for a purchase of spinng
20 reserves from BP A during the months of May and June that matches the test
21 year purchase expense.
22
23 28 Ancilary Services - Proforma expense is $0 because ths is an intra-utility
24 expense (matching revenue in Account 447).
25
26 29 PPM-Statelie Wind Purchase - Proforma expense is for a 10-year purchase
27 from a Northwest wind project. Expense is based on expected energy amount
28 times the contract rate. (Contract details are provided in a CONFIDENTIA
29 workpaper).
30
31 30 Total Account 555
32
33 31 Broker Commssion Fees - Proforma expense is associated with purchases
34 and sales of electrcity and natual gas fueL.
35
36 32 REC Purchases - Expense is for the purchase of Californa certifiable
37 renewable Energy Credits to support the SMU Sale.
38
39 33 Bankruptcy Write-Off - Expense was for revenue the Company accounted
40 for but never received. Proforma expense is $0.
41
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 3 of 8
1 34 Natural Gas Fuel Purchases - This is the expense for natual gas purchased
2 for but not consumed for generation. Proforma expense is $0 because all gas
3 purchased is assumed to be used for generation, and included in Account 547.
4
5 35 Total Account 557
6
7 36 Kettle Falls Wood Fuel Cost - Proforma fuel expense is based on the
8 generation of the Kettle Falls plant in the AURORA Model and the projected
9 unt cost of fueL.
10
11 37 Kettle Falls Gas Fuel Cost - Proforma expense is $0 because natual gas is
12 not a Kettle Falls fuel option in the AURORA modeL.
13
14 38 Colstrip Coal Cost - Proforma fuel expense is based on the generation of the
15 Colstrp plant in the AURORA Model and the projected unit cost of fueL.
16
17 39 Colstrip Oil- Proforma expense is for star-up oil expense.
18
19 40 Total Account 501
20
21 41 Coyote Springs Gas - Proforma expense is an output of the AURORA Model
22 based on the projected unit cost of fuel and the dispatch of the plant, which
23 determines the volume of fuel consumed.
24
25 42 Gas Transportation Charge - Ths expense is for transportation of natural
26 gas from AECO to the Coyote Springs 2 plant. Proforma expense is based on
27 transportation charges in Canada and from the Canadian Border (Kngs gate )
28 and for the Coyote Springs lateraL.
29
30 43 Rathdrum Gas - Proforma expense is an output of the AURORA Model
31 based on the projected unt cost of fuel and the dispatch of the plant, which
32 determines the volume of fuel consumed.
33
34 44 Northeast CT Gas - Proforma expense is an output of the AURORA Model
35 based on the projected unt cost of fuel and the dispatch of the plant, which
36 deterines the volume of fuel consumed.
37
38 45 Boulder Park Gas - Proforma expense is an output of the AURORA Model
39 based on the projected unt cost of fuel and the dispatch of the plant, which
40 determines the volume of fuel consumed. .
41
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 4 of 8
1 46 Kettle Falls CT Gas - Proforma expense is an output of the AURORA Model
2 based on the projected unt cost of fuel and the dispatch of the plant, which
3 deterines the volume of fuel consumed.
4
5 47 Total Account 547
6
7 48 WNP-3 Transmission - Proforma WN-3 wheeling is based on 32.22 MW at
8 a rate of$2.05/kW/mo.
9
10 49 Grant Transmission - Pro forma expense is $0 because contract ended
11 October 2007.
12
13 50 Sand Dunes-Warden - Pro forma expense is $0 because contract ended
14 October 2007.
15
16 51 Black Creek Wheelig - Expense is for wheeling and shaping associated
17 with the Black Creek power purchase.
18
19 52 Wheelig for System Sales and Purchases - Proforma expense is short-term
20 transmission purchases.
21
22 53 BPA PTP Wheelig for Colstrip and Coyotes Springs 2- This wheeling is
23 for the transmission of 196 MW from Colstrp at the Garson substation and
24 272 MW from the Coyote Sprigs 2 plant to Avista's system. Proforma
25 expense is based on 468 MW of capacity at a rate of $1.509/kW Imo.
26
27 54 BPA Townsend-Garrison Wheelig - Ths expense is for the transmission of
28 Colstrp power from the Townsend substation to the Garson substation.
29
30 55 AVIsta on BPA Borderlie - Ths expense is to serve Avista load offofBPA
31 transmission. Proforma expense is based on Avista's borderline loads priced
32 at BP A's NT transmission rates plus ancilar serces cost and use of facilities33 charges.
34
35 56 Kootenai for Worley - This expense is for A vista load sered using Kootenai36 PUD's facilities.
37
38 57 Sagle-Northern Lights - Expense is for transmission purchased from
39 Northern Light Utility to serve A vista customers in northern Idaho.
40
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 5 of 8
1 58 Garrison Burke - Garson Burke wheeling is an expense for the transmission
2 of. Colstrp energy above 196 MW frm the Garson substation over
3 Nortwester Energy's transmission system to the interconnection of
4 Nortwestern Energy and Avista.
5
6 59 PGE Firm Wheelig - PGE Firm wheeling reflects the cost of transmission
7 from the John Day substation to COB (Interie South) purchased from Portland
8 General Electrc. The Proforma expense is based on 100 MW at the curent
9 rate of$.53549/kW/mo.
10
11 60 Total Account 565
12
13 61 Headwater Benefits Expense - Proforma expense is based on the expense for
14 contract year September 2007 though August 2008
15
16 62 Rathdrum Municipal Payment - Ths includes a payment in Jan. 2009 of
17 $160,000 to the city of Rathdr for mitigation related to the Rathdr18 generating facilty.
19
20 63 Total Expenses - Sum of Accounts 555,557,501,547,565,536, and 549.
21
22 64 Short-Term Market Sales - Short-ter sales voluies and market prices are
23 normalized though use of the AURORA Model simulation. The pro forma
24 revenue reflects the short-ter sales durng the pro forma period from the
25 dispatch simulation study.
26
27 65 Peaker (PGE) Capacity Sale - Ths proforma revenue is based on 150 MW
28 of capacity at a price of$I/kW/mo.
29
30 66 Nichols Pumping Sale - This is a sale of energy to other Colstrp Units 3 and
31 4 owners at the Mid Columbia index price. Proforma revenue is based on
32 approximately 8 MW at the market price as determined by the AURORA
33 modeL.
34
35 67 Kaiser DES - Ths contract provides load control servces to Kaiser's
36 Trentwood plant. (Contract details are provided in a CONFIDENT
37 workpaper).
38
39 68 Pend Oreile DES & Spinning Reserves - This contract provides load
40 control and spinnng reseres for Pend Oreile PUD. (Contract detais are
41 provided in a CONFIDENTIA workpaper).
42
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 6 of 8
1 69 Northwestern Load Following - Ths contract provides load following
2 capacity to Nortwestern Energy. (Contract details are provided in a
3 CONFIDENTIA workpaper).
4
5 70 SMU Sale - Proforma revenue is the expected margi (margi only, not
6 including index priced energy) from the sale of energy and associated
7 renewable energy credits.
8
9 71 Ancilary Servces - Proforma revenue is $0 because it is intra-utility revenue
10 (matching expense in Account 555).
11
12 72 Spokane Energy Servce Fee - Peaker Sale - Expense is for the scheduling of
13 the Peaker (portland General) capacity sales. Most of the expense is offset
14 with Account 456 revenue.
15
16 73 BP A NT Deviation Energy - Proforma revenue is $0 because deviation
17 energy is priced at index and is not included in the AURORA modeL.
18
19 74 Total Account 447
20
21 75 Renewable energy Credit Sales - Proforma revenue is $0 because 2007
22 revenue was only for short-ter renewable energy credit sales.
23
24 76 Gas Not Consumed Sales Revenue - Ths is the revenue for natual gas
25 purchased for but not consumed for generation. Proforma expene is $0
26 because all gas purchased is assumed to be used for generation, and included27 in Account 547.
28
29 77 Total Account 456
30
31 78 Upstream Storage Revenue - Proforma revenue is based on the revenue for
32 contract year September 2007 through August 2008.
33
34 79 Colstrip Rents - Proforma revenue is based on expected revenue.
35
36 80 Total Revenue - Sum of Accounts 447, 456, 453 and 454.
37
38 81 Total Net Expense - Total expense minus total revenue.
39
40 82 Potlatch Purchase Assigned to Idaho - This line shows the Potlatch
41 purchase adjustment. The Potlatch expense is directly assigned to Idaho and is
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 7 of 8
1 not included in the pro forma system power supply expense. The Potlatch
2 purchase expense is included in the adjustment in line 83 to show the total
3 adjustment from 2007 actu expense (includes Potlatch) to the proforma.
4
5 83 Total Adjustment Includig Potlatch - Ths is the total adjustment in power
6 supply expense factonng in the Potlatch purchase expense directly assigned to
7 Idaho.
8
Exhibit NO.6
Case No. AVU-E-08-01
W. Johnson, Avista
Schedule 2, p. 8 of 8
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