HomeMy WebLinkAbout20100323Johnson Di Revised 04-13.pdfDAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727TELEPHONE: (509l 495-4316FACSIMILE: (509) 495-8851
ir:
Mm17A? 2'",i J Arll/:04
BEFORE THE IDAHO PUBLIC UTILITIES CO~SSION
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC )
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO )
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
CASE NO. AVU-E-10-01
DIRECT TEiTIMONY
OF
WILLIAM G. JOHNSON
1
2
I.INTRODUCTION
Q.Please state your name, business addess, 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 Uni versi ty of Montana in 1985.
13 Q.How long have you been emloyed 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.What 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
25 January 2009 through December 2009 test period power supply
Johnson, Di 1
Avista Corporation
1 .revenues and expenses, and 2) describe the proposed level
2 of authorized expense and retail revenue credit for the
3 Power Cost Adjustment (PCA) calculation purposes, using the
4 pro forma costs proposed by the Company in this filing.
5 Q.Are you sponsoring any exhibits to be introduced
6 in this proceeding?
7 A.Yes. I am sponsoring Exhibit No.6, Schedules 1
8 through 4, which were prepared under my supervision and
9 direction.
10 Q.Are other company witnesses providing testimony
11 regarding issues you are addressing?
12 A.Yes.Company witness Mr. Kalich provides
13 detailed testimony on the AURORA model used. by the Company
14 to develop short-term power purchase expense, fuel expense
15 and short-term power sales revenue included in my exhibits.
16
17
18
II. OVERIEW OF PRO FORM POWER SUPPLY ADJUSTM
Q.Please provide an overview of the pro form power
19 supply adjustmnt.
20 A.The pro forma power supply adj ustment involves
21 the determination of revenues and expenses based on the
22 generation and dispatch of Company resources and expected
23 wholesale market power prices as determined by the AURORA
24 model simulation for the pro forma period.In addition,
25 adjustments are made to reflect contract changes between
Johnson, Di 2
Avista Corporation
CASE NO. AVU-E-IO-Ol ri¡:I"..I' !r:\..- B J:i " ~i ¡-.. "ú", i! i
2ßiD APR 13 AM 10: 30
CORRECTED PAGES (3, 6, 7, and
TO WILLIAM G. JOHNSON DIRECT TESTIMONY
(Marked)
REVISED APRI 12, 2010
1 the 2009 calendar-year test period and the pro forma period
2 October 2010 to September 2011.The table below shows
3 total net power supply expense during the test period and
4 the pro forma period.For information purposes only, the
5 power supply expense! currently in rates, which is based on
6 a July 2009 through June 2010 pro forma period, is also
7 shown.
Idaho
System Allocation
Power Supply Expense in Current Base Rates $169,037,000
Actual Jan 09 - De 09 Power Supply Expense $189,811,000
Adjustment to Test Period $29,376,000 $10,319,789
Proposed Pro forma Power Supply Expense $219,187,000
Increase frm Expense in Current Rates $50,150,000 $17,617,6958
9 The net effect of my adjustments to the test year
10 power supply expense is an increase of $29, 376,000
11 ($219,187,000 - $189,811, 000) on a system basis. The Idaho
12 allocation of this adjustment of $10,319,789 is
13 incorporated into the revenue requirement calculation for
14 the Idaho jurisdiction by Company witness Ms. Andrews.
15 The increase in power supply expense compared to the
16 authorized level in current base rates is $50,150,000
17 (system) and $17, 617,695 (Idaho allocation) .
i For the remainder of my testiony, for puroses of the power supply adjustment, I will refer to the net of
power supply revenues and expenses as power supply expense for ease of reference.
Johnson, Di 3
Avista Corporation
1 Q.What are the major factors driving the increased
2 power supply expnse in the pro form year over the level
3 of power supply expense currently in base rates?
4 A. This increase in pro forma power supply expense
5 over the expense currently in base rates is based on
6 numerous factors, primarily the inclusion of expenses
7 related to the Lancaster Power Purchase Agreement (PPA),
8 the termination of four low cost power purchases, reduced
9 hydro generation and higher natural gås prices.
10 The Lancaster PPA increases power supply expense by
11 approximately $21.3 million on a system basis or $7.5
12 million for the Idaho allocation.The pro forma in this
13 case includes all expenses and revenues associated with the
Lancaster PPA.These include the Lancaster PPA charges,14
15 gas transportation, transmission and fuel expense.These
16 expenses are partially offset by the value of the
17 generation.The fixed Lancaster PPA expenses, including
18 the PPA charges, gas transportation and transmission are
19 currently tracked in the Power Cost Adjustment (PCA) at
20 100%, while the variable costs and benefits, including
21 natural gas fuel and generation value are tracked in the
22 PCA at the normal 90/10 sharing between ratepayers and the
23 company.
24 Another big driver of increased expense in the pro
25 forma is the loss of four low cost 25 aMW power purchases
Johnson, Oi 4
Avista Corporation
1 that end December 31, 2010. Those four purchases have an
2 average rate of $31. 68/MWh, well below their replacement
3
4
costs.The cost of replacement in the pro forma is
$48. 51/MWh.This leads to an increased expense of $3.6
5 million (Idaho allocation) .
6 Other expense increases are due to decreased hydro
7 generation, higher net wholesale contract costs and
8 increased fuel prices.Lower retail load reduces power
9 supply expense.
10 Hydro generation is lower by 43.4 aMW in the pro forma
11 versus the amount in the current base rates. The loss of
12 hydro generation is due to several factors. The first is a
13 reduction in generation from Avista's plants on the Clark
14 Fork River as explained in Mr. Kalich' s testimony. The
15 second is a reduction in Mid-Columbia purchased hydro
16 generation.This is due to reduced allocation for Avista
17 of Grant County PUD's Priest Rapids Project, and the
18 expiration of Avista' s purchase of the Colville Indian
19 Tribe's share of the Wells project on September 30, 2010.
20 The net impact of reduced hydro generation is an increased
21 expense of $2.5 million (Idaho allocation) .
22 Higher net wholesale contract costs increase power
23 supply expense by $.7 million (Idaho allocation), and is
24 primarily a result of reduced wholesale revenues due to the
Johnson, Di 5
Avista Corporation
REVISED APRI 12, 2010
1 expiration of a load following contract with NorthWestern
2 Energy along with other contract volume and price changes.
3 Higher fuel prices increases power supply expense by
4 $5.3 million (Idaho allocation). This impact is the sum of
5 higher natural gas fuel prices ($4.1 million) and higher
6 net costs at Colstrip and Kettle Falls ($1.2 million).
7 Natural gas prices in this pro forma are $6.26/dth
8 (Stanfield) compared to $4.79/dth in the current base
9 rates.
10 A reduction in retail loads reduces power supply
11 expense by $2.1 million (Idaho allocation). Pro forma
12 system loads are 13.5 aM lower than loads that current
13 rates are based on. Most of this increase is mitigated by
14 the production property adjustment so the net impact of
15 lower retail loads is small.
16 The table below shows the primary factors driving the
17 increase in power supply expense compared to the level in
18 current base rates.
Johnson, Di 6
Avista Corporation
REVISED APRI 12,2010
Power Supply Expense Change
Oct 10-5ep-11 Pro forma vs. Current Authorized
Lancaster $21.3 $7.5
Decreased System Load -$6.0 -$2.1
Low Cost 100 MW Purchase Ends $10.3 $3.6
Reduced Hydro Generation $7.1 $2.5
Colstrip and Kettle Falls Fuel $3.5 $1.2
Purchase Contracts $2.1 $0.7
Higher Natural Gas Prices $11.8 $4.1
Total Power Supply Increase $50.1 $17.61
2
3 III. PRO FORM POWER SUPPLY EXPENSE ADJUSTMNTS
4 Overview
5 Q.Please identify the specific power supply cost
6 i teis that are covered by your testimony and the total
7 adjustment being proposed.
8 A.Exhibi t No.6, Schedule 1 identifies the power
9 supply expense and revenue items that fall within the scope
10 of my testimony.These revenue and expense items are
11 related to power purchases and sales, fuel expenses,
12 transmission expense, and other miscellaneous power supply
13 expenses and revenues.
14 Q.What is the basis for the adjustments to the test
15 period power supply revenues and expenses?
Johnson, Di 7
Avista Corporation
1 A.The purpose of the adjustments to the test period
2 is to normalize power supply expenses for normal weather
3 and normal hydroelectric generation and to reflect known
4 and measurable changes for the pro forma period that retail
5 rates will be in effect.Adj ustments are also made to
6 reflect contract changes from the test period to the pro
7 forma period.
8 The AURORA Model, as explained by Mr. Kalich,
9 dispatches Company resources on an hourly basis and
10 calculates the level of generation from the Company's
11 thermal resources, fuel costs for thermal resources, and
12 the short-term purchases and sales necessary to serve
13 system requirements.
14 Q.Have any changes been made in the calculation of
15 pro form power supply costs from the last general rate
16 case?
17 A.No.The process to develop the pro forma net
18 power supply expense in this case is the same as in the
19 2009 general rate case.
20 A brief description of each adjustment is provided in
21 Exhibit No.6, Schedule 2.Detailed workpapers have been
22 provided to the Commission coincident to this filing to
23 support each of the pro forma revenues and expenses.The
24 detailed workpapers for each adjustment show the actual
Johnson, Di 8
Avista Corporation
1 revenue or expense in the test period, and the pro forma
2 revenue or expense.
3 Long-Term Contracts
4 Q.How are long-term power contracts included in
5 the pro form?
6 A.Long-term power contracts are included in the pro
7 forma by including the energy receipt or obligation
8 associated with the contract in the AURORA model and
9 including the cost or revenue in the pro forma net power
10 supply expense.
11 Q.Are there any new long-term power purchases or
12 sales in the pro form?
13 A.Yes. This pro forma includes the expenses and
14 revenues related to the Lancaster power purchase agreement.
15 These expenses and revenues are not in the authorized power
16 supply expense supporting current base rates and are being
17 tracked in the PCA.
18 Q.Are there any power purchases or sales that are
19 in current base rates but not in this pro form?
20 A.Yes.As stated earlier, one of the larger
21 factors driving expenses higher is the expiration of four
22 low cost 25 aMW purchases at the end of 2010.Also as
23 discussed earlier, the company's purchase of the Colville
24 Indian Tribe's share of Wells dam ends September 30, 2010.
Johnson, Di 9
Avista Corporation
1 On the revenue side, the load following contract with
2 NorthWestern Energy ends January 9, 2011.
3 Short-Term Power Purchases and Sales
4 Q.How are short-term transactions included in the
5 pro form?
6
7
A.Short-term electric power purchases and sales are
an output of the AURORA model.The model calculates both
8 the volumes and price of short-term purchases and sales
9 that balance the system's generation and long-term
10 purchases with retail load and other obligations.The
11 price of' the short-term transactions represents the price
12 of spot market power as determined by the AURORA model.
13 Therml Fuel Expense
14 Q.How are therml fuel expenses determned in the
15 pro form?
16 A.Thermal fuel expenses include Colstrip coal
17 costs, Kettle Falls wood waste costs and natural gas
18 expense for the Company's gas-fired resources consisting of
19 Coyote Springs 2, Lancaster PPA, Rathdrum, Northeast,
20 Boulder Park, and the Kettle Falls combustion turbine.
21 Unit coal costs at Colstrip are based on the long-term coal
22 supply and transportation agreements. Unit wood fuel costs
23 at Kettle Falls are based on multiple shorter-term
24 contracts with fuel suppliers and inventory.Total fuel
25 costs for each plant are based on the unit fuel cost and
Johnson, Di 10
Avista Corporation
1 the plant's level of generation as determined by the AURORA
2 model. Exhibit No.6, Schedule 3 shows the pro forma fuel
3 costs by month for each plant. Mr. Kalich provides details
4 and supporting workpapers regarding the level of generation
5 for the Company's thermal plants, and the fuel costs for
6 the natural gas-fired and thermal plants.
7 Transmission Expense
8 Q. What changes in transmission expense are in the
9 pro form compared to the test year or the current base
10 rates?
11 The pro forma in this case includes the purchase of
12 250 MW of BPA point-to-point transmission for the Lancaster
13 plant.The annual cost of this transmission is $4.5
14 million (system basis) .
15
16 iv. PCA CACULTIONS
17 Proposed Changes to the PCA
18
19
Q.Is the Company proposing any changes to the PCA?
A.Yes.The Company is proposing to remove the
20 separate 100% tracking of Lancaster fixed expenses in the
21 PCA as all of Lancaster PPA's related expenses and revenues
22 will be included in the authorized power supply expense in
23 the PCA.
24
25
Johnson, Di 11
Avista Corporation
REVISED APRI 12, 2010
1 New Authorized power Supply and Transmission Exense
2 Q.What is the authorized power supply exense and
3 revenue proposed by the Company for the PCA?
4
5
A.The proposed authorized level of annual system
power supply expense is $200,570,792.This is the sum of
6 Accounts 555 (Purchased power), 501 (Thermal Fuel), 547
7 (Fuel), less Account 447 (Sale for Resale).The proposed
8 level of Transmission Expense is $17, 64~, 340. The proposed
9 level of Transmission Revenue is $12,388,460.
10 The level of retail sales and the retail revenue
11 credit will also be updated. The proposed authorized level
12 of retail sales to be used in the PCA is the October 2009
13 through September 2011 pro forma retail sales.The
14 proposed retail revenue credit is $50. 26/MW, which is the
15 average cost of production/transmission in this filing.
16 The proposed authorized monthly PCA expense and
17 revenue is shown in Exhibit 6, Schedule 4.
18 Q.Does that conclude your pre-filed direct
19 testimony?
20 A. Yes.
Johnson, Di 12
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P . O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-8851
DAVID. MEYER~AVISTACORP. COM
BEFORE THE IDAHO PUBLIC UTILITIES COMNSSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-10-01
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)
REVISED APRIL 6, 2010 - .,,',,1; \1 'c,~~:j'"'
555 PURCHASED POWER
1 Modeled Short-Term Market Purchases $0 $31,363 $31,363
2 Actual ST Market Purchases - Physical 198,063 -198,063 0
3 Rocky Reach 1,658 439 2,097
4 Wanapum 4,989 -4,989 0
5 Wells - Avista Share 1,412 140 1,552
6 Wells - Colville Tribe's Share 11,202 -11,202 0
7 Priest Rapids Project 4,999 692 5,691
8 Grant Displacement 5,333 326 5,659
9 Douglas Settlement 365 219 584
10 Lancaster Capacity Payment 0 20,999 20,999
11 Lancaster Variable O&M Payments 0 2,555 2,555
12 Lancaster BPA Reserves 0 744 744
13 WNP-3 14,078 -1,825 12,253
14 Deer Lake-IP&L 7 0 7
15 Small Power 904 115 1,019
16 Stimson 1,865 300 2,165
17 Spokane-Upriver 1,792 211 2,003
18 Douglas Exchange Capacity 1,511 -1,511 0
19 Seattle Exchange Capacity 1,535 -1,535 0
20 Black Creek Index Purchase 139 -5 134
21 Non-Monetary -142 142 0
22 Contract A 6,789 -5,077 1,712
23 Contract B 6,745 -5,044 1,701
24 Contract C 6,657 -4,978 1,679
25 Contract D 7,556 -5,651 1,905
26 Northwestern Deviation Energy 1,661 -1,661 0
27 BPA NT Deviation Energy 1,101 -1,101 0
28 Clearwater Paper Co-Geri Purchase 19,413 -19,413 0
29 Spinning Reserve Purchase 622 0 622
30 Ancilary Services 686 -686 0
31 Stateline Wind Purchase 2,846 685 3,531
32 Total Account 555 303,786 -203,811 99,975
557 OTHER EXPENSES
33 Broker Commission Fees 124 0 124
34 REC Purchases 350 0 350
35 Natural Gas Fuel Purchases 32,480 -32,480 0
36 Total Account 557 32,954 -32,480 474
501 THERMAL FUEL EXPENSE
37 Kettle Falls - Wood Fuel 7,450 2,830 10,280
38 Kettle Falls - Start-up Gas 47 0 47
39 Colstrip - Coal 13,336 7,012 20,348
40 Colstip - Oil 113 85 198
41 Total Account 501 20,946 9,927 30,873
547 OTHER FUEL EXPENSE
42 Coyote Springs Gas 57,429 -2,651 54,778
43 CS2 Gas Transportation Charge 6,832 1,052 7,884
44 Lancaster Gas 0 57,669 57,669
45 Lancaster Gas Transportation Charge 0 6,014 6,014
46 Lancaster Gas Transportation Optimization 0 -392 -392
47 Rathdrum Gas 2,628 -2,285 343
48 Northeast CT Gas 3 73 76
49 Boulder Park Gas 1,461 -1,276 185
50 Kettle Falls CT Gas 303 -101 202
51 Total Account 547 68,656 58,102 126,758 Exhibit NO.6
Case No. AVU.E.10.01
W. Johnson, Avista
Schedule 1, p. 1 of 2
Avista Corp.
Power Supply Pro forma . Idaho Jurisdiction
System Numbers. Jan 2009 . Dec 2009 Actual and Oct 2010 . Sep 2011 Pro Forma
Jan ~~t~~I:c 09 Adjustment oc~:~ ~;i1~1'~1tl:Pd~-)):N,i\ \~3 S
26m ~PR \ '3 ~M H= 43
Line
No.
REVISED APRIL 6, 2010
r. ~,ç- \l,;-,./ ;,,,,'
Line
No.
Avista Corp.
Power Supply Pro forma . Idaho Jurisdiction
System Numbers - Jan 2009 . Dec 2009 Actual and Oct 2010 . Sep 2011 Pro Forma ," " . ,',
\ü,L\h\)Oct 10 - Sep 11TìUT\ I::;':;
Adjustment Pro forma .~
ia\o APR \ '3 AM \\: 43
Jan 09 - Dec 09
Actuals
565 TRANSMISSION OF ELECTRICITY BY OTHERS
52 WNP-3 789 0 789
53 Sand Dunes-Warden 13 0 13
54 Black Creek Wheeling 25 -4 21
55 Wheeling for System Sales & Purchases 332 0 332
56 PTP Transmission for Colstrip & Coyote 8,432 -2 8,430
57 PTP Transmission for Lancaster 0 4,503 4,503
58 Redirected Lancaster Transmission 0 -241 .241
59 BPA Townsend-Garrison Wheeling 1,173 0 1,173
60 Avista on BPA - Borderline 1,530 0 1,530
61 Kootenai for Worley 45 0 45
62 Sagle-Northern Lights 140 0 140
63 Garrison-Burke 226 44 270
64 PGE Firm Wheeling 647 -4 643
65 Total Account 565 13,352 4,296 17,648
536 WATER FOR POWER
66 Headwater Benefis Payments 716 7 723
549 MISC OTHER GENERATION EXPENSE
67 Rathdrum Municipal Payment 160 0 160
68 ITOTAL EXPENSE 440,570 -163,960 276,6101
447 SALES FOR RESALE
69 Modeled Short-Term Market Sales 0 45,214 45,214
70 Actual ST Market Sales - Physical 158,707 -158,707 0
71 Peaker (PGE) Capacity Sale 1,748 0 1,748
72 Nichols Pumping Sale 1,642 1,511 3,153
73 Sovereign/Kaiser DES 511 -432 79
74 Pend Oreile DES & Spinning 613 -154 459
75 Northwestern Load Following 4,554 -3,556 998
76 NaturEner 313 -313 0
77 SMUD Sale 27,648 -22,265 5,383
78 Ancillary Services 686 -686 0
79 BPA NT Deviation Energy 1,233 -1,233 0
80 Total Account 447 197,655 -140,621 57,034
456 OTHER ELECTRIC REVENUE
81 Renewable Energy Credit Sales 144 .144 0
82 Gas Not Consumed Sales Revenue 33,137 -33,137 0
83 Total Account 456 33,281 -33,281 0
453 SALES OF WATER AND WATER POWER
84 Upstream Storage Revenue 381 -20 361
454 MISC RENTS
85 Colstrip Rents 29 0 29
86 ITOTAL REVENUE 231,346 -173,922 57,4241
87 ITOTAL NET EXPENSE 209,224 9,963 219,1871
88 Clearwater Paper Purchase Assigned to Idaho 19,413
89 Total Adjustment Including Clearwater Paper 29,376
Exhibit NO.6
Case No. AVU.E.10.01
W. Johnson, Avista
Schedule 1, p. 2 of 2
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1 A vista Corp.
2 Brief Description of Power Supply Adjustments
3
4 Line No.
5 1 Modeled Short-term Market Purchases - Short-term purchases from the
6 AURORA Dispatch Simulation ModeL.
7
8 2 Actual ST Market Purchases-Physical - Expense of the actul term physical
9 power transactions in the test year.
10
11 3 Rocky Reach - The Pro forma cost for Rocky Reach is based on Chelan
12 PUD's budgeted expenses. Avista's costs are based on the Company's 2.9%
13 share of total cost. The contrct terminates 10-31-11.
14
15 4 Wanapum - The Wanpum contract expires October 31, 2009. Beginning
16 November 2009 Wanapum becomes par of the Priest Rapids Project and
17 Wanapum costs are included in the Priest Rapids Project costs.
18
19 5 Wells - Avista Share - Wells' costs are based on the Company's 3.34% share
20 of total cost at project costs.
21
22 6 Wells - Colville Tribe's Share - The 2009 test yea included 4.5% of Well's
23 output purchased from the Colvile Indian Tribe that terminates 9-30- 10.
24
25 7 Prest Rapids Project - Priest Rapids Project expense includes the expense
26 related to the purchased power from the Priest Rapids development and power
27 from the Wanapum development.
28
29 8 Grant Displacement - Grant Displacement is scheduled energy from Grant
30 PUD that is priced at Grnt's cost. This contrct ends 9-30-11. .
31
32 9 Douglas Settlement - Douglas Settlement is for power A vista purchases from
33 Douglas PUD per the 1989 Settlement Agreement.
34
35 10 Lancaster Capacity Payment - The Lacaster capacity payment includes a
36 capital payment and a fixed O&M payment.
37
Exhibit No. 6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 1 of 8
1 11 Lancaster Variable Eiiergy Payment - The Lacaster varable energy
2 payment is based on the varable energy rate in the Lacaster Power Puchase
3 Agreement multiplied time the MWh of Lacaste generaion in the pro forma.
4
5 12 Lancaster BPA Reserves - Because Lancaster is in BPA's balancing
6 authority, A vista purchases reserves for the plant from BP A. The expense is
7 based on BPA's reserve rate times 7% of Lancaster generation in the pro
8 forma.
9
10 13 WNP-3 - Pro forma costs are based on the 10wer of actul costs or the
11 midpoint.The pro forma uses the actul rate for contract year 2009 though
12 2010 escalated at the 5..year average escalation rate to the pro forma perod.
13
14 14 Deer Lake-IP&L - Pro forma expense is for power purchased from Inland
15 Power to serve A vista customers.
16
17 15 Small Power - Pro forma costs are based on 5-yea average generation and an
18 averge contract rate.
19
20 16 Stimson - This purchase is from the cogeneration plant at Plumer, Idao.
21 Pro fonn costs are based on 5-year average generation and pro forma perod
22 contract rates.
23
24 17 Spokane-Upriver - Pro forma expense is based on a purchase on the net of
25 pumping (at the plant) generation at the contract rate.
26
27 18 Douglas Exchange Capacity - Pro forma is $0 because Avista bids anually
28 for this capacity.
29
30 19 Seattle Exchange Capacity - Pro forma is $0 because contract terminates 9-
31 30-10.
32
33 20 Black Creek Index Purchase - Expense is for an October purchase at index
34 prices less transmission expense and a margin.
35
36 21 Non-Monetary - Expense is normalized to $0 in the Pro forma.
37
38 22 Contract A - Pro forma expense is for a 2007 though 2010 25 MW power
39 purchase. (Contrct details are provided in a CONFENT workpaper).
40
Exhibit No. 6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 2 of 8
1 23 Contract B - Pro forma expense is for a 2007 though 2010 25 MW power
2 purchase. (Contrt details are provided in a CONFIDENT workpaper).
3
4 24 Contract C - Pro forma expense is for a 2007 though 20 I 0 25 MW power
5 purchase. (Contrt details are provided in a CONFIDENT workpaper).
6
7 25 Contract D - Pro forma expense is for a 2007 though 2010 25 MW power
8 purchase. (Contract details are provided in a CONFIDENTIA workpaper).
9
10 26 NorthWestern Load Following Deviation Energy - Pro forma expene is $0
11 because deviation energy is priced at market and is not included In AURORA
12 modeL.
13
14 27 BPA NT Deviation Energy - Pro forma expense is $0 because deviation
15 energy is priced at market and is not included In AURORA modeL.
16
17 28 Clearwater Paper Co-Gen Purchase - Pro forma expense is $0 because
18 Cleaater Paper purchase expene is directly assigned to the Idao
19 jursdiction and is not included in system power supply expense.
20
21 29 Spinning Reserve Purchase - Pro forma expense is for a purchase of spinning
22 reserves. durng the months of May through July that matches the test year
23 purchase expense. The AURORA model does not include reserves.
24
25 30 Ancilary Servces - Pro forma expense is $0 because this is an intra-utility
26 expense (matching revenue in Account 447).
27
28 31 Stateline Wind Purchase - Pro forma expense is for a 10-year purchase from
29 a Nortwest wid project. Expense is based on expected energy amount times
30 the contract rate. (Contrt details are provided in a CONFIDENTIAL
31 workpaper).
32
33 32 Total Account 555
34
35 33 Broker Commission Fees - Pro forma expense is associated with purchases
36 and sales of electrcity and natul gas fueL.
37
38 34 REC Purchases - Expense is for the purchase of Californa certfiable
39 renewable Energy Credits to support the SMU Sale.
40
Exhibit NO.6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 3 of 8
1 35 Natural Gas Fuel Purchases - This is the expense for natual gas purchased
2 for but not consumed for generation. Pro forma expense is $0 t,cause alI gas
3 purchased is assumed to be used for generation, and included in Account 547.
4
5 36 Total Account 557
6
7 37 Kettle Falls Wood Fuel Cost - Pro forma fuel expense is based on the
8 generation of the Kettle Falls plant in the AURORA Model and the projected
9 unit cost of fueL.
10
11 38 Kette Falls-Start-up Gas - Pro forma expense is for sta-up gas at Kettle
12 Falls and is based on the test-year expense.
13
14 39 Colstrp Coal Cost - Pro forma 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 40 Colstrp Oil - Pro forma expense is for sta-up oil expense. Pro forma is
18 based on a five year average.
19
20 41 Total Account 501
21
22 42 Coyote Sprigs Gas - Pro forma expense is an output of the AURORA Model
23 based on the projected unit cost of fuel and the dispatch of the plant, which
24 determines the volume of fuel consumed.
25
26 43 CS2 Gas Transportation - This expense is for transporttion of natul gas to
27 the Coyote Springs 2 plant.
28
29 44 Lancaster Gas - Pro forma expense is an output of the AURORA Model
30 based on the projected unit cost of fuel and the dispatch
of the plant, which
31 determines the volume of fuel consumed.
32
33 45 Lancaster Gas Transportation - This expense is for natul gas
34 transporttion to the Lancaster plant.
35
36 46 Lancaster Gas Transportation Optimiation - This credit to expene is
37 based on optimizing the gas transporttion contrcts for Coyote Sprigs 2 and
38 Lancaster. In general, this involves trading the gas price spread between
39 ABCD (Canada) and Malin.
40
41
Exhibit NO.6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 4 of 8
1 47 Rathdrum Gas - Pro forma expense is an output of the AURORA Model
2 based on the projecte unit cost of fuel and the dispatch of the plant, which
3 determines the volume of fuel consumed.
4
5 48 Northeast CT Gas - Pro forma expense is an output of the AURORA Model
6 based on the projected unit cost of fuel and the dispatch of theplant, which
7 deteines the volume of fuel consumed.
8
9 49 Boulder Park Gas - Pro forma expense is an output of the AURORA Model
10 based on the projected unit cost of fuel and the dispatch of the plant, which
11 determines the volume of fuel consumed.
12
13 50 Kette Falls CT Gas - Pro forma expense is an output of the AURORA Model
14 based on the projected unit cost of fuel and the dispatch of the plant, which
15 determines the volume of fuel consumed.
16
17 51 Total Account 547
18
19 52 WNP-3 Transmission - Pro forma WN-3 trsmission is based on 32.22
20 MW at a rate of $2.04/kW Imo.
21
22 53 Sand Dunes-Warden - Pro forma expense is for a tranmission expense with
23 GrantPUD.
24
25 54 Black Creek Wheeling - Expense is for wheeling and shaping associated with
26 the Black Creek power purchase.The purchase rate is reduced by the
27 wheeling expense.
28
29 55 Wheeling for System Sales and Purchases - Pro forma expense is for short-
30 term transmission purhases.
31
32 56 PTP for Colstrp and Coyotes Springs 2 - This wheeling is for the
33 transmission of 196 MW from Colstrp at the Garson substation and 272
34 MW frm the Coyote Sprigs 2 plant to Avista's system. Pro forma expene
35 is based on 468 MW of capacity at a rate of$1.501/kW/mo.
36
37 57 PTP for Lancaster - This wheeling is for the transmission from the Lacaster
38 plant to Avista's system. Pro forma expense is based on 250 MW of capacity
39 at a rate of$1.501/kW/mo.
40
Exhibit No.6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 5 of 8
1 58 Redirected Lancaster Transmission - This credit is for the Lacaster
2 tranmission that is redrected and used when the plant is off-line or not
3 operating at full capacity.
4
5 59 BPA Townsend-Garrison Wheelig - This expense is for the trmission
6 of Colstrp power from the Townsend substation to the Garson substation.
7
8 60 A vista on BP A Borderline - This expene is to serve A vista load off of BP A
9 trsmission. The expense is based on Avista's borderline 10ad priced at
10 BPA's NT transmission rates pIus ancilar servces cost and use of facilties11 charges.
12
13 61 Kootenai for Worley - This expense is for Avista 10ad served using Kootenai14 PUD's facilties.
15
16 62 Sagle-Northern Lights - Expense is for transmission purchased from
17 Nortern Lights Utility to serve A vista customers.
18
19 63 Garrison Burke - Garson Burke wheeling is an expense for the transmission
20 of Colstrp energy above 196 MW from the Garson substation over
21 Nortwestern Energy's tranmission system to the interconnection of
22 Nortwestern Energy and Avista. Expense is based on a 5-year average.
23
24 64 PGE Fim Wheeling - PGE Fir wheeling reflects the cost of transmission
25 from the John Day substation to COB (Iterte South) purchased from Portland
.26 General Electrc. The Pro forma expense is based on 100 MW at the curent
27 rate of$.53549/kW/mo.
28
29 65 Total Account 565
30
31 66 Headwater Benefits Expense - Pro forma expense is based on the expense for
32 contract year September 2009 though August 2010.
33
34 67 Rathdrum Municipal Payment - This includes a payment in Jan. 2011 of
35 $160,000 to the city of Rathdr for mitigation related to the Rathdr
36 generating facilty.
37
38 68 Total Expenses - Sum of Accounts 555, 557, 501, 547, 565, 536, and 549.
39
40 69 Modeled Short-Term Market Sales - Short-term market sales frm the
41 AURORA Model simulation.
Exhibit NO.6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 6 of 8
1
2 70 Actual ST Market Sales-Physical - Revenue from the actul term
3 transactions in the test year.
4
5 71 Peaker (pGE) Capacity Sale - This Pro forma revenue is based on 150 MW
6 of capacity at a price of $ I/kW Imo less a contrt sericing fee.
7
8 72 Nichols Pumping Sale - This is a sale of energy to other Colstrp Units 3 and
9 4 owners at the Mid Columbia index price less $2.05/MWh. Pro forma
10 revenue is based on approximately 8 MW at the market price (less
11 $2.05/MWh) as determined by the AURORA modeL.
12
13 73 Sovereignliser DES - This contract provides 1000 control services to
14 Kaiser's Trentwood plant. (Contract details are provided in a
15 CONFIDENTIL workpaper).
16
17 74 Pend Oreile DES & Spinning Reserves - This contract provides 1000 control
18 and spinning reserves for Pend Oreile PUD. (Contract details are provided in
19 a CONFIDENTIA workpaper).
20
21 75 Northwestern Load Following - This contract provides load following
22 capacity to NortWestern Energy. Contract ends 1-9-11. (Contrt details are
23 provided in a CONFIDENTIA workpaper).
24
25 76 NaturEner - This contract provides 1000 following capacity to a Montaa
26 wind facilty. Contract ends 6-30-10.
27
28 77 SMU Sale - Pro forma revenue is the expected margin (margin only, not
29 including index priced energy) from the sale of energy and associated
30 renewable energy credits.
31
32 78 Ancilary Servces - Pro forma revenue is $0 because it is intra-utilty revenue
33 (matching expense in Account 555).
34
35 79 BP A NT Deviation Energy - Pro forma revenue is $0 because deviation
36 energy is priced at index and is not included in the AURORA modeL.
37
38 80 Total Account 447
39
40 81 Renewable Energy Credit Sales - Pro forma revenue is $0 because test yea
41 revenue was for non-reoccurng renewable energy credit sales.
Exhibit No. 6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 7 of 8
1
2 82 Gas Not Consumed Sales Revenue - This is the revenue for natual gas
3 purchased for but not consumed for generation. Pro forma expense is $0
4 because all gas purchased is assumed to be used for generation, and included
5 in Account 547.
6
7 83 Total Account 456
8
9 84 Upstream Storage Revenue - Pro forma revenue is based on the revenue for
10 contract year September 2009 though Augut 2010.
11
12 85 Colstrp Rents - Pro forma revenue is based on expected revenue.
13
14 86 Total Revenue - Sum of Accounts 447,456,453 and 454.
15
16 87 Total Net Expense - Total expense minus total revenue.
17
18 88 Clearwater Paper Purchase Assigned to Idaho - This line shows the
19 Clearater Paper purchase adjustment. The Cleaater Paper expene is
20 directly assigned to Idao and is not included in the pro forma system power
21 supplyexpense. The Clearater Paper purchase expense is included in the
22 adjustment in line 89 to show the tota adjustment from test year actul
23 expense (includes Clearater Paper) to the Pro forma.
24
25 89 Total Adjustment Including Clearwater Paper - This is the total adjustment
26 in power supply expense factorig in the Clearater Paper purchase expense
27 directly assigned to Idaho.
28
. Exhibit No.6
Case No. AVU-E-10-01
W. Johnson, Avista
Schedule 2, p. 8 of 8
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