20110706Johnson Di.pdf

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DAVID J. MEYER Z!'q i !1 II !" I" II 1.1.
VICE PRESIDENT AND CHIEF COUNSEL FOR J ¡ ..'jL -J Ht1 : 41-
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P .0. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
DAVID .MEYER~AVISTACORP. COM
L
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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
CASE NO. AVU-E-11-01
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 Uni versi ty 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 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.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 2010 through December 2010 test period power supply
26 revenues and expenses, and 2) describe the proposed level
27 of expense and retail revenue credit for The Power Cost
Johnson, Di 1
Avista Corporation
1 Adjustment (PCA) purposes, using the pro forma costs
2 proposed by the Company in this filing. My testimony also
3 shows the change in power supply expense incorporating the
4 Energy Efficiency Load Adjustment proposed by the Company
5 in this case.
6 Q.Are you sponsoring any exhibits to be introduced
7 in this proceeding?
8 A.Yes.I am sponsoring Exhibit 6, Schedules 1
9 through 5, which were prepared under my supervision and
10 direction. Schedule 1 identifies the power supply expense
11 and revenue items that fall wi thin the scope of my
12 testimony. A brief description of each adjustment is
13 provided in Schedule 2.Schedule 3 shows the pro forma
14 fuel costs and short-term purchase and sales by month for
15 each plant.The proposed authorized PCA power supply
16 expense and revenue, transmission expense and revenue, and
17 retail sales are shown in Schedule 4.Schedule 5
18 identifies the power supply expense and revenue without the
19 Energy Efficiency Load Adjustment, and is provided for
20 information purposes to isolate the impact of the Energy
21 Efficiency Load Adjustment on power supply expense.
22 Q.Are there other Company wi tnesses providing
23 testimony regarding issues you are addressing?
24 A.Yes.Company witness Mr. Kalich provides
25 detailed testimony on the AURORA model used by the Company
26 to develop short-term power purchase expense, fuel expense
27 and short-term power sales revenue included in my
Johnson, Di 2
Avista Corporation
1 Schedules. Mr. Ehrbar addresses the Energy Efficiency Load
2 Adjustment in his testimony.
3
4
5
II. OVERVIEW OF PRO FORM POWER SUPPLY ADJUSTMNT
Q. Please provide an overview of the pro form power
6 supply adjustment.
7 A.The pro forma power supply adjustment involves
8 the determination of revenues and expenses based on the
9 generation and dispatch of Company resources and expected
10 wholesale market power prices as determined by the AURORA
11 model simulation for the pro forma period under normal
12 weather and hydro generation conditions.In addition,
13 adjustments are made to reflect contract changes between
14 the test period and the pro forma period. The table below
15 shows total net power supply expense during the test period
16 and the pro forma period.For information purposes only,
17 the power supply expense1 currently in base retail rates,
18 which is based on an October 2010 through September 2011
19 pro forma period, is also shown.
1 For the remainder of my testimony, for purposes 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
System
Power Supply Expense in Current Base Rates (Oct 2010 - Sep 2011 pro forma) $197,453,000
Actual Jan 10 - Dec 10 Power Supply Expense $190,323,000
Adjustment to Test Period $700,000
Proposed 2012 Pro forma Power Supply Expense - Unadjusted $191,023,000
Increase from Ex ense in Currnt Rates -$6,430,0001
2
3
The net effect of my adjustments to the test year
power supply expense is an increase of $700,000
4 ($191,023,000 - $190,323,000) on a system basis.
5 The decrease in power supply expense compared to the
6 authorized level in current base rates is $6,430,000
7 (system) and $2,240,212 (Idaho allocation).
8 Q.What are the major factors driving the decreased
9 power supply expense in the pro form year over the level
10 of power supply expense currently in base rates?
11
12
A.The level of power supply expense currently in
base rates is $197,453,000 (system number).This expense
13 level is based on an October 2010 through September 2011
14 pro forma period.This compares to the proposed 2012 pro
15 forma power supply expense of $191,023,000, a decrease of
16 approximately $6.4 million on a system basis and an Idaho
17 allocation of approximately $2.2 million.
18 This decrease in pro forma power supply expense over
19 the expense currently in base rates is caused primarily by
20 two factors, lower loads and lower market prices for
21 natural gas and power.Loads are lower by 50.8 aMW from
Johnson, Di 4
Avista Corporation
1 the loads authorized in current based rates, which used a
2 pro forma load proj ection.The reduction in load is a
3 result of using historical test-year loads and including
4 the Energy Efficiency Load adjustment.The reduction in
5 load due to moving from a pro forma year load to a
6 historical test-year load is 30.7 aMW and the reduction in
7 load due to the Energy Efficiency load adjustment is 20.1
8 aMW.
9 Market prices for natural gas and power are both lower
10 than the level included in current base rates. The annual
11 average natural gas price is $4. 62/dth in this case versus
12 $5.04/dth in current base rates.The annual average flat
13 power price is $37. 11/MWh in this case versus $40. 31/MWh in
14 current base rates.
15 Overall, the pro forma in this case has 17.3 aMW more
16 hydro generation than was in the 2010 general rate case.
17 The cost of the Mid-Columbia purchased generation, however,
18 is higher. This is primarily a result of the expiration of
19 the original Rocky Reach purchase agreement, which was
20 priced at project cost (approximately $11. 50/Mwh) .The
21 Rocky Reach and Rock Island purchase in this pro forma was
22 acquired through a competitive bid at market prices.The
23 costs for the other Mid-Columbia generation from the Wells
24 proj ect and the Priest Rapids proj ect are also higher.
25 The net expense of long-term contracts is higher in
26 this case. This is primarily a result of the expiration of
27 the Grant PUD Displacement purchase on September 30, 2011,
Johnson, Di 5
Avista Corporation
1 in which the Company purchases power at a rate equivalent
2 to the BPA Priority Firm price.It also reflects the
3 expiration of some load following sales.
4 The net (net of generation value) cost of thermal and
5 natural gas-fired generation is higher due to increased
6 fuel expense and reduced value of the power produced.
7 The table below shows the primary factors driving the
8 decrease in power supply expense compared to the level in
9 current base rates.
2011 to 2012
Pro forma Idaho
Factor Change Allocation
$millions $millions
Hydro Generation & Mid C Costs $4.4 $1.5
Change in System Load -$14.9 -$5.2
Themal Plant Costs $2.3 $0.8
CCCT Operating Margin $6.9 $2.4
Long-Term Contract Changes $5.4 $1.9
Market Prices Natural Gas & Power -$10.5 -$3.7
2011 to 2012 Power Su i Increase -$6.4 -$2.210
11
12 III. PRO FORM POWER SUPPLY ADJUSTMNTS
13 Overview
14 Q.Please identify the specific power supply cost
15 items that are covered by your testimony and the total
16 adjustment being proposed.
17 A.Schedule 1 identifies the power supply expense
18 and revenue items that fall within the scope of my
Johnson, Di 6
Avista Corporation
1 testimony. These revenue and expense items are related to
2 power purchases and sales, fuel expenses, transmission
3 expense, and other miscellaneous power supply expenses and
4 revenues.
5 Q.What is the basis for the adjustments to the test
6 period power supply revenues and expenses?
7 A.The purpose of the adjustments to the test period
8 is to normalize power supply expenses for normal weather
9 and normal hydroelectric generation and to reflect current
10 forward natural gas prices and other known and measurable
11 changes for the pro forma period.
12 The AURORA Model,as explained by Mr.Kalich,
13 dispatches Company resources using the current forward
14 natural gas prices and calculates the level of generation
15 from the Company's thermal resources, fuel costs for
16 thermal resources, and the short-term purchases and sales
17 necessary to balance system requirements and resources.
18 Q.Are there any changes in how the pro form in
19 this case was developed versus the authorized power supply
20 expense currently in base rates?
21 A.No.wi th the exception of reducing system load
22 due to the use of historical versus pro forma load and the
23 Energy Efficiency Load Adjustment, the process to develop
24 the pro forma net power supply expense in this case is the
25 same as the process used to develop authorized power supply
26 expense in current base rates. The Energy Efficiency Load
27 Adjustment, as further explained later in my testimony,
Johnson, Di 7
Avista Corporation
1 lowers the system load used to develop the pro forma to a
2 level below the weather adjusted test-year load.
3 A brief description of each adjustment is provided in
4 Schedule 2. Detailed workpapers have been provided to the
5 Commission coincident to this filing to support each of the
6 pro forma revenues and expenses.The detailed workpapers
7 for each adjustment show the actual revenue or expense in
8 the test period, and the pro forma revenue or expense.
9 Long-Term Contracts
10 Q.How are long-term power contracts included in the
11 pro form?
12 A.Long-term power contracts are included in the pro
13 forma by including the energy receipt or obligation
14 associated with the contract in the AURORA model and
15 including the cost or revenue in the pro forma net power
16 supply expense.
17 Q.Are there any new power purchases or sales in the
18 pro form that are not in the current base rates?
19 A.Yes. This pro forma includes the expenses and
20 generation related to the purchase of a 3.0% slice of the
21 output of the Rocky Reach and Rock Island dams owned and
22 operated by Chelan PUD.This purchase was made through a
23 competitive auction and has a term of July 2011 through
24 December 2014.The purchase was made to maintain an
25 adequate level of Mid-Columbia generation to provide load
26 shaping and ramping capabilities at the Mid-Columbia, which
Johnson, Di 8
Avista Corporation
, .
1 allows the Company to operate its own hydro facilities in a
2 more efficient manner.
3 Q.Are there any long-term power purchases or sales
4 that are in current base rates but not in this pro form?
5 A.Yes.Four 25 aMW long-term market purchases
6 ended December 31, 2010. The Company's long-term purchase
7 of Rocky Reach generation at project cost ends October 31,
8
9
2011.The Grant PUD Displacement power purchase ends
September 30, 2011.The Black Creek purchase ended March
10 25, 2011. On the revenue side, the load following contract
11 with Northwestern Energy ended January 9, 2011, and the
12 load following contract with NatuEner ends August 31, 2011.
13 Short-Term Power Purchases and Sales
14 Q.How are short-term transactions included in the
15 pro form?
16
17
A.System balancing electric power purchases and
sales are an output of the AURORA model.The model
18 calculates both the volumes and price of short-term
19 purchases and sales that balance the system's generation
20 and long-term purchases with retail load and other
21 obligations.The price of the short-term transactions
22 represents the price of spot market power as determined by
23 the AURORA model.The pro forma does not include any of
24 the actual short-term transactions already entered into for
25 the 2012 pro forma period.
26 Energy Efficiency Load Adjustment
Johnson, Di 9
Avista Corporation
1 Q.How was the net power supply expense adjusted for
2 the proposed Energy Efficiency Load Adjustment that is
3 explained in Mr. Ehrbar' s testimony?
4 A.The power supply pro forma incorporates the
5 reduction in Idaho retail sales shown in Table 12 of Mr.
6 Ehrbar's direct testimony, which was then grossed up for
7 losses and then divided by Idaho's allocation to create a
8 system load reduction. The power supply pro forma was then
9 developed using the lower system load incorporating the
10 Energy Efficiency Load Adjustment.
11 Q.What power supply expenses are affected using the
12 Energy Efficiency Load Adjustment?
13 A.The only accounts affected in the power supply
14 pro forma for the Energy Efficiency Load Adjustment are
15 Account 555, Purchased Power and Account 447, Sales for
16 Resale. Purchased power expense decreased by $3,323,000 on
17 a system basis ($1,150,000 Idaho allocation) and Sales for
18
19
Resale increased by $3,445,000 on a system basis
($1,200,000 Idaho allocation).All other power supply
20 accounts are unaffected by the Energy Efficiency Load
21 Adjustment.Schedule 5 is provided for information
22 purposes and shows the power supply pro forma excluding the
23 Energy Efficiency Load Adjustment. The difference between
24 net power supply costs in Schedule 5 and Schedule 1
25 reflects the change in net power supply costs associated
26 with the Energy Efficiency Load Adjustment.
27 Therml Fuel Expense
Johnson, Di 10
Avista Corporation
1 Q.How are therml fuel expenses determined in the
2 pro form?
3 A.Thermal fuel expenses include Colstrip coal
4 costs, Kettle Falls wood-waste costs and natural gas
5 expense for the Company's gas-fired resources including
6 Coyote Springs 2, Lancaster, Rathdrum, Northeast, Boulder
7 Park, and the Kettle Falls combustion turbine.Unit coal
8 costs at Colstrip are based on the long-term coal supply
9 and transportation agreements.Uni t wood fuel costs at
10 Kettle Falls are based on multiple shorter-term contracts
11 wi th fuel suppliers and inventory.Total fuel costs for
12 each plant are based on the unit fuel cost and the plant's
13 level of generation as determined by the AURORA model.
14 Schedule 3 shows the pro forma fuel costs by month for
15 each plant.Mr. Kalich provides details and supporting
16 workpapers regarding the level of generation for the
17 Company's thermal plants, and the fuel cost for thermal and
18 natural gas-fired plants.
19 Transmission Expense
20 Q.What changes in transmission expense are in the
21 pro form compared to the expense in current base rates?
22 A.The only change in transmission expense is the
23 elimination of the Black Creek wheeling expense since that
24 contract ended March 25, 2011.
25 iv. PCA CACULTIONS
26 New Authorized Power Supply and Transmission Expense
Johnson, Di 11
Avista Corporation
1 Q.What is the authorized power supply expense and
2 revenue proposed by the Company for the PCA?
3
4
A.The proposed authorized level of annual system
power supply expense is $172,632,863.This is the sum of
5 Accounts 555 (Purchased Power), 501 (Thermal Fuel), 547
6 (Fuel), less Account 447 (Sale for Resale). The proposed
7 level of Transmission Expense is $17,641,176. The proposed
8 level of Transmission Revenue is $11,524,732.
9
10
The level of retail sales MWh and the retail revenue
credi t is also updated.The proposed authorized level of
11 retail sales to be used in the PCA is the January 2010
12 through December 2010 weather adjusted retail sales
13 incorporating the Energy Efficiency Load Adjustment.The
14 proposed load change adjustment rate is $26. 33/MWh, which
15 is the energy classification of the average cost of
16 production/transmission in this filing developed by Company
17 wi tness Ms. Knox.
18 The proposed authorized PCA power supply expense and
19 revenue, transmission expense and revenue, and retail sales
20 is shown in Schedule 4.
21 Q.Does that conclude your pre-filed direct
22 testimony?
23 A.Yes.
Johnson, Di 12
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P . O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
DAVID .MEYER~AVISTACORP. COM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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
CASE NO. AVU-E-11-01
EXHIBIT NO. 6
WILLIAM G. JOHNSON
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avista Corp.RECEIVED
Power Supply Pro forma - Idaho Jurisdiction 11 JUl22System Numbers - Jan 2010 - Dec 2010 Acual and Jan 2012 - Dec 2012 Pro Forma AM 10: 08Historic 2010 Loads w/ Energy Effciency Load Adjustment, Without Actual ST Transactions
.f H'~; ;;; ~r ."-.
Line Jan 10 - Dec 10 Jan 12 - Dii1ìd ,L,~"
No.Actuals Adjustment Pro foriá . ."'"'
555 PURCHASED POWER
1 Modeled Short-Term Market Purchases $0 $21,271 $21,271
2 Actual Short-Term Market Purchases 159,193 -159,193 0
3 Rocky Reach 2,172 -2,172 0
4 Rocky Reach/Rock Island Purchase 0 11,384 11,384
5 Wells - Avista Share 1,400 499 1,899
6 Wells - Colville Tribe's Share 9,496 -9,496 0
7 Priest Rapids Project 5,609 785 6,394
8 Wanapum -1,228 1,228 0
9 Grant Displacement 5,653 -5,653 0
10 Douglas Settlement 334 246 580
11 Lancaster Capacity Payment 21,475 578 22,053
12 Lancaster Variable O&M Payments 2,689 -223 2,466
13 Lancaster BPA Reserves 824 -824 0
14 WNP-3 13,920 -368 13,552
15 Deer Lake-IP&L 6 0 6
16 Small Power 1,079 13 1,092
17 Stimson 1,964 402 2,366
18 Spokane-Upriver 2,055 884 2,939
19 Black Creek Index Purchase 234 -234 0
20 Non-Monetary 90 -90 0
21 Contract A 6,789 -6,789 0
22 Contract B 6,745 -6,745 0
23 Contract C 6,658 -6,658 0
24 Contract D 7,556 -7,556 0
25 Clearwter Paper Co-Gen Purchase 18,720 -18,720 0
26 Ancilary Services 631 -631 0
27 Stateline Wind Purchase 3,016 530 3,546
28 Total Accunt 555 277,080 -187,532 89,548
557 OTHER EXPENSES
29 Broker Commission Fees 366 0 366
30 REC Purchases (SMUD)349 1 350
31 Natural Gas Fuel Purchases 119,116 -119,116 0
32 Total Account 557 119,831 -119,115 716
501 THERMAL FUEL EXPENSE
33 Kettle Falls - Wood Fuel 10,551 1,534 12,085
34 Kettle Falls - Start-up Gas 30 0 30
35 ColStrp - Coal 15,984 3,803 19,787
36 Coistip - Oil 139 0 139
37 Total Account 501 26,704 5,336 32,040
547 OTHER FUEL EXPENSE
38 Coyote Springs Gas 53,491 -15,894 37,597
39 Coyote Springs 2 Gas Transportation 7,891 -58 7,833
40 Lancaster Gas 46,902 -6,544 40,358
41 Lancaster Gas Transportation 5,837 956 6,793
42 Lancaster Gas Transportation Optimization 0 -409 -409
43 Gas Transportation for BP, NE and KFCT 32 0 32
44 Rathdrum Gas 545 -544 1
45 Northeast CT Gas 62 -62 0
46 Boulder Park Gas 505 -472 33
47 Kettle Falls CT Gas 185 -136 49
48 Total Account 547 115,450 -23,163 92,287
Exhibit No. 6
Case No. AVU-E-11-01
REVISED JUL Y 21, 2011 W. Johnson, Avista
Schedule 1, p. 1 of 2
Avista Corp.
Power Supply Pro forma. Idaho Jurisdiction
System Numbers - Jan 2010 - Dec 2010 Actual and Jan 2012 - Dec 2012 Pro Forma
Historic 2010 Loads wI Energy Effciency Load Adjustment, Without Actual ST Transactions
Idaho p
lIblle U..
Office ti/¡tlas ri
R Of the \JOm.ê C ê i ~eC~et m'SSion
JUi êD i)222010
Bose, Idao
Line Jan 10 - Dec 10 Jan 12 - Dec 12
No.Actuals Adjustment Proforma
565 TRANSMISSION OF ELECTRICITY BY OTHERS
49 WNP-3 789 0 789
50 Sand Dunes-Warden 9 0 9
51 Black Creek Wheeling 65 -65 0
52 Wheeling for System Sales & Purchases 321 0 321
53 PTP Transmission for Colstnp & Coyote 8,428 2 8,30
54 PTP Transmission for Lancaster 4,541 -38 4,503
55 BPA Townsend-Garnson Wheeling 1,173 0 1,173
56 Avista on BPA - Borderline 1,253 0 1,253
57 Kootenai for Worley 45 0 45
58 Sagle-Nortern Lights 139 0 139
59 Garnson-Burke 337 0 337
60 PGE Firm Wheeling 644 -1 643
61 Total Accunt 565 17,744 -102 17,642
536 WATER FOR POWER
62 Headwater Benefis Payments 853 0 853
549 MISC OTHER GENERATION EXPENSE
63 Rathdrum Municipal Payment 160 0 160
64 ITOTAL EXPENSE 557,822 -324,575 233,2471
447 SALES FOR RESALE
65 Modeled Short-Term Market Sales 0 30,778 30,778
66 Actual Short-Term Market Sales 219,096 -219,096 0
67 Peaker (PGE) Capacity Sale 1,749 0 1,749
68 Nichols Pumping Sale 1,693 688 2,381
69 Sovereign/Kaiser DES 80 0 80
70 Pend Oreile DES & Spinning 419 0 419
71 Northwestern Load Following 3,257 -3,257 0
72 NaturEner 551 -551 0
73 SMUD Sale - Energy and REC 27,761 -21,926 5,835
74 Ancilary Servce 631 -631 0
75 Total Accunt 447 255,237 -213,995 41,242
456 OTHER ELECTRIC REVENUE
76 Renewable Energy Credit Sales 700 0 700
77 Gas Not Consumed Sales Revenue 111,280 -111,280 0
78 Total Account 456 111,980 -111,280 700
453 SALES OF WATER AND WATER POWER
79 Upstream Storage Revenue 282 0 282
80 ITOTAL REVENUE 367,499 -325,275 42,2241
81 ITOTAL NET EXPENSE 190,323 700 191,0231
REVISED JULY 21, 2011
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 1, p. 2 of 2
A vista Corp.
Brief Description of Power Supply Adjustments
Line No.
1 Modeled Short-term Market Purchases - Short-term purchases from the
AURORA Dispatch Simulation ModeL.
2 Actual ST Market Purchases - No actual transactions are included in the pro
forma.
3 Rocky Reach - The pro forma cost for Rocky Reach is $0 because the
contract ends 10-31-11.
4 Rocky ReachlRock Island Purchase - The pro forma expense is based on a
purchase of a portion of Rocky Reach and Rock Island generation beginning
July 1, 2011.
5 Wells - Avista Share - Wells' costs are based on the Company's 3.34% share
of total cost at project costs.
6 Wells - Colvile Tribe's Share - The 2010 test-year included 4.5% of Well's
output purchased from the Colvile Indian Tribe.
7 Priest Rapids Project - Priest Rapids Project expense includes the expense
related to the purchased power from the Priest Rapids development and power
from the Wanapum development.
8 Wanapum - The Wanapum contract ended 10-31-2009. The 2010 test-year
included a tre-up of 2009 payments.
9 Grant Displacement - The 2010 test-year expense included a purchase from
Grant PUD that ends 9-30-11.
10 Douglas Settlement - Douglas Settlement is for power A vista purchases from
Douglas PUD per the 1989 Settlement Agreement.
11 Lancaster Capacity Payment - The Lancaster capacity payment includes a
capital payment and a fixed O&M payment.
12 Lancaster Variable O&M Payments - the Lancaster variable O&M payment
is based on the variable O&M rate in the Lancaster Power Purchase
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 1 of 7
Agreement multiplied times the MWh of Lancaster generation in the pro
forma.
13 Lancaster BP A Reserves - The pro forma expense is $0 because Lancaster
was moved (electronically) into Avista's balancing authority on March 29,
2011 so purchases of generation reserves from BP A are longer required.
14 WNP-3 - Pro forma costs are based on the midpoint. The pro forma uses the
actual midpoint of the ceiling and floor prices identified in the contract for
contract year 2010 through 2011 escalated at the 5-year average escalation rate
to the pro forma period.
15 Deer Lake-IP&L - Pro forma expense is for power purchased from Inland
Power to serve A vista customers.
16 Small Power - Pro forma costs are based on 5-year average generation and an
average contract rate.
17 Stimson - This purchase is from the cogeneration plant at Plummer, Idaho.
Pro forma costs are based on 5-year average generation and pro forma period
contract rates.
18 Spokane-Upriver - Pro forma expense is based on a purchase of the net of
pumping (at the plant) generation at a contract based on Washington's
Schedule 62 avoided cost rates.
19 Black Creek Index Purchase - Pro forma expense is $0 because the contract
ended March 25, 2011.
20 Non-Monetary - Expense is normalized to $0 in the pro forma.
21 Contract A - This contract ended 12-31-10.
22 Contract B - This contract ended 12-31-10.
23 Contract C - This contract ended 12-31-10.
24 Contract D - This contract ended 12-31-10.
25 Clearwater Paper Co-Gen Purchase - Clearwater Paper purchase is directly
assigned in Idaho.
26 Ancilary Services - Pro forma expense is $0 because this is an intra-utilty
expense (matching revenue in Account 447).
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 2 of 7
27 Stateline Wind Purchase - Pro forma expense is $0 because the contract was
scheduled to end 12-31-2011. (It was extended to 4-30-2014 on April 20,
2011, after the pro forma expense was developed).
28 Total Account 555
29 Broker Commission Fees - Pro forma expense is associated with purchases
and sales of electricity and natural gas fueL.
30 REC Purchases - Expense is for the purchase of California certifiable
renewable Energy Credits to support the SMUD Sale.
31 Natural Gas Fuel Purchases - This is the expense for natual gas purchased
for but not consumed for generation. Pro forma expense is $0 because all gas
purchased is assumed to be used for generation, and included in Account 547.
32 Total Account 557
33 Kettle Falls Wood Fuel Cost - Pro forma fuel expense is based on the
generation of the Kettle Falls plant in the AURORA Model and the unit cost
of available fueL.
34 Kettle Faiis~Start~up Gas - Pro forma expense is for start-up gas at Kettle
Falls and is based on the test-year expense.
35 Colstrip Coal Cost - Pro forma fuel expense is based on the generation of the
Colstrip plant in the AURORA Model and the unit cost of fuel under the
contract.
36 Colstrip Oil - Pro forma expense is for start-up oil expense. Pro forma is
based on the test-year expense.
37 Total Account 501
38 Coyote Springs Gas - Pro forma expense is an output of the AURORA
Model based on the pro forma unit cost of fuel and the dispatch of the plant,
which determines the volume of fuel consumed.
39 CS2 Gas Transportation - This expense is for transporttion of natual gas
from AECO to the Coyote Springs 2 plant.
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 3 of 7
40 Lancaster Gas - Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant, which
determines the volume of fuel consumed.
41 Lancaster Gas Transportation - This expense is for natural gas
transportation to the Lancaster plant.
42 Lancaster Gas Transportation Optimization - This credit to expense is
based on optimizing the gas transporttion contracts for Coyote Springs 2 and
Lancaster. In general, this involves trading the gas price spread between
ABCO (Canada) and Malin.
43 Gas Transportation for BP, NE and KFCT - This expense is for
transportation of natual gas to serve Boulder Park, Northeast and Kettle Falls
Combustion Turbine gas-fired plants.
44 Rathdrum Gas - Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant, which
determines the volume of fuel consumed.
45 Northeast CT Gas - Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant
(including test firing), which determines the volume of fuel consumed.
46 Boulder Park Gas - Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant, which
determines the volume of fuel consumed.
47 Kettle Falls CT Gas - Pro forma expense is an output of the AURORA
Model based on the pro forma unit cost of fuel and the dispatch of the plant,
which determines the volume of fuel consumed.
48 Total Account 547
49 WNP-3 Transmission - Pro forma WN-3 wheeling is based on 32.22 MW
at a rate of$2.04/kW/mo.
50 Sand Dunes-Warden - Pro forma expense is for a transmission expense with
GrantPUD.
51 Black Creek Wheeling - Pro forma expense is $0 because the contract ended
March 25, 2011.
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 4 of 7
52 Wheeling for System Sales and Purchases - Pro forma expense is for short-
term transmission purchases.
53 PTP for Colstrip and Coyotes Springs 2- This wheeling is for the
transmission of 196 MW from Colstrip at the Garison substation and 272
MW from the Coyote Springs 2 plant to Avista's system. Pro forma expense
is based on 468 MW of capacity at a rate of $ 1.501/kW/mo.
54 PTP for Lancaster - This wheeling is for the transmission from the Lancaster
plant to Avista's system. Pro forma expense is based on 250 MW of capacity
at a rate of$1.501/kW/mo.
55 BPA Townsend-Garrison Wheeling - This expense is for the transmission of
Colstrp power from the Townsend substation to the Garrison substation.
56 A vista on BPA Borderline - This expense is to serve A vista load off of BP A
transmission. Expense is based on Avista's borderline loads priced at BPA's
NT transmission rates plus ancilary services cost and use of facilties charges.
57 Kootenai for Worley - This expense is for A vista load served using
Kootenai's facilties.
58 Sagle-Northern Lights - Expense is for transmission purchased from
Northern Lights Utilty to serve Avista customers.
59 Garrison Burke - Garrson Burke wheeling is an expense for the
transmission of Colstrip energy above 196 MW from the Garison substation
over Northwestern Energy's transmission system to the interconnection of
Northwestern Energy and A vista.
60 PGE Firm Wheeling - PGE Firm wheeling reflects the cost of transmission
from the John Day substation to COB (Intertie South) purchased from Portland
General Electric. The Pro forma expense is based on 100 MW at the curent
rate of$.53549/kW/mo.
61 Total Account 565
62 Headwater Benefits Expense - Pro forma expense is based on the expense
for contract year September 2010 though August 2011.
63 Rathdrum Municipal Payment - This includes a payment in Jan. 2011 of
$160,000 to the city of Rathdrm for mitigation related to the Rathdr
generating facilty.
64 Total Expenses - Sum of Accounts 555, 557, 501, 547, 565, 536, and 549.
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 5 of 7
65 Modeled Short-Term Market Sales - Short-term market sales from the
AURORA Model simulation.
66 Actual ST Market Sales - No actual transactions are included in the pro
forma.
67 Peaker (pGE) Capacity Sale - This pro forma revenue is based on 150 MW
of capacity at a price of $1/kW/mo less a contract servicing fee. This contrct
is related to the sales of capacity to Portland General Electric, which was
monetized in 1998.
68 Nichols Pumping Sale - This is a sale of energy to other Colstrip Units 3 and
4 owners at the Mid-Columbia index price less $2.05/MWh. Pro forma
revenue is based on approximately 8 aM at the market price (less
$2.05/M) as determined by the AURORA modeL.
69 SovereignlKaiser DES - This contract provides load control services to
Kaiser's Trentwood plant. (Contract details are provided in a
CONFIDENTIAL workpaper).
70 Pend Oreile DES & Spinning Reserves - This contract provides load
control and spinning reserves for Pend Oreile PUD. (Contract details are
provided in a CONFIDENTIA workpaper).
71 Northwestern Load Following - Pro forma revenue is $0 because the
contract ended 1-9-11.
72 NaturEner - This contract provides load following capacity to a Montana
wind facility. Contract ends 08-31-11.
73 SMUD Sale - Pro forma revenue is the expected margin (margin only, not
including index priced energy) from the sale of energy and associated
renewable energy credits.
74 Ancilary Services - Pro forma revenue is $0 because it is intra-utilty
revenue (matching expense in Account 555).
75 Total Account 447
76 Renewable Energy Credit Sales - Pro forma revenue is based on 2010 test-
year revenue for non-reoccuring renewable energy credit sales.
77 Gas Not Consumed Sales Revenue - This is the revenue for natural gas
purchased for but not consumed for generation. Pro forma revenue is $0
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 6 of 7
because all gas purchased is assumed to be used for generation, and included
in Account 547.
78 Total Account 456
79 Upstream Storage Revenue - Pro forma revenue is based on the revenue for
contract year September 2009 through August 2010.
80 Total Revenue - Sum of Accounts 447,456,453 and 454.
81 Total Net Expense - Total expense minus total revenue.
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 2, p. 7 of 7
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Avista Corp.
Power Supply Pro forma. Idaho Jurisdiction
System Numbers - Jan 2010 - Dec 2010 Actual and Jan 2012 - Dec 2012 Pro Forma
Historic 2010 Loads Unadjusted, Without Actual ST Transactions
366 0
349 1
119,116 -119,116
119,831 -119,115
10,551 1,534
30 0
15,984 3,803
139 0
26,704 5,336
53,491 -15,894
7,891 -58
46,902 -6,544
5,837 956
0 -409
32 0
545 -544
62 -62
505 -472
185 -136
115,450 -23,163
Line
No.
Jan 10 - Dec 10
Actuals
555 PURCHASED POWER
1 Modeled Short-Term Market Purchases
2 Actual Short-Term Market Purchases
3 Rocky Reach
4 Rocky Reach/Rock Island Purchase
5 Wells - Avista Share
6 Wells - Colvile Tribe's Share
7 Priest Rapids Project
8 Wanapum
9 Grant Displacement
10 Douglas Settlement
11 Lancaster Capacity Payment
12 Lancaster Variable O&M Payments
13 Lancaster BPA Reserves
14 WNP-3
15 Deer Lake-IP&L
16 Small Power
17 Stimson
18 Spokane-Upriver
19 Black Creek Index Purchase
20 Non-Monetary
21 Contract A
22 Contract B
23 Contract C
24 Contract D
25 Clearwater Paper Co-Gen Purchase
26 Ancilary Services
27 Stateline Wind Purchase
28 Total Account 555
$0
159,193
2,172
o
1,400
9,496
5,609
-1,228
5,653
334
21,475
2,689
824
13,920
6
1,079
1,964
2,055
234
90
6,789
6,745
6,658
7,556
18,720
631
3,016
277,080
557 OTHER EXPENSES
29 Broker Commission Fees
30 REC Purchases (SMUD)
31 Natural Gas Fuel Purchases
32 Total Accunt 557
501 THERMAL FUEL EXPENSE
33 Kettle Falls - Wood Fuel
34 Kettle Falls - Start-up Gas
35 Colstrip - Coal
36 Colstip - Oil
37 Total Accunt 501
547 OTHER FUEL EXPENSE
38 Coyote Springs Gas
39 Coyote Springs 2 Gas Transportation
40 Lancaster Gas
41 Lancaster Gas Transportation
42 Lancaster Gas Transportation Optimization
43 Gas Transportation for BP, NE and KFCT
44 Rathdrum Gas
45 Northeast CT Gas
46 Boulder Park Gas
47 Kettle Falls CT Gas
48 Total Accunt 547
REVISED JULY 21, 2011
Adjustment
$24,594
-159,193
-2,172
11,384
499
-9,496
785
1,228
-5,653
246
578
-223
-824
-368
o
13
402
884
-234
-90
-6,789
-6,745
-6,658
-7,556
-18,720
-631
530
-184,209
Idaho Public Utilities Commission
Office of the Secretary
RECEIVED
JUL 22 2010
Boise, Idaho
Jan 12 - Dec 12
Proforma
$24,594
o
o
11,384
1,899
o
6,394
o
o
580
22,053
2,466
o
13,552
6
1,092
2,366
2,939
o
o
o
o
o
o
o
o
3,546
92,871
366
350
o
716
12,085
30
19,787
139
32,040
37,597
7,833
40,358
6,793
-409
32
1
o
33
49
92,287
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 5, p. 1 of 2
Idaho Public Utllitltki 0üiimiSSion
Office of the SecretaryRECEIVED
JUl 22 2010
Avista Corp.
Power Supply Pro forma - Idaho Jurisdiction
System Numbers - Jan 2010. Dec 2010 Actual and Jan 2012. Dec 2012 Pro Forma
Historic 2010 Loads Unadjusted, Without Actual ST Transactions
Boise, Idaho
Line Jan 10 - Dec 10 Jan 12 - Dec 12
No.Actuals Adjustment Proforma
565 TRANSMISSION OF ELECTRICITY BY OTHERS
49 WNP-3 789 0 789
50 Sand Dunes-Warden 9 0 9
51 Black Creek Wheeling 65 -65 0
52 Wheeling for System Sales & Purchases 321 0 321
53 PTP Transmission for Colstrip & Coyote 8,428 2 8,430
54 PTP Transmission for Lancaster 4,541 -38 4,503
55 BPA Townsend-Garrison Wheeling 1,173 0 1,173
56 Avista on BPA - Borderline 1,253 0 1,253
57 Kootenai for Worley 45 0 45
58 Sagle-Northern Lights 139 0 139
59 Garrison-Burke 337 0 337
60 PGE Firm Wheeling 644 -1 643
61 Total Accunt 565 17,744 -102 17,642
536 WATER FOR POWER
62 Headwater Benefits Payments 853 0 853
549 MISC OTHER GENERATION EXPENSE
63 Rathdrum Municipal Payment 160 0 160
64 ITOTAL EXPENSE 557,822 -321,253 236,5691
447 SALES FOR RESALE
65 Modeled Short-Term Market Sales 0 27,333 27,333
66 Actual Short-Term Market Sales 219,096 -219,096 0
67 Peaker (PGE) Capacity Sale 1,749 0 1,749
68 Nichols Pumping Sale 1,693 688 2,381
69 Sovereign/Kaiser DES 80 0 80
70 Pend Oreile DES & Spinning 419 0 419
71 Northwestern Load Following 3,257 -3,257 0
72 NaturEner 551 -551 0
73 SMUD Sale - Energy and REC 27,761 -21,926 5,835
74 Ancilary Services 631 -631 0
75 Total Account 447 255,237 -217,440 37,797
456 OTHER ELECTRIC REVENUE
76 Renewable Energy Credit Sales 700 0 700
77 Gas Not Consumed Sales Revenue 111,280 -111,280 0
78 Total Account 456 111,980 -111,280 700
453 SALES OF WATER AND WATER POWER
79 Upstream Storage Revenue 282 0 282
80 ITOTAL REVENUE 367,499 -328,720 38,7791
81 ITOTAL NET EXPENSE 190,323 7,468 197,7911
REVISED JULY 21, 2011
Exhibit NO.6
Case No. AVU-E-11-01
W. Johnson, Avista
Schedule 5, p.2 of 2
Avista Corp.
Power Supply Pro forma. Washington Jurisdiction
System Numbers - Jan 2010 . Dec 2010 Actual and Jan 2012 - Dec 2012 Pro Forma
Weather Normalized 2010 Loads
Line Jan 10 - Dec 10 Jan 12 - Dec 12
No.Actuals Adjustment Pro forma
555 PURCHASED POWER
1 Modeled Short-Term Market Purchases $0 $20,836 $20,836
2 Actual ST Market Purchases - Physical 159,193 -147,924 11,269
3 Actual ST Purchases - Financial M-to-M 0 12,326 12,326
4 Rocky Reach 2,172 -2,172 0
5 Rocky ReachlRock Island Purchase 0 11,384 11,384
6 Wells - Avista Share 1,400 499 1,899
7 Wells - Colvile Tribe's Share 9,496 -9,496 0
8 Priest Rapids Project 5,609 785 6,394
9 Wanapum -1,228 1,228 0
10 Grant Displacement 5,653 -5,653 0
11 Douglas Settlement 334 246 580
12 Lancaster Capacity Payment 21,475 578 22,053
13 Lancaster Variable O&M Payments 2,689 -223 2,466
14 Lancaster BPA Reserves 824 -824 0
15 WNP-3 13,920 1,284 15,204
16 Deer Lake-IP&L 6 0 6
17 Small Power 1,079 13 1,092
18 Stimson 1,964 402 2,366
19 Spokane-Upriver 2,055 884 2,939
20 Black Creek Index Purchase 234 -234 0
21 Non-Monetary 90 -90 0
22 Contract A 6,789 -6,789 0
23 Contract B 6,745 -6,745 0
24 Contract C 6,658 -6,658 0
25 Contract D 7,556 -7,556 0
26 Clearwater Paper Co-Gen Purchase 18,720 -18,720 0
27 Ancilary Services 631 -631 0
28 Stateline Wind Purchase 3,016 -3,016 0
29 Total Account 555 277,080 -166,265 110,815
557 OTHER EXPENSES
30 Broker Commission Fees 366 0 366
31 REC Purchases (SMUD)349 1 350
32 EIA REC Purchase 0 725
33 Natural Gas Fuel Purchases 119,116 -119,116 0
34 Total Account 557 119,831 -118,390 1,441
501 THERMAL FUEL EXPENSE
35 Kettle Falls - Wood Fuel 10,551 1,534 12,085
36 Kettle Falls - Start-up Gas 30 0 30
37 Colstrip - Coal 15,984 3,803 19,787
38 Colstrip - Oil 139 0 139
39 Total Account 501 26,704 5,336 32,040
547 OTHER FUEL EXPENSE
40 Coyote Springs Gas 53,491 -15,894 37,597
41 Coyote Springs 2 Gas Transportation 7,891 -58 7,833
42 Lancaster Gas 46,902 -6,544 40,358
43 Lancaster Gas Transportation 5,837 956 6,793
44 Lancaster Gas Transportation Optimization 0 -409 -409
45 Actual Physical Gas Transactions M-to-M 0 4,800 4,800
46 Actual Financial Gas Transactions M-to-M 0 -113 -113
47 Gas Transportation for BP, NE and KFCT 32 0 32
48 Rathdrum Gas 545 -544 1
49 Northeast CT Gas 62 -62 0
50 Boulder Park Gas 505 -472 33
Exhibit NO.6
Case No. AVU~E.11'(1
w. Johnson, Avista
Schedule 6, p.1 of 2
Avista Corp.
Power Supply Pro forma. Washington Jurisdiction
System Numbers. Jan 2010 . Dec 2010 Actual and Jan 2012. Dec 2012 Pro Forma
Weather Normalized 2010 Loads
Line Jan 10. Dec 10 Jan 12 - Dec 12
No.Actuals Adjustment Pro forma
51 Kette Falls CT Gas 185 -136 49
52 Total Account 547 115,450 -18,76 96,974
565 TRANSMISSION OF ELECTRICITY BY OTHERS
53 WNP-3 789 0 789
54 Sand Dunes-Warden 9 0 9
55 Black Creek Wheeling 65 -65 0
56 Wheeling for System Sales & Purchases 321 0 321
57 PTP Transmission for Colstrip & Coyote 8,428 2 8,430
58 PTP Transmission for Lancaster 4,541 -38 4,503
59 BPA Townsend-Garrison Wheeling 1,173 0 1,173
60 Avista on BPA - Borderline 1,253 0 1,253
61 Kootenai for Worley 45 0 45
62 Sagle-Northern Lights 139 0 139
63 Garrison-Burke 337 0 337
64 PGE Firm Wheeling 644 -1 643
65 Total Account 565 17,744 -102 17,62
536 WATER FOR POWER
66 Headwater Benefits Payments 853 0 853
549 MISC OTHER GENERATION EXPENSE
67 Rathdrum Municipal Payment 160 0 160
68 ITOTAL EXPENSE 557,822 -297,897 259,9251
447 SALES FOR RESALE
69 Modeled Short-Term Market Sales 0 29,773 29,773
70 Actual ST Market Sales - Physical 219,096 -218,234 862
71 Actual ST Market Sales - Financial M-to-M 0 423 423
72 Peaker (PGE) Capacity Sale 1,749 0 1,749
73 Nichols Pumping Sale 1,693 688 2,381
74 Sovereign/Kaiser DES 80 0 80
75 Pend Oreile DES & Spinning 419 0 419
76 Northwestern Load Following 3,257 -3,257 0
77 NaturEner 551 -551 0
78 SMUD Sale - Energy and REC 27,761 -21,926 5,835
79 Ancilary Services 631 -631 0
80 Total Account 447 255,237 -213,714 41,523
456 OTHER ELECTRIC REVENUE
81 Renewable Energy Credit Sales 700 0 700
82 Gas Not Consumed Sales Revenue 111,280 -111,280 0
83 Total Account 456 111,980 -111,280 700
453 SALES OF WATER AND WATER POWER
84 Upstream Storage Revenue 282 0 282
85 ITOTAL REVENUE 367,499 -324,994 42,5051
86 ITOTAL NET EXPENSE 190,323 27,097 217,4201
Exhibit No.6
Case No. AVU.E.11.01
W. Johnson, Avista
Schedule 6, p. 2 of 2