HomeMy WebLinkAbout20090529Sterling Direct.pdfBEFORE THE
REGEl ~ì
2009 HAY 29 M111:
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MA ITER OF THE APPLICATION )
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU.E-09-1/
AUTHORITY TO INCREASE ITS RATES) AVU-G-09-1
AND CHARGES FOR ELECT~C AND )
NATURAL GAS SERVICE TO ELECTRIC )
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO. )
)
)
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
MAY 29,2009
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a Staff engineer.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science degree in Civil
11 Engineering from the University of Idaho in 1981 and a
12 Master of Science degree in Civil Engineering from the
13 University of Idaho in 1983. I worked for the Idaho
14 Department of Water Resources Energy Division from 1983 to
15 1994. In 1988, I became licensed in Idaho as a registered
16 professional Civil Engineer. I began working at the Idaho
17 Public Utilities Commission in 1994. My duties at the
18 Commission include analysis of a wide variety of electric
19 and large water utility applications.
20 Q.What is the purpose of your testimony in this
21 proceeding?
22 A.The purpose of my testimony is to review the
23 power supply modeling computations of Avista witness
24 Kalich and the power supply pro forma adjustment
25 calculations of Company witness Johnson. I propose
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 1
STAFF
1 changes to the gas price assumptions used for power supply
2 modeling, and I propose removing all term (less than 18
3 months) gas and electric transactions from the analysis
4 used to compute power supply costs for inclusion in base
5 rates.
6 Q.What model did the Company use to dispatch its
7 portfolio of resources and obligations?
8 A.Avista uses the AURORA model for determining
9 power supply costs. Staff has a license to use the AURORA
10 model (courtesy of Avista) i and possesses the ability to
11 run the model and interpret its results. The model
12 optimizes dispatch of Company-owned resources and
13 contracts in each hour of the pro forma year. The pro
14 forma period is July 1, 2009 through June 30, 2010. The
15 model simulates true system operations by evaluating
16 future resource decisions on an hourly basis. Company
17 wi tness Kalich provides detailed testimony on the AURORA
18 model used by the Company to develop short-term power
19 purchase expense, fuel expense and short-term power sales
20 revenue. His testimony includes a good description of the
21 calculations performed by AURORA.
22 Q.Did Staff use the same AURORA version and
23 database as Avista for reviewing the Company i s proposed
24 power supply costs and for determining Staff i s proposed
25 adjustments?
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 2
STAFF
1 A.Yes, Staff used exactly the same version of
2 AURORA (version 9.3.1001), including the same database
3 used by the Company (North_American_DB_200S-03).1
4 Q.What modifications did Avista make to the
5 database for this case?
6 A.Avista modified its portfolio of resources to
7 reflect actual operating characteristics, modified natural
S gas prices to match proj ected forward prices over the pro
9 forma period, modified regional resource characteristics
10 where better information is known, and replaced Northwest
11 hydro data with Northwest Power Pool data.
12 Q.Do you accept the modifications made by Avista
13 for this case?
14 A.I accept the Company's modifications to its own
15 and to other regional resources to better reflect actual
16 operating characteristics. I also accept replacement of
17 Northwest hydro data with Northwest Power Pool data.
1S However, I do not accept the natural gas prices used by
19 Avista for the pro forma period.
20 Q.What natural gas prices did Avista use for the
21 pro forma period for its AURORA analysis?
22 A.The natural gas prices used by the Company for
23 this filing are based on a three-month average from
24
25
lIn the testimony of Avista witness Kalich, he erroneously stated
that Avista used AURORA version 9.1.1003. The Company actually used
version 9.3.1001.
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 3
STAFF
1 September 1, 2008 to November 30, 2008, of monthly forward
2 prices for the pro forma period.
3 Q.What gas prices did you use for your analysis?
4 A.I used a one-month average from March 27, 2009
5 to April 27, 2009, of monthly natural gas forward prices
6 for the pro forma period. In other words, I averaged 30
7 forward prices (one each day) for each month for a 12-
8 month period. I chose to use a one-month average of
9 prices because they were the most recent available at the
10 time I performed the AURORA analysis.
11 Q.Why do you believe that the natural gas prices
12 you used are better than those used by Avista?
13 A.The prices used by Avista were reasonable at the
14 time the Company conducted its analysis and prepared its
15 case. However, forward gas prices have dropped
16 dramatically since that time. Exhibit No. 101 shows a
17 history of natural gas forward prices since January 2007.
18 Each separate line in the chart represents one month of
19 the pro forma period. In addition to gas forwards, I have
20 also shown forecasted prices from the U. S. Department of
21 Energy i s Energy Information Administration (EIA), prepared
22 since January 2008 in its monthly Short Term Energy
23 Outlook reports. Note that EIA i S forecasted prices
24 closely track gas forward prices. As indicated by the
25 chart, prices peaked last summer, but have dropped
CASE NOS. AVU-E-09-1/AVU-G-09-1OS/29/09 STERLING, R. (Di) 4
STAFF
1 steadily since then. In preparing its case, Avista used
2 an average of prices bounded by the wide pair of bold
3 vertical lines (Sept os - Nov OS) shown on the graph in
4 Exhibit No. 101. I used an average of prices bounded by
5 the narrow pair of vertical lines on the right side of the
6 graph. A numerical comparison between Avista' s prices and
7 those that I used is shown in Exhibit No . 102 for various
S trading hubs included in the AURORA modeling. Exhibit
9 No. 103 shows a comparison of monthly prices for the pro
10 forma period for specific gas-fired plants owned by
11 Avista.
12 I believe the prices I used for my analysis are
13 a much better indication of natural gas prices likely to
14 occur during the pro forma period. The pro forma period
15 begins in July 2009, just two months from the time this
16 testimony is being prepared. Prices obtained two months
17 before the start of the pro forma period are much more
1S likely to be representative than prices obtained 7-10
19 months before the pro forma period, especially if the
20 change in prices has been continuous and steady over the
21 past 10 months as shown in Exhibit No. 101.
22 Q.Please explain what a forward price is.
23 A.A forward price is a price quote to deliver gas
24 at some future date at a price agreed upon today. They
25 are not a forecast of what prices are expected to be at
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 5
STAFF
1 some future time, instead, they are the actual prices at
2 which gas can be purchased now for delivery in the future.
3 Q.Current natural gas prices are extremely low
4 compared to prices seen over the past several years. Why
5 are you proposing to use lower prices for computing
6 Avista i s power supply costs rather than the higher prices
7 of the past?
8 A.For most ratemaking purposes, adjustments are
9 made to a specific test period to normalize power supply
10 expenses for normal weather and hydroelectric generation
11 and to reflect known and measurable changes for the pro
12 forma period that rates will be in effect. Adjustments
13 are also made to reflect contract changes from the test
14 period to the pro forma period. In the case of natural
15 gas fuel, however, historic averages or test period actual
16 costs are not necessarily a good approximation of costs
17 that will likely be incurred in the future pro forma
18 period. Consequently, natural gas fuel costs are now
19 usually based on forecasts of what those costs are
20 expected to be during the time when new rates will be in
21 effect. They are not historic, nor are they known and
22 measurable in the traditional sense. The gas prices I
23 have used for my AURORA analysis are the prices I expect
24 to occur during the period in which the rates set in this
25 case will be in effect.
CASE NOS. AVU-E-09-1/AVU-G-U9-1
OS/29/09 STERLING, R. (Di) 6
STAFF
1 While it is true that natural gas prices are
2 currently at six-year lows, it is also true that the
3 prices I used in my analysis are the actual prices at
4 which gas can be purchased now for delivery in the pro
5 forma period. Obviously, Avista will not purchase now all
6 of the gas it expects to need during the pro forma period,
7 but I believe forward prices over the course of the past
S month are the best information currently available to
9 predict prices that Avista will pay for gas to be used
10 during the pro forma period.
11 Q.Besides natural gas prices, have you made any
12 additional changes to the AURORA input data used by
13 Avista?
14 A.Yes, I have. Since its last general rate case
15 in 200S, Avista has included the actual term power and
16 natural gas transactions already entered into for delivery
17 in the pro forma period. Term transactions are monthly
1S and quarterly transactions made less than 1S months prior
19 to delivery. Avista contends that term transactions
20 should be included to more accurately reflect the actual
21 power supply expense the Company will incur during the pro
22 forma period. As of November 30, 200S, Avista had entered
23 into 33 forward electric contracts and forward natural gas
24 contracts for delivery in the pro forma period. The
25 electric contracts include 15 physical purchases and 4
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 7
STAFF
1 physical sales and 14 financial (fixed-for-floating swaps)
2 purchases. The natural gas transactions include 4
3 purchases and 4 sales. As Mr. Johnson explained in his
4 testimony, Avista added the physical electric transactions
5 as resources and obligations in the AURORA model and
6 included a mark-to-model adjustment in the pro forma for
7 the financial electric and natural gas transactions. If
S the actual transactions lower power supply expense (lower
9 purchase costs or higher sales revenue) as compared to the
10 cost produced by the AURORA model, then the lower cost is
11 included in the pro forma expense. If the actual
12 transactions increase power supply expense (higher
13 purchase costs or lower sales revenue) as compared to the
14 cost produced by the AURORA model, then the higher cost is
15 included in the pro forma expense.
16 Q.What was the effect of Avista including term
17 transactions in calculating its pro forma power supply
1S expense?
19 A.Because many of the actual transactions included
20 by Avista as pro forma expenses were entered into during
21 the period of high forward prices during the middle of
22 200S, and because prices have declined substantially since
23 July 2008, the overall impact of the actual transactions
24 is an increase in the pro forma expense. Overall, the
25 actual transactions increase pro forma expense by
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) S
STAFF
1 $4,314,400 on a system basis, ($1,527,729 Idaho
2 allocation) compared to what expenses would be based
3 solely on the AURORA model output.
4 Q.Why did you exclude term transactions from your
5 analysis?
6 A.I excluded all term transactions because I do
7 not believe that they represent normal conditions upon
8 which rates should be based. They are generally made to
9 balance loads and resources in the short-term, usually in
10 response to expectations about short-term conditions like
11 water and weather conditions. Term transactions can be
12 ei ther purchases or sales, and either physical or
13 financial trades. They are the primary element of the
14 utility's hedging strategy. Term transactions made during
15 one certain time period are highly unlikely to be repeated
16 again exactly, both in terms of price, quantity, and
17 proportion of purchases versus sales. In my opinion they
18 in no way represent normal conditions and are not
19 appropriate to include as a basis for setting base rates
20 in a general rate case.
21 Q.If you remove all term transaction from the
22 power supply cost analysis in this rate case, where do you
23 propose they be considered instead?
24 A.The proper place to account for actual term
25 transaction is in the Company's Power Cost Adjustment
CASE NOS. AVU-E-09-1/AVU-G-09-1OS/29/09
STERLING, R. (Di) 9
STAFF
1 (PCA) mechanism. Term transactions create real costs that
2 the Company is obligated to payor real revenues that the
3 Company is enti tIed to receive. The PCA allows them to do
4 so on an annual basis (as opposed to a long-term basis) ,
5 subject to the 90/10 sharing percentage now in place.2
6 Q.Have term transactions ever been included in the
7 analysis to compute power supply costs for inclusion in
8 base rates?
9 A.No, they have not, not for Avista or for any
10 other electric utility within the Commission's
11 jurisdiction. Avista' s proposal to include them now would
12 be a significant departure from past practice.
13 Q.Please summarize the results of your AURORA
14 analysis using your adjusted natural gas prices and after
15 removing all term transactions.
16 A.The results of my AURORA analysis are shown in
17 Exhibit No. 104. This compares to the Company's AURORA
18 results as presented in Exhibit No. 5 of Mr. Kalich. My
19 results show an annual cost that is $20.6 million less
20 than the Company's result. To these results, resource and
21 contract revenues and expenses not accounted for in AURORA
22 (e. g., fixed costs) must be added to determine net power
23 supply expense.
24
25 2Avista has requested to change the PCA sharing percentage to 95/5 in
this general rate case.
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 10
STAFF
1 Q.Please explain how your AURORA results are used
2 to make a pro forma adjustment to power supply expense.
3 A.As explained by Avista witness Johnson, "The pro
4 forma adj ustment to power supply expense involves the
S determination of revenues and expenses based on the
6 generation and dispatch of Company resources and expected
7 wholesale market power prices as determined by the AURORA
8 model simulation for the pro forma period under normal
9 weather and hydro generation conditions. In addition,
10 adjustments are made to reflect contract changes between
11 the test period and the pro forma period." My Exhibit No.
12 ios shows total net power supply expense during the test
13 period and the pro forma period under both Avista' sand
14 Staff's proposals. For information purposes only, the
is power supply expense currently in rates, which is based on
16 a 2009 calendar year pro forma period, is also shown.
17 As shown on Exhibit No. ios, current rates are
18 based on a system power supply cost of $174,849,000.
19 Avista' s test year power supply expenses were
20 $180, 39S, 000. Avista proposes to adjust test year power
21 supply expenses upward by $27, 64S, 000 to arrive at a pro
22 forma period power supply expense of $208,040,000 on a
23 system basis ($180,39S,OOO + $27,64S,OOO = $208,040,000).
24 This represents an increase of $33,191,000 on a system
2S basis over the amount currently built into rates.
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 11
STAFF
1 Staff, on the other hand, proposes to decrease
2 test year power supply expenses by $13,000,000 to arrive
3 at a pro forma period power supply expense of $167,395,000
4 on a system basis ($180,395,000 - $13,000,000 =
5 $167,395,000). This represents a decrease of $7,454,000
6 on a system basis from the amount currently built into
7 rates.
8 The Idaho allocation of Avista i s proposed
9 adj ustment to test period expenses is an increase of
10 $9,789,095. Under Staff's proposal, the Idaho allocation
11 of its proposed adjustment to test period expenses is a
12 decrease of $4,603,300. The overall difference between
13 the Company i s proposed power supply cost and Staff's is
14 $40,645,000 on a total system basis.
15 Q.Is it unusual in a rate case to have a
16 difference of over $40 million between the utility's and
17 Staff's recommended power supply costs?
18 A.Yes, it is an unusually large difference.
19 However, as I explained previously, the change in natural
20 gas price that occurred between when the Company prepared
21 its case and when Staff prepared its case is highly
22 unusual. In addition, Avista included term transactions
23 in its case, which neither Avista nor any other Idaho
24 utility has ever done before. These two differences
25 between Avista i s and Staff's case account for the entire
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 12
STAFF
1 $40 million difference in recommended power supply costs.
2 Q.Please summarize your recommended changes in
3 power supply cost.
4 A.My recommended changes to power supply costs are
5 shown in Exhibit No. 106. I have compared my recommended
6 costs with those recommended by Avista witness Johnson. I
7 have highlighted those cost items in which my
8 recommendation differs from the Company's. with only
9 three exceptions, all of my proposed adjustments are based
10 directly on AURORA results. The three exceptions are for
11 the Priest River Proj ect, the Black Creek Index purchase,
12 and the Nichols Pumping sale. Each of these three
13 contracts has a pricing structure that is tied to electric
14 market prices. Because electric market prices are
15 projected in AURORA, I have adjusted these contract costs
16 and revenues to be consistent with prices in AURORA.
17 Exhibi t No. 107 shows the computations of these
1S adjustments using my AURORA results along with the
19 adjusted workpapers of Avista witness Johnson.
20 Q.With the exception of the changes you previously
21 discussed related to gas prices and the removal of all
22 term transactions, do you accept all of the other
23 normalizing and pro forma adjustments to the October 2007
24 through September 200S test period power supply revenues
25 and expenses proposed by Avista in this case?
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 13
STAFF
1 A.Yes, I do. All of the other adjustments
2 proposed by Avista are reasonable and in accordance with
3 adjustments accepted by this Commission in the Company's
4 prior general rate case.
5 Q.Does this conclude your direct testimony in this
6 proceeding?
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
A.Yes, it does.
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 14
STAFF
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$2
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Henry Hub Gas Forwards
for Pro Forma Months of July 2009 - June 2010
$0 """"""00 00 00 00 00 00 C"C"C"0 0 0 0 0 0 0 0 0 0 0 0 0 0 0IIIIIIIIIIIIIIICi.~C.;:C i.~C.;:C i.~
ro ro ro ::Q)0 ro ro ro ::Q)0 ro ro ro......~~I V1 Z ..~~I V1 Z ..~~I o:I I ('I I('I I ('i N i I N i ~I I0o:o:0 0 ('0 ('('0 0 N 0 ('('0 0 0 0 0 0 0 0
Settlement Date
-Ju109
-Aug 09
-Sep09
-Oct 09
-Nov09
-Dec09
-Jan 10
-Feb 10
-MarlO
-Apr 10
-May 10
-Jun 10
- EIA Jul 09
--EIAAug09
EIA Sep 09
EIA Oct 09
- EIA Nov 09
-EIADec09
-EIAJan 10
-EIAFeb10
-EIAMar10
-EIAApr10
-EIAMay10
-EIAJun 10
Exhibit No. 101
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09
Pro Forma Natural Gas Prices
($/MMBtu)
AECO
Malin
Spokane
Rockies
Stanfield
Sumas
Henry Hub
Topock
7.31
7.75
8.03
5.59
7.67
7.83
8.08
7.49
4.27
4.60
4.75
3.81
4.52
4.60
5.05
4.46
Avista's prices are based on an average of forward prices for the period 8/1/08-11/30/08.
Staff's prices are based on an average of forward prices for the period 3/27/09-4/27/09.
Exhibit No. 102
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09
Dispatch Model Prices Summary
Gas Price Period
CSII&
Rathdrum Rathdrum
Gas Gas Mid-C Gas Gas Mid-C
Month ($/dth)($/dth)($/MWh)($/dth)($/dth)($/MWh)
Jul-09 7.18 7.51 57.01 3.36 3.54 31.44
Aug-09 7.29 7.63 63.09 3.48 3.67 36.05
Sep-09 7.29 7.64 60.64 3.55 3.74 33.56
Oct-09 7.34 7.68 55.47 3.70 3.90 33.13
Nov-09 7.75 8.11 59.58 4.36 4.58 37.45
Dec-09 8.13 8.50 71.66 4.98 5.23 48.21
Jan-10 8.38 8.76 67.51 5.21 5.47 44.84
Feb-10 8.36 8.74 62.47 5.24 5.50 41.42
Mar-10 8.12 8.50 57.69 5.15 5.40 38.17
Apr-10 7.41 7.76 49.74 5.01 5.26 37.45
May-10 7.36 7.70 39.36 5.06 5.31 30.97
Jun-10 7.44 7.79 34.74 5.17 5.43 27.61
Average 7.67 8.03 56.58 4.52 4.75 36.69
CSII Coyote Springs II
NE Northeast
BP Boulder Park
KFCT Kettle Falls Combustion Turbine
Exhibit No. 103
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09
Dispatch Model Pro Forma Costs ($000)
Staff Adjusted
1 Ann Jan Feb Mar 81 .M Jun .!8!§I Oct Nov Dec
2 Hydro Projects
3 Clark Fork 0 0 0 0 0 0 0 0 0 0 0 0 0
4 Cabinet Gorge 0 0 0 0 0 0 0 0 0 0 0 0 0
5 Noxon Rapids 0 0 0 0 0 0 0 0 0 0 0 0 0
6 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
7
8 Spokane River 0 0 0 0 0 0 0 0 0 0 0 0 0
9 Litte Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
10 Long Lake 0 0 0 0 0 0 0 0 0 0 0 0 0
11 Monroe Street 0 0 0 0 0 0 0 0 0 0 0 0 0
12 Nine Mile 0 0 0 0 0 0 0 0 0 0 0 0 0
13 Post Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
14 Upper Falls 0 0 0 0 0 0 0 0 0 0 0 0 0
15 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
16
17 Mid-Columbia- Contracts
18 Priest RapidS 0 0 0 0 0 0 0 0 0 0 0 0 0
19 Rocky Reach 0 0 0 0 0 0 0 0 0 0 0 0 0
20 Wanapum 0 0 0 0 0 0 0 0 0 0 0 0 0
21 Wells 0 0 0 0 0 0 0 0 0 0 0 0 0
22 TOTAL 0 0 0 0 0 0 0 0 0 0 0 0 0
23
24 Thermals
25 Boulder Park 36 0 2 0 1 9 0 12 11 0 0 0 0
26 Colstrp 18,030 1.717 1,573 1.727 1,552 1,007 1,038 1,558 1,598 1,548 1,587 1,549 1.575
27 Coyote Springs 2 46,030 5,050 4,868 5,179 3,543 1,864 2,498 3,154 3,533 3,382 3,660 4,249 5,049
28 Kettle Falls 10,907 1,232 1,173 1,295 305 0 0 1,127 1,170 1,127 1,169 1,135 1,173
29 Kettle Falls CT 78 6 9 2 9 16 5 14 13 0 0 2 1
30 Lancaster 0 0 0 0 0 0 0 0 0 0 0 0 0
31 Northeast 43 0 0 0 0 0 0 20 23 0 0 0 0
32 Rathdrum 281 0 6 0 1 50 2 121 100 0 0 1 0
33 TOTAL 75,405 8,006 7,632 8,204 5,409 2,946 3,543 6,007 6,448 6,058 6,417 6,937 7,799
34
351 RESOURCE TOTAL 75,405 8,006 7,632 8,204 5,409 2,946 3,543 6,007 6,448 6,058 6,417 6,937 7,799
36
37 Contracts
38 Black Creek 89 0 0 0 0 0 0 0 0 0 89 0 0
39 DOPD 783 45 41 62 82 119 126 92 66 37 44 34 35
40 Market Contrct 1 7,556 642 580 642 621 642 621 642 642 621 642 621 642
41 Can Ent Return 0 0 0 0 0 0 0 0 0 0 0 0 0
42 Grant County 0 0 0 0 0 0 0 0 0 0 0 0 0
43 Clark Fork LLC 101 8 8 8 13 16 15 11 6 3 3 5 7
44 Market Contrct 2 20,192 1,715 1,549 1,715 1,660 1.715 1,660 1,715 1,715 1,660 1,715 1,660 1.715
45 Grant Displacement 5,449 397 385 384 504 522 431 516 438 434 454 473 510
46 Stimson Lumber 2,084 191 182 161 148 144 139 181 198 187 178 193 182
47 Jim Ford Creek 228 39 49 38 33 19 9 0 0 0 1 11 30
48 John Day Creek 81 4 2 2 3 11 14 12 8 6 5 8 6
49 Meyers Falls 409 36 41 50 49 51 46 24 12 14 23 30 32
50 Nichols Pumping (2.169)(225)(188)(192)(182)(156)(134)(158)(181)(163)(166)(182)(242)
51 Colstrip Start Energy 0 0 0 0 0 0 0 0 0 0 0 0 0
52 PGE CapExch 0 0 0 0 0 0 0 0 0 0 0 0 0
53 Phillps Ranch 1 0 0 0 0 0 0 0 0 0 0 0 0
54 Potlatch 0 0 0 0 0 0 0 0 0 0 0 0 0
55 Wind Contrct 2,933 258 201 302 265 256 304 245 246 206 229 236 185
56 Load Following Contrct 0 0 0 0 0 0 0 0 0 0 0 0 0
57 Sheep Creek 317 22 24 34 41 38 34 29 18 16 17 21 23
58 Upriver 2,090 271 266 265 255 250 191 66 (40)28 105 169 263
59 WNp.3 14,347 2.963 2,676 1.463 1,415 0 0 0 0 0 0 2,867 2,963
60 ST Purchases 0 0 0 0 0 0 0 0 0 0 0 0 0
61 ST Saies 0 0 0 0 0 0 0 0 0 0 0 0 0
62 SMUD (5,264)(145)(120)(152)(162)(457)(599)(682)(631)(597)(590)(564)(567)
63 Thompson River Co-Gen 0 0 0 0 0 0 0 0 0 0 0 0 0
64 TOTAL 49,225 6,220 5,696 4,781 4,746 3,170 2,856 2,693 2,497 2,452 2,749 5,583 5,781
65
66 Market Transactions
67 Market PurchaSes 35.598 5.371 3,348 2,518 1,676 471 323 1,228 4,582 3,206 4,117 3,895 4,862
68 Market Sales (34.537)(1,631)(1,751)(3,244)(4,587)(5,251)(6,494)(4,492)(776)(1,055)(1,091)(2,062)(2,103)
69 TOTAL 1,060 3,741 1,597 (726)(2,910)(4,780)(6,171)(3,265)3,806 2,151 3,026 1,833 2,760
70
711 Fuel and Market Only 76,465 11,747 9,228 7,478 2,499 (1,834)(2,628)2,743 10,254 8,209 9,443 8,770 10,558 I
72
73 Adjustments
74 Coyote Springs 2 Start Fuel 45 1 0 0 1 10 29 4 0 0 0 0 0
75 Rathdrum Start Fuel 21 0 1 0 0 3 0 9 7 0 0 0 0
76 Lancaster Start Fuel 0 0 0 0 0 0 0 0 0 0 0 0 0
77 Northeast Lost Margin 10 0 3 0 1 3 0 (0)1 0 0 1 0
78 Coyote Springs 2 Fuel Cost (1,529)(95)(91)(82)(125)(65)(84)(177)(202)(156)(105)(187)(161)
79 Lancaster Fuel Cost 0 0 0 0 0 0 0 0 0 0 0 0 0
80 Total Adjustments (1,453)(94)(86)(82)(123)(48)(55)(164)(195)(156)(105)(186)(161)
81
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Exhibit No. 104
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
05!il)09 Page 1 00
Dispatch Model Pro Forma Generation (aMW)
Staff Adjusted
1 Ann Jan Feb Mar ßi !i Jun Jul A!§!Oct Nov Dec
2 Hydro Projects
3 Clark Fork 325.9 246.0 284.9 236.2 367.2 648.5 681.2 450.7 244.4 166.9 140.8 166.3 275.8
4 Cabinet Gorge 125.3 100.4 118.0 98.2 148.7 226.3 228.3 178.1 99.9 67.9 58.0 68.2 111.3
5 Noxon Rapids 200.6 145.6 167.0 137.9 218.5 422.2 452.9 272.7 144.4 99.0 82.8 98.1 164.6
6 TOTAL (aMW)325.9 246.0 284.9 236.2 367.2 648.5 681.2 450.7 244.4 166.9 140.8 166.3 275.8
7
8 Spokane River 125.6 138.4 143.5 158.7 169.1 167.9 155.6 98.8 55.0 773 95.9 119.0 130.4
9 Little Falls 23.5 27.4 27.9 30.6 32.4 32.2 29.6 17.5 9.7 13.0 16.3 21.5 24.0
10 Long Lake 58.7 66.5 67.1 75.4 82.7 83.3 74.7 43.9 25.4 33.2 40.9 52.8 59.5
11 Monroe Street 11.7 11.9 12.6 13.4 13.6 13.6 13.2 10.6 5.9 9.4 11.2 12.2 12.6
12 Nine Mile 13.3 13.7 15.4 16.7 17.7 16.6 16.2 11.2 5.8 8.3 10.9 13.2 14.5
13 Post Falls 9.8 10.3 11.5 13.4 13.7 13.5 12.9 7.1 2.8 5.3 7.3 9.9 10.4
14 Upper Falls 8.6 8.7 9.0 9.2 8.9 8.7 9.0 8.5 5.4 8.2 9.2 9.3 9.4
15 TOTAL (aMW)125.6 138.4 143.5 158.7 169.1 167.9 155.6 98.8 55.0 77.3 95.9 119.0 130.4
16
17 Mid-Columbia- Contracts 101.7 126.1 102.3 81.5 96.5 104.0 119.3 128.2 99.8 77.4 87.5 91.7 105.6
18 Priest Rapids 19.2 30.6 25.3 19.1 17.5 12.7 18.5 14.4 13.9 12.4 13.9 24.5 28.4
19 Rocky Reach 20.3 25.8 19.7 16.1 21.8 22.4 26.5 25.1 21.5 14.0 15.7 16.6 18.8
20 Wanapum 27.5 27.4 23.3 18.8 22.9 26.7 29.9 46.8 27.7 27.1 31.0 22.2 26.1
21 Wells 34.6 42.3 33.9 27.4 34.2 42.1 44.5 41.9 36.7 23.9 26.9 28.4 32.3
22 TOTAL (aMW)101.7 126.1 102.3 81.5 96.5 104.0 119.3 128.2 99.8 77.4 87.5 91.7 105.6
23
24 TOTAL 553.2 510.5 530.7 476.3 632.8 920.4 956.1 677.8 399.1 321.6 324.2 377.0 511.
25
26 Thermals
27 Boulder Park 0.1 0.0 0.1 0.0 0.0 0.2 0.0 0.5 0.4 0.0 0.0 0.0 0.0
28 Colstrip 189.7 203.4 206.3 204.6 189.9 119.3 127.1 200.8 205.9 206.2 204.4 206.2 202.9
29 Coyote Springs 2 169.3 185.0 197.6 194.1 140.7 71.0 96.0 180.5 195.6 190.2 193.8 194.1 194.1
30 Kettle Falls 34.4 40.8 43.1 43.0 10.5 0.0 0.0 44.4 46.2 45.9 46.1 46.3 46.3
31 Kettle Falls CT 0.2 0.2 0.3 0.1 0.3 0.5 0.1 0.6 0.5 0.0 0.0 0.1 0.0
32 Lancaster 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
33 Northeast 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.6 0.0 0.0 0.0 0.0
34 Rathdrum 0.8 0.0 0.2 0.0 0.0 1.2 0.0 4.3 3.3 0.0 0.0 0.0 0.0
35 TOTAL 394.6 429.4 447.5 441.8 341.4 192.1 223.3 431.7 452.6 442.3 444.3 446.7 443.4
36
37 I RESOURCE TOTAL 947.8 939.9 978.2 918.2 974.1 1,112.6 1,179.4 1,109.5 851.7 763.8 768.5 823.6 955.2
38
39 Contracts
40 Black Creek 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.4 0.0 0.0
41 DOPD 3.7 2.4 2.4 3.3 4.8 6.7 7.3 5.3 3.8 2.0 2.4 2.0 1.8
42 Market Contract 1 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0
43 Can Ent Return (3.9)(3.5)(3.6)(3.7)(3.6)(3.5)(3.6)(4.2)(4.0)(4.1)(4.2)(4.0)(4.2)
44 Grant County 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
45 Clark Fork LLC 0.1 0.1 0.1 0.1 0.2 0.3 0.3 0.2 0.1 0.1 0.0 0.1 0.1
46 Market Contract 2 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0
47 Grant Displacement 22.2 17.4 17.6 17.7 26.2 31.8 31.6 27.6 19.7 19.0 18.7 19.3 19.2
48 Stimson Lumber 4.2 4.2 4.4 4.5 4.3 4.0 4.0 4.0 4.4 4.3 4.0 4.5 4.0
49 Jim Ford Creek 0.4 0.6 0.8 1.2 1.0 0.6 0.3 0.0 0.0 0.0 0.0 0.2 0.4
50 John Day Creek 0.2 0.1 0.0 0.1 0.1 0.4 0.6 0.4 0.3 0.2 0.2 0.1 0.1
51 Meyers Falls 1.0 1.0 1.2 1.4 1.4 1.4 1.3 0.7 0.3 0.4 0.6 0.9 0.9
52 Nichols Pumping (7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)(7.8)
53 Colstrip Start Energy 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
54 PGE CapExch 0.1 2.4 0.0 (2.8)(0.4)1.2 0.0 (0.8)0.8 (0.4)0.4 1.7 (0.8)
55 Philips Ranch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
56 Potlatch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
57 Wind Contract 8.4 8.6 7.4 10.0 9.1 8.5 10.4 8.3 8.3 7.2 7.8 8.3 6.3
58 Load Following Contracts 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
59 Sheep Creek 0.8 0.4 0.6 1.1 1.5 1.6 1.6 1.0 0.3 0.2 0.3 0.5 0.4
60 Upriver 6.1 8.3 9.0 10.4 10.3 9.8 7.8 2.0 (1.2)0.9 3.2 5.4 8.0
61 WNP-3 43.8 106.6 106.6 52.6 52.6 0.0 0.0 0.0 0.0 0.0 0.0 106.6 106.6
62 ST Purchases 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
63 ST Sales 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
64 SMUD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
65 Thompson River Co-Gen 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
66 TOTAL 179.8 240.8 238.9 188.1 199.8 155.2 153.7 136.8 125.1 122.0 130.1 237.6 235.3
67
68 Market Transactions
69 Market Purchases 92.0 142.5 105.9 77.9 50.3 13.0 11.9 39.3 138.6 116.5 154.6 129.8 123.1
70 Market Sales (135.7)(55.5)(70.3)(126.2)(191.6)(287.3)(378.4)(227.3)(35.6)(53.8)(48.6)(86.7)(66.3)
71 TOTAL (43.7)87.0 35.6 (48.3)(141.2)(274.3)(366.5)(188.0)103.0 62.6 106.1 43.1 56.8
72
73 System Load 1,083.9 1,267.7 1,252.7 1,057.9 1,032.7 993.4 966.6 1,058.3 1,079.8 948.4 1,004.7 1,104.4 1,247.3
Exhibit NO.1 04
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09 Page 2 of3
Dispatch Model Generation (GWh)
Staff Adjusted
1 Ann Jan Feb Mar &r ~Jun Jul ß!§i Oct Nov DèC
2 Hydro Projects
3 Clark Fork 2,854.5 183.0 191.5 175.7 264.4 482.5 490.5 335.4 181.8 120.1 104.8 119.7 205.2
4 Cabinet Gorge 1,097.6 74.7 79.3 73.1 107.1 168.4 164.4 132.5 74.4 48.9 43.2 49.1 82.8
5 Noxon Rapids 1,756.9 108.3 112.2 102.6 157.3 314.1 326.1 202.9 107.4 71.2 61.6 70.6 122.4
6 TOTAL 2,854.5 183.0 191.5 175.7 264.4 482.5 490.5 335.4 181.8 120.1 104.8 119.7 205.2
7
8 Spokane River 1,100.3 103.0 96.4 118.1 121.7 125.0 112.0 73.5 40.9 55.7 71.3 85.7 97.0
9 Litte Falls 205.4 20.4 18.7 22.7 23.3 24.0 21.3 13.0 7.2 9.3 12.1 15.4 17.9
10 Long Lake 514.2 49.4 45.1 56.1 59.6 62.0 53.8 32.7 18.9 23.9 30.4 38.0 44,3
11 Monroe Street 102.3 8.8 8.5 10.0 9.8 10.1 9.5 7.9 4.4 6.7 8.3 8.8 9.4
12 Nine Mile 116.8 10.2 10.4 12.4 12.8 12.4 11.7 8.3 4.3 6.0 8,1 9.5 10.8
13 Post Falls 86.0 7.7 7.7 10.0 9.9 10.0 9.3 5.3 2.0 3.8 5.4 7,2 7.7
14 Upper Falls 75,5 6.5 6.1 6.9 6.4 6.5 6.5 6.3 4.0 5.9 6.9 6.7 7.0
15 TOTAL 1,100.3 103.0 96.4 118.1 121.7 125.0 112.0 73.5 40.9 55.7 71.3 85.7 97.0
16
17 Mid-Columbia- Contracts 890.9 93.8 68.7 60.6 69.5 77.4 85.9 95.4 74.3 55.7 65.1 66.0 78.5
18 Priest Rapids 168.6 22.7 17.0 14.2 12.6 9.5 13.3 10.7 10.4 8.9 10.3 17.7 21.1
19 Rocky Reach 178.1 19.2 13.3 12.0 15.7 16.7 19.1 18.7 16.0 10.1 11.6 11.9 14.0
20 Wanapum 241.3 20.4 15.7 14.0 16.5 19.9 21.5 34.8 20.6 19.5 23.1 16.0 19.4
21 Wells 303.0 31.5 22.8 20.4 24.6 31.3 32.0 31.2 27.3 17.2 20.0 20.5 24.0
22 TOTAL 890.9 93.8 68.7 60.6 69.5 77.4 85.9 95.4 74.3 55.7 65.1 66.0 78.5
23
24 TOTAL 4,845.8 379.8 356.6 354.4 455.6 684.8 688.4 504.3 297.0 231.5 241.2 271.4 380.8
25
26 Thermals
27 Boulder Park 1.0 0.0 0.0 0.0 0.0 0.2 0.0 0.4 0.3 0.0 0.0 0.0 0.0
28 Colstrip 1,661.8 151.4 138.6 152.2 136.8 88.7 91.5 149.4 153.2 148.4 152.1 148.5 151.0
29 Coyote Springs 2 1,483.2 137,6 132.8 144.4 101.3 52.8 69.1 134.3 145.5 136.9 144.2 139.8 144.4
30 Kettle Falls 301.3 30.3 29.0 32.0 7.5 0.0 0.0 33.0 34.3 33.1 34.3 33.3 34.4
31 Kettle Falls CT 1.9 0.1 0.2 0.1 0.2 0.4 0.1 0.4 0.4 0.0 0.0 0.1 0.0
32 Lancaster 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
33 Northeast 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.5 0.0 0.0 0.0 0.0
34 Rathdrum 6.7 0.0 0.1 0.0 0.0 0.9 0.0 3.2 2.5 0.0 0.0 0.0 0.0
35 TOTAL 3,456.8 319.5 300.7 328.7 245.8 142.9 160.8 321.2 336.7 318.4 330.6 321.6 329.9
36
371 RESOURCE TOTAL 8,302.6 699.3 657.4 683.1 701.4 827.7 849.2 825.5 633.7 549.9 571.8 593.0 710.6 I
38
39 Contracts
40 Black Creek 3.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.3 0.0 0.0
41 DOPD 32.3 1.8 1.6 2.4 3.5 5.0 5.3 3.9 2.8 1.5 1.8 1.4 1.4
42 Market Contract 1 219.0 18.6 16.8 18.6 18.0 18.6 18.0 18.6 18.6 18.0 18.6 18.0 18.6
43 Can Ent Return (33.8)(2.6)(2.4)(2.7)(2.6)(2.6)(2.6)(3.1)(3.0)(3.0)(3.1)(2.9)(3.1)
44 Grant County 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
45 Clark Fork LLC 1.2 0.1 0.1 0.1 0.2 0.2 0.2 0.1 0.1 0.0 0.0 0.0 0.1
46 Market Contract 2 657.0 55.8 50.4 55.8 54.0 55.8 54.0 55.8 55.8 54.0 55.8 54.0 55.8
47 Grant Displacement 194.2 13.0 11.8 13.1 18.8 23.7 22.8 20.5 14.6 13.7 13.9 13.9 14.3
48 Stimson Lumber 37.0 3.1 2.9 3.4 3.1 3.0 2.9 3.0 3.3 3.1 3.0 32 3.0
49 Jim Ford Creek 3.7 0.4 0.5 0.9 0.8 0.4 0.2 0.0 0.0 0.0 0.0 0.1 0.3
50 John Day Creek 1.9 0.1 0.0 0.1 0.1 0.3 0.4 0.3 0.2 0.1 0.1 0.1 0.1
51 Meyers Falls 8.4 0.7 0.8 1.0 1.0 1.0 0.9 0.5 0.2 0.3 0.5 0.6 0.7
52 Nichols Pumping (67.9)(5.8)(5.2)(5.8)(5.6)(5.8)(5.6)(5.8)(5.8)(5.6)(5.8)(5.6)(5.8)
53 Colstrip Start Energy 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
54 PGE CapExch 0.9 1.8 0.0 (2.1)(0.3)0.9 0.0 (0.6)0.6 (0.3)0.3 1.2 (0.6)
55 Phillips Ranch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
56 Potlatch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
57 Wind Contract 73.2 6.4 5.0 7.5 6.6 6.3 7.5 6.2 6.2 5.2 5.8 6.0 4.7
58 Load Following Contracts 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
59 Sheep Creek 6.9 0.3 0.4 0.8 1.1 1.2 1.1 0.7 0.2 0.2 0.2 0.3 0.3
60 Upriver 53.8 6.2 6.1 7.8 7.4 7.3 5.6 1.5 (0.9)0.6 2.4 3.9 6.0
61 WNP-3 384.0 79.3 71.6 39.1 37.9 0.0 0.0 0.0 0.0 0.0 0.0 76.7 79.3
62 ST Purchases 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
63 ST Sales 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
64 SMUD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
65 Thompson River Co-Gen 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
66 TOTAL 1,575.1 179.1 160.5 139.9 143.9 115.4 110.7 101.8 93.0 87.8 96.8 171.1 175.0
67
68 Market Transactions
69 Market Purchases 806.0 106.0 71.2 58.0 36.2 9.7 8.6 29.2 103.1 83.9 115.0 93.5 91.6
70 Market Sales (1.188.8)(41.3)(47.3)(93.9)(137.9)(213.8)(272.5)(169.1)(26.5)(38.8)(36.1)(62.4)(49.3)
71 TOTAL (382.8)64.7 23.9 (36.0)(101.7)(204.1)(263.9)(139.9)76.6 45.1 78.9 31.1 42.3
72
73 SYSTEM LOAD 9,494.9 943.1 841.8 787.1 743.5 739.1 696.0 787.4 803.4 682.9 747.5 795.1 928.0
Exhibit No. 104
Case No. A VU-E-9-09-1/
AVU-G-09-1
R. Sterling, Staff
OS/29/09 Page 3 of 3
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Avista Corp.
Staff Adjusted Power Supply Pro forma. Idaho Jurisdiction
System Numbers. Oct 2007 . Sep 2008 Actual and Jul 09 . Jun 10 Pro forma
No Short.Term Transactions & 3/27/09.4/27/09 Gas Prices
Line
No.
1
2
3
4
5
6
7
8
9 Douglas Settlement 497 122 619 122 619
10 WNP-3 12.553 2.248 14,801 2,248 14,801
11 Deer Lake-IP&L 7 0 7 0 7
12 Small Power 1,125 29 1,154 29 1,154
13 Stimson 1,964 138 2,102 138 2,102
14 Spokane-Upriver 1,790 300 2,090 300 2,090
15 Douglas Exchange Capacity 1,648 .1,648 0 -1,648 0
16 1,699
17 114
18 .242
19 Contract A 6,808 -19 6,789 -19 6,789
20 Contract B 6,764 -19 6,745 -19 6.745
21 Contract C 6,675 -17 6,658 -17 6,658
22 Contract D 7,576 .20 7,556 .20 7,556
23 CS2 Exchange 387 -387 0 -387 0
24 Northwestern Deviation Energy 1,867 -1,867 0 -1,867 0
25 BPA NT Deviation Energy 3,236 -3,236 0 -3,236 0
26 Potlatch co-Gen Purchase 18,439 -18,439 0 -18,439 0
27 Spinning Reserve Purchase 1,500 0 1,500 0 1,00
28 Ancillary Services 670 -670 0 .670 0
29 Slateline Wind Purchase .159 -159
30 '¡IL,
557 OTHER EXPENSES
31 Broker Commission Fees 104 0 104 0 104
32 REC Purchases 364 -14 350 -14 350
33 Bad Debt Reserve 2,728 -2,728 0 -2,728 0
34 Natural Gas Fuel Purchases 39,075 -39.075 0 -39,075 0
35 T olal Account 557 42.271 -41,817 454 -41.817 454
36
37
38
39
40 ~""-'iiiiiiiiliiili1;r;x;vNn'.II_nli w;n
41
42
43
44
45
46
47
48 T olal Account 547 108,398 -31,316 77,082 -55,058 53,340
565 TRANSMISSION OF ELECTRICITY BY OTHERS
49 WNP-3 789 0 789 0 789
50 Sand Dunes-Warden 20 0 20 0 20
51 Black Creek Wheeling 18 2 20 2 20
52 Wheeling for System Sales & Purchases 845 0 845 0 845
53 PTP for Colstrip & Coyote 8,427 3 8,430 3 8,430
54 BPA Townsend-Garrison Wheeling 1.173 0 1,173 0 1,173
55 Avisla on BPA. Borderline 1,483 -5 1,478 .5 1,478
56 Kootenai for Worley 39 6 45 6 45
57 Sagle-Northern Lights 136 -2 134 -2 134
58 Garrison-Burke 592 0 592 0 592
Exhibit No. 106
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09 Page 1 of 2
Avista Corp.
Staff Adjusted Power Supply Pro forma. Idaho Jurisdiction
System Numbers. Oct 2007 . Sep 2008 Actual and Jul 09. Jun 10 Pro forma
No Short-Term Transactions & 3/27/09 . 4127109 Gas Prices
Line Oct 07 - Sep 08
No.Actuals
59 PGE Firm Wheelin 643
60 T olal Account 565 14.165
536 WATER FOR POWER
61 Headwater Benefits Payments 654 655 655
549 MISC OTHER GENERATION EXPENSE
62 Rathdrum Municipal Payment 175 -15 160 -15 160
63
64
65
66
67
68
69 Pend DES & Spinning
70 Northwestern Load Following
71 SMUDSale
72 Ancilary Services
73 Spokane Energy Service Fee - Peaker Sale
74 BPA NT Deviation Ener
75
456 OTHER ELECTRIC REVENUE
76 Renewable Energy Credit Sales 13 -13 0 -13 0
77 Gas Not Consumed Sales Revenue 41,799 -41,799 0 -41,799 0
78 Tolal Account 456 41,812 -41,812 0 -41,812 0
453 SALES OF WATER AND WATER POWER
79 Upstream Storage Revenue 303 -1 302 -1 302
454 MISC RENTS
80 Colstrip Rents 57 -33 24 -33 24
81
82
83 Potlatch Purchase Assigned to Idaho 18,439 18,439
84
Exhibit No. 106
Case No. A VU-E-9-09-l/
AVU-G-09-1
R. Sterling, Staff
OS/29/09 Page 2 of 2
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 29TH DAY OF MAY 2009,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE
NOS. AVU-E-09-1 & AVU-G-09-1, BY ELECTRONIC MAIL TO THE FOLLOWING:
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220
E-MAIL: david.meyer(iavistacorp.com
DEAN J MILLER
McDEVITT & MILLER LLP
PO BOX 2564
BOISE ID 83701
E-MAIL: joe(imcdevitt-miler.com
CONLEY E WARD
MICHAEL C; CREAMER
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
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mcc(igivenspursley.com
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ID CONSERVATION LEAGUE
710 N SIXTH STREET
POBOX 844
BOISE ID 83701
E-MAIL: bbridge(iwildidaho.org
CARRE TRACY
1265 S MAIN ST, #305
SEATTLE WA 98144
E-MAIL: carrie(inwfco.org
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VICE PRESIDENT - STATE & FED. REG.
A VISTA UTILITIES
PO BOX 3727
SPOKANE WA 99220
E-MAIL: kelly.norwood(iavistacorp.com
SCOTT ATKINSON
PRESIDENT
IDAHO FOREST GROUP LLC
171 HIGHWAY 95 N
GRANGEVILLE ID 83530
E-MAIL: scotta(iidahoforestgroup.com
DENNIS E PESEAU, Ph.D.
UTILITY RESOURCES INC
SUITE 250
1500 LIBERTY STREET SE
SALEM OR 97302
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ID COMMUNITY ACTION NETWORK
3450 HILL RD
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ATTORNEY AT LAW
2019 N 17TH ST
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Jdw.~SEOOTARY
CERTIFICATE OF SERVICE