20081024Sterling Direct.pdf

BEFORE THE RECEIVED
2008 OCT 24 PM 3: 27
IDAHO PUBLIC UTILITIES COMMISSIONIDAHO PUBLIC
UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO.IPC-E-08-10
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
TO ELECTRIC CUSTOMERS IN THE STATE)OF IDAHO. )
)
)
)
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
OCTOBER 24, 2008
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
11 Civil Engineering from the University of Idaho in 1981
12 and a Master of Science degree in Civil Engineering from
13 the University of Idaho in 1983. I worked for the Idaho
14 Department of Water Resources from 1983 to 1994. In
15 1988, I received my Idaho license as a registered
16 professional Civil Engineer. I began working at the
17 Idaho Public Utilities Commission in 1994. During my
18 employment at the IPUC, I have attended the annual
19 regulatory studies program sponsored by the National
20 Association of Regulatory Commissioners (NARUC) at
21 Michigan State University, as well as numerous other
22 seminars and short courses.
23 Q.What is the purpose of your testimony in this
24 proceeding?
25 A.The purpose of my testimony is to discuss the
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 1
STAFF
1 net power supply cost recommendation of Idaho Power, to
2 explain why I believe it is too high, and to make an
3 al ternati ve recommendation that I believe fairly and
4 reasonably represents the Company's normalized net power
5 supply cost for the 2008 test year.
6 Q.Please briefly summarize your proposed net
7 power supply cost adjustments.
8 A.I am proposing a net power supply cost of $77.6
9 million, which is approximately $11.2 million less than
10 Idaho Power's proposed net power supply cost. My net
11 power supply cost recommendation is based on the use of a
12 natural gas price of $7.75 per MMBtu in the AURORA model.
13 Q.Have you reviewed the work done by Idaho Power
14 to develop a net power supply cost recommendation for
15 this case?
16 A.Yes, I have reviewed the Company's testimony
17 and recommendations related to net power supply cost, and
18 have also reviewed all of the supporting exhibits and
19 workpapers prepared by the Company as well as all of the
20 power supply cost simulations made using AURORA.
21 Q.What is Idaho Power recommending as the net
22 power supply cost to be included in its revenue
23 requirement?
24 A.Idaho Power is recommending a net power supply
25 cost of $88.4 million in addition to PURPA costs of $63.3
CASE NO. IPC-E-08-10
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STERLING, R (Di) 2
STAFF
1 million, for a total power supply cost of $151.7 million.
2 Q.Do you agree with the net power supply cost
3 recommendations contained in the testimony of Idaho Power
4 witness Greg Said?
5 A.NO, I do not. I believe that the net power
6 supply cost recommendations of the Company are too high.
7 I do accept the Company's estimate of PURPA costs,
8 however.
9 Q.Why do you believe that the net power supply
10 cost recommendations of the Company are too high?
11 A.I believe that Idaho Power's net power supply
12 cost recommendations are too high because of inaccurate
13 assumptions made by the Company regarding natural gas
14 fuel prices used in AURORA, the model used for computing
15 net power supply costs.
16 Q.Are natural gas price assumptions crucial in
17 the determination of net power supply costs, even though
18 Idaho Power has a relatively small amount of natural gas
19 fired generation on its system?
20 A.Yes, Idaho Power's net power supply costs are
21 not only a function of the costs of fueling and operating
22 its own generating resources, but are also a function of
23 the costs of its off-system purchases and its secondary
24 sales. During the maj ori ty of the year, gas - fired
25 generation is the marginal resource in the region;
CASE NO. IPC-E-08-10
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STERLING, R (Di) 3
STAFF
1 consequently, it tends to set the market price for all
2 market purchases and sales. Obviously, higher gas prices
3 drive electric market prices up and lower gas prices
4 dri ve market prices down.
5 Q.How do high gas prices affect Idaho Power and
6 its ratepayers?
7 A.High gas prices actually benefit Idaho Power
8 and its ratepayers in most years. Because Idaho Power is
9 a net energy seller over the course of the year, high gas
10 prices, which in turn cause high electric market prices,
11 allow the Company to sell its surplus low-cost hydro and
12 coal generation at those higher market prices,
13 substantially reducing its net power supply costs.
14 Q.What assumptions about gas price did Idaho
15 Power make for purposes of its AURORA power supply cost
16 simulations?
17 A.Idaho Power's derivation of the gas prices it
18 used in AURORA is shown on Staff Exhibit No. 101. Idaho
19 Power obtained 10-year gas price forecasts from three
20 different sources-PIRA, DOE-EIA, and Global Insight-and
21 five-year forecasts from two sources-NYMEX and NGX.
22 Idaho Power computed a weighted average price using each
23 of the ten years from 2008-2017, then made other
24 adj ustments to prepare the prices for input into the
25 AURORA model. Idaho Power generated upper and lower
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 4
STAFF
1 limits for gas prices to be used in AURORA by applying
2 the standard deviation in actual prices at Sumas from
3 2001 through 2007. The result of this exercise was an
4 average gas price of $7. 74/MMBtu with upper and lower
5 limits of $9. 75/MMBtu and $5. 73/MMBtu.
6 Q.How was this range of assumed gas prices used
7 by Idaho Power in the AURORA model?
8 A.Idaho Power assumed that high gas prices are
9 associated with low water conditions and that low gas
10 prices occur when water conditions are high. For the 80
11 water years of record used in the power supply analysis,
12 the Company created an algorithm that assigned the
13 highest gas price ($9.75) to the lowest water year on
14 record and assigned the lowest gas price ($5.73) to the
15 highest water year on record. Gas prices were then
16 assigned to all of the years in between based on their
17 relative water condition.
18 Q.What is wrong with this approach in your
19 opinion?
20 A.I believe that Idaho Power's approach is wrong
21 for two reasons. First, I do not believe it is
22 appropriate to use 10, or even five years of gas price
23 forecasts when we are really only trying to establish
24 power supply costs between now and when Idaho Power files
25 its next general rate case. Idaho Power's last general
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 5
STAFF
1 rate case was filed only about one year before this one,
2 and the Company has indicated that it expects to make
3 more frequent rate case filings in the future.
4 Informally, Idaho Power has told Staff that its future
5 rate case filings could be made as often as annually.
6 Therefore, because we are likely only setting rates to be
7 effective for approximately the next year, it seems
8 logical that we should only be using gas price forecasts
9 representative of the same time frame. Gas price
10 forecasts five or ten years into the future have no
11 relevance whatsoever when we are only setting rates one
12 year into the future.
13 Q.What is your other primary obj ection to the
14 method used by Idaho Power?
15 A.My second objection relates to Idaho Power's
16 assumption that gas prices are directly related to hydro
17 condi tions. I do not believe that gas prices are
18 correlated with hydro conditions on Idaho Power's system,
19 or for that matter, even with Northwest hydro conditions.
20 I believe that natural gas prices are influenced by
21 numerous factors, most of which have nothing to do with
22 water conditions in the Northwest. Because pipelines
23 allow natural gas to be transported throughout North
24 America, gas prices now tend to rise or fall in unison.
25 Prices in the Northwest can be affected by a prolonged
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 6
STAFF
1 cold snap in the Midwest, for example, by tropical storms
2 and hurricanes in the Gulf, or by unusual demand in
3 California. Underground gas storage levels, drilling
4 activity, market speculation and economic conditions also
5 significantly affect prices. Gas demand, wherever it
6 occurs in the country, can affect prices nationally.
7 Regional supply interruptions seem to be one of the few
8 factors that can still significantly affect regional gas
9 prices.
10 Q.Have you examined any data or performed any
11 analysis to support your conclusion that gas prices and
12 Northwest hydro conditions are not related?
13 A.Yes, I have. I performed regression analysis
14 using historical Henry Hub and Sumas gas prices as
15 reported by the Intercontinental Exchange and historical
16 water conditions represented by hydro shaping factors
1 7 used in AURORA. The hydro shaping factors used in AURORA
18 reflect monthly and annual scaling factors used to
19 accurately replicate historic hydro conditions in areas
20 throughout the Northwest. The source for the hydro data
21 used in AURORA is the Northwest Power Pool. Staff
22 Exhibit No. 102 shows the results of the correlation
23 analysis on a monthly basis for hydro conditions from
24 2001 through 2006 at Hells Canyon, Southern Idaho, run-
25 of-river plants on Idaho Power's system, the Oregon-
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 7
STAFF
1 Washington-Northern Idaho area, British Columbia and
2 Montana. As shown by the exhibit, there appears to be no
3 correlation whatsoever between Northwest hydro conditions
4 and Sumas gas prices on a monthly basis. The results are
5 similar for Henry Hub gas prices.
6 Q.Are you saying that neither gas prices nor
7 hydro conditions affect power supply costs?
8 A.No, I am not suggesting that gas prices and
9 hydro conditions do not affect power supply costs.
10 Clearly, both greatly affect power supply costs. They do
11 so independently, however. What I am saying is that gas
12 prices are unrelated to Northwest hydro conditions.
13 Q.What gas prices did you consider using for the
14 power supply analysis in AURORA?
15 A.I believe it is reasonable to use gas prices
16 representative of 2009, the year when the rates
17 determined in this case will be effective. To obtain
18 prices representative of 2009, I considered several
19 forecasts available to Staff. First, I considered the
20 August 2008 forecast prepared by Global Insight because
21 it was more recent than the March 2008 Global Insight
22 forecast used by Idaho Power in developing the Company; s
23 gas price forecast. I also considered the Department of
24 Energy/Energy Information Administration's (EIA) Annual
25 Energy Outlook forecast that was released in June 2008.
CASE NO. IPC-E-08-10
10/24/08 STERLING, R (Di) 8
STAFF
1 In addition, I considered EIA's Short Term Energy Outlook
2 forecasts released monthly in 2008 from January through
3 October. In addition to these forecasts, I considered
4 the most recent 12 months of NYMEX spot market prices and
5 NYMEX forwards prices for 2009. I also reviewed recent
6 forecasts made by gas industry experts as reported
7 quarterly in the publication Natural Gas Week.
8 Q.Do you consider these sources to be superior to
9 those used by Idaho Power?
10 A.All of the forecasts I considered were more
11 recent than the forecast information used by Idaho Power.
12 I had an advantage in my analysis because all of the gas
13 price information I considered was simply not yet
14 available at the time the Company prepared its case.
15 Q.Were gas price forecasts for 2009 reasonably
16 consistent throughout the past year?
17 A.No, gas price forecasts for 2009 and 2009 gas
18 forwards prices were extremely variable during the past
19 year. Exhibit No. 103 shows how dramatically 2009 gas
20 forwards prices varied throughout 2008.
21 Q.Why did 2009 gas forwards prices vary so much
22 during the year?
23 A.There were several extremely unusual events in
24 2008 that had major impacts on 2009 forwards prices.
25 First, oil prices began climbing in the first half of the
CASE NO. IPC-E-08-10
10/24/08
STERLING, R (Di) 9
STAFF
1 year, eventually reaching record levels. Natural gas
2 prices followed a similar trend until July 1, when winter
3 2009 forwards prices peaked at over $14 per MMBtu. In
4 less than a month and a half, prices plummeted to the $8
5 per MMBtu range. Two maj or hurricanes in the Gulf during
6 September also affected prices. Finally, the recent
7 economic crisis and Wall Street bailout plan have lowered
8 forecast prices even further due to expectations of a
9 global economic downturn. These highly unusual events
10 have made it extremely difficult to forecast prices even
11 one year into the future. Selecting gas prices in recent
12 months for use in power supply modeling has truly been a
13 case of chasing a moving target.
14 Q.What gas prices do you believe should be used
15 for power supply modeling in AURORA?
16 A.My recommendation is to use a gas price of
17 $7.75 per MMBtu for all 80 water years based on the
18 natural gas price forecast contained in the Energy
19 Information Administration's October 2008 Short Term
20 Energy Outlook. That is the forecasted price for 2009
21 (in year 2008 dollars).
22 Q.Why did you decide to rely on just one recent
23 forecast rather than using a blend of forecasts like
24 Idaho Power or using an average of several forecasts
25 prepared at different times during the year?
CASE NO. IPC-E-08-1010/24/08
STERLING, R (Di) 10
STAFF
1 A.Because of the extreme events during the past
2 year, gas forecasts prepared early in the year could not
3 take into account the effect of recent events. The
4 extreme rise and fall in oil and natural gas prices and
5 the economic credit crisis, in particular, are two events
6 whose effects can only be reflected in very recent price
7 forecasts. I chose to use the freshest forecast
S available at the time I prepared my testimony. Because
9 multiple recent forecasts were not available, blending
10 forecasts was not an option. Furthermore, blending
11 forecasts prepared at different points in time when
12 economic conditions are extremely different would be
13 inadvisable.
14 Q.Why do you propose to use the same gas price
15 for all SO water years?
16 A.I believe it is appropriate to use the same gas
17 price for all SO water years because I have found no
lS evidence to suggest that gas prices vary based on water
19 conditions. The purpose of using so different water
20 years is to simulate normal water conditions during the
21 test year. Normal gas prices for the test year can be
22 simulated with only a single estimate because gas prices
23 are unrelated to water conditions.
24 Q.What net power supply cost do you calculate
25 using AURORA with the $7.75 per MMBtu gas price you
CASE NO. IPC-E-OS-10
10/24/0S
STERLING, R (Di) 11
STAFF
1 believe should be used?
2 A.Using a gas price of $7.75 per MMBtu for all
3 water years, AURORA calculated a net power supply cost of
4 $77.6 million. Net power supply costs are comprised of
5 four accounts: 447 System Opportunity Sales; 501 Fuel
6 (Coal); 547 Fuel (Gas); and 555.1 Purchased Power.
7 Staff's proposed totals for each account are shown on
S Exhibit No. 104, and are also compared to Idaho Power's
9 proposed amounts. Staff's most significant adjustment is
10 a $6.4 million increase in account 447 System Opportunity
11 Sales.
12 Q.The $ 7 . 75 per MMBtu gas price that you used for
13 AURORA modeling is only one cent higher than the price
14 Idaho Power used for its modeling. Why did such a small
15 difference in gas price cause your power supply costs to
16 be $11.2 million lower than Idaho Power IS?
17 A.The extremely small difference in annual gas
lS price assumptions is not a significant reason for the
19 substantial difference in net power supply costs. The
20 primary reason why my results differ so much from Idaho
21 Power's is because I did not assume a correlation between
22 water conditions and gas prices, as I explained
23 previously. Idaho Power assumes that the highest gas
24 prices (thus the highest electric prices) will occur in
25 the lowest water years. In those low-water/high-price
CASE NO. IPC-E- OS - 1010/24/0S STERLING, R (Di) 12
STAFF
1 years, Idaho Power will have little or no surplus power
2 to sell, and instead will likely need to buy power at
3 those high prices. Idaho Power assumes the opposite
4 situation in high water years, i.e., that in years when
5 it has a lot of surplus power to sell, gas and electric
6 prices will be low. Compared to my assumptions, the
7 Company i s assumptions produce lower revenues in high-
S water years and higher costs in low-water years.
9 Q.Did you make any other changes to the AURORA
10 input assumptions that are different from those used by
11 Idaho Power?
12 A.Yes, I made two changes that had a
13 comparatively minor effect. First, I decreased the gas
14 price basis differential between Henry Hub and Danskin.
15 Idaho Power used a basis differential of $0.27 per MMBtu.
16 I performed analysis of Henry Hub to Sumas basis
17 differentials using NYMEX forwards prices, then accounted
lS for delivery costs from Sumas to Danskin, and determined
19 that a basis differential of $0.13 is more appropriate.
20 Second, I modified the "monthly shape factors"
21 for the gas prices used in AURORA. Monthly shape factors
22 are basically multipliers that are used to convert an
23 annual gas price (in this case $7.75 per MMBtu) to a
24 series of twelve different monthly prices. My
25 modification was based on analysis of 2009 monthly gas
CASE NO. IPC-E-OS-1010/24/0S STERLING, R (Di) 13
STAFF
1 forwards prices as quoted daily by NYMEX for the past
2 twelve months.
3 Except for these two changes, I used all of
4 Idaho Power's other assumptions in AURORA. A summary of
5 the results of this AURORA simulation is presented in
6 Staff Exhibit No. 105.
7 Q.Have you prepared an exhibit comparing your net
S power supply cost recommendations to Idaho Power's?
9 A.Yes, Staff Exhibit No. 106 compares my
10 recommendation for net power supply cost to Idaho
11 Power's. The exhibit also shows the PURPA costs that are
12 added to get total power supply cost, as well as the
13 normalized power supply costs adopted in the Company's
14 last general rate case. Note that even under Staff i s
15 recommendation, net power supply costs are more than
16 double what they were in the Company's last general rate
17 case.
lS Q.Did you make any AURORA runs using gas prices
19 from Idaho Power's own gas forecast?
20 A.No, I did not. I did not use Idaho Power's own
21 forecasted gas prices for 2009 because all of the
22 forecasts used by Idaho Power were made in March - before
23 the extreme run-up in prices prior to July, before the
24 precipi tous drop in prices in July and August, before
25 hurricanes Gustav and Ike, and before the credit crisis
CASE NO. ÍPC-E-OS-10
10/24/0S STERLING, R (Di) 14
STAFF
1 in October. I do not believe any forecasts for 2009 that
2 were made in March 2008 should be relied upon for power
3 supply modeling. Idaho Power's forecasted price for 2009
4 was $8.89 per MMBtu. I believe that price is clearly too
5 high. Such high gas prices produce net power supply cost
6 results that are unrealistically low. Using my other
7 assumptions, a price of $8.89 per MMBtu would have
8 produced a net power supply cost of approximately $64.5
9 million.
10 Q.Have you prepared an exhibi t to compare Idaho
11 Power's net power supply recommendation, your
12 recommendation, and other net power supply results
13 obtained using other possible gas price assumptions?
14 A.Yes, I have. Staff Exhibit No. 107 shows the
15 effect of various gas price assumptions on net power
16 supply costs and compares my recommended result to the
17 Company's. As the results show, my recommended net power
18 supply cost is below the Company's recommendation, but
19 higher than it would be if several other gas forecasts
20 were used. Compared to the results obtained using other
21 possible gas prices, I believe my recommendation is
22 conservative.
23 Q.What happens if Idaho Power's actual net power
24 supply costs turn out to be different than those adopted
25 in this general rate case?
CASE NO. IPC-E-08-1010/24/08 STERLING, R (Di) 15
STAFF
1 A.If actual power supply costs in the future are
2 different than those adopted in this general rate case,
3 then the difference will be considered in the annual
4 Power Cost Adjustment (PCA) until the Company's next
5 general rate case. Under the PCA, 90 percent of the
6 difference between the annual proj ected power cost and
7 the Commission approved base power cost as established in
S this case will be credited to or collected from
9 customers. Consequently, Idaho Power will never be at
10 risk for more than 10 percent of the difference between
11 proj ected power supply costs and the base power supply
12 costs.
13 Q.Can you validate the AURORA model by comparing
14 predicted results to actual net power supply costs from
15 prior years, say for 2007?
16 A.Although it is possible to compare simulated
17 results to actual historical results, the two will
lS probably never be equal even if historical gas prices and
19 hydro conditions are replicated. Actual electric market
20 prices are affected by many things besides just hydro
21 conditions and natural gas prices. Many factors that
22 affect actual power supply costs simply cannot easily be
23 replicated on an actual basis in AURORA, such as weather,
24 plant outages, fuel supply interruptions, and market
25 speculation. The 2007 water year results from the "base
CASE NO. IPC-E- OS - 10
10/24/0S
STERLING, R (Di) 16
STAFF
1 case" used to determine power supply costs in this case
2 will not match actual 2007 power supply costs because the
3 "base case" for 2007 only differs from the other 79 years
4 used in the analysis by the hydro conditions. The base
5 case for 2007 does not use actual gas prices in 2007,
6 actual demand in 2007, or any other actual data from
7 2007. The 2007 results only reflect 2007 water
S conditions and nothing more.
9 Does this conclude your direct testimony inQ.
10 this proceeding?
11
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20
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A.Yes, it does.
CASE NO. IPC-E-OS-1010/24/0S STERLING, R (Di) 17
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Exhibit No. 103
Case No. IPC-E-08-10
R. Sterling, Staff
10/24/08
Net Power Supply Cost Adjustments by Account
Account Description IPCo Proposal Staff Proposal Adjustment
447 System Opportunity Sales
System Opportunity Sales $110,210,425 $116,568,567 $6,358,142
501 Fuel (Coal)
Bridger $82,101,940 $82,077,624 $(24,316)
Boardman $6,035,719 $6,022,749 $(12,971)
Valmy $45,280,425 $45,354,350 $73,925
Subtotal $133,418,084 $133,454,723 $36,639
547 Fuel (Gas)
Danskin $6,307,632 $5,554,274 $(753,357)
Bennett Mountain $779,236 $570,905 $(208,331)
Subtotal $7,086,868 $6,125,180 $(961,688)
555 Purchased Power
Purchased Power $58,126,719 $54,565,145 $(3,561,574)
Total Net Power Supply Cost $88,421,246 $77,576,480 $(10,844,766)
555 Transmission Losses $3,051,318 $2,666,773 $(384,545)
Total Net Power Supply Cost including Trans Losses $91,472,564 $80,243,253 $(11,229,311)
Exhibit No. 104
Case No. IPC-E-08-10
R. Sterling, Staff
10/24/08
Scenario 1
2008 NORMALIZED NET POWER SUPPLY COSTS
Thermal Generation (MWh) (Br, Bo, V)7,444,117
Hydro Generation (MWh)6,193,320
Combustion Turbine (MWh)68,315
Total Market Purchases (MWh)1,091,102
Total Market Sales (MWh)564,310
Total Thermal Unit Fuel Costs ($000)'1/139,319
Total Market Purchases ($000)67,479 $61.84
Total Market Sales ($000)32,217 $57.09
Net Power Supplv Costs ($0001 174,581
~ Bridger, Boardman, Valmy, Danskin, Bennett Mt
Scenärio2
Thermal Generation (MWh) (Br, Bo, V)7,429,752
Hydro Generation (MWh)7,429,648
Combusüon Turbine (MWh)41,854
Total Market Purchases (MWh)664,477
Total Market Sales (MWh)1,333,097
Total Themial Unit Fuel Costs ($000).137,187
Total Market Purchases ($000)40,248 $60.57
Total Market Sales ($000)73,947 $55.47
Net Power Supplv Costs 1$0001 103,487
Bridger, Boardman, Valmy, Danskin, Bennett Mt
Scenario 3
Thermal Generation (MWh) (Br, Bo, V)7,406,067
Hydro Generaüon (MWh)8,637,374
Combusüon Turbine (MWh)27,197
Total Market Purchases (MWh)367,440
Total Market Sales (MWh)2,205,336
Total Themial Unit Fuel Costs ($000)'135,680
Total Market Purchases ($000)21,426 $58.31
Total Market Sales ($000)114,375 $51.86
Net Power Supplv Costs ($000\42,730
Bridger, Boardman, Valmy, Danskin, Bennett Mt
Scenario 4
Themial Generation (MWh) (Br, Bo, V)7,381,227
Hydro Generation (MWh)9,900,506
Combustion Turbine (MWh)22,468
Total Market Purchases (MWh)220,978
Total Market Sales (MWh)3,292,332
Total Thermal Unit Fuel Costs ($000)'134,853
Total Market Purchases ($000)12,403 $56.13
Total Market Sales ($000)162,701 $49.42
Net Power Suoolv Costs 1$000\115,444\
Bridger, Boardman, Valmy, Danskin, Bennett MI
Scenario 5
Thermal Generation (MWh) (Br, Bo, V)7,289,636
Hydro Generation (MWh)11,581,966
Combustion Turbine (MWh)8,878
Total Market Purcases (MWh)57,079
Total Market Sales (MWh)4,704,463
Total Themial Unit Fuel Costs ($000)'132,210
Total Market Purchases ($000)2,858 $50.07
Total Market Sales ($000)211,702 $45.00
Net Power Supplv Costs ($0001 176,635\
Themial Generation (MWh) (Br, Bo, V)7,390,160
Hydro Generation (MWh)8,748,563 998.7
Combustion Turbine (MWh)33,742
Total Market Purchases (MWh)480,215
Total Market Sales (MWh)2,419,908
Total Themial Unit Fuel Costs ($000)'135,850
Total Market Purchases ($000)28,883 $60.15
Total Market Sales ($000)118,988 $49.17
Net Power Supplv Costs 1$0001 45,744
Bridger, Boardman, Valmy, Danskin, Bennett Mt
AVERAGE OF ALL YEARS
Bridger,Boarman,Valmy, Bennett and
Danskin (axel fixed)
11 Excludes Danskin Fixed
10/20/2008 12:09 PM
Danskin-Fixed
Contracts
Wheeling
IAvQ NPSC
3,730
25,682
2,420
77,576 I
008 Nomialized Themial Out ut MWh
im Bridger 5,098,743almy 1,913,229oardman 432,145anskin 53,509ennett Mt 14,806
ed
82,211
46,090
6,192
3,754
1,072
rmlized Themial Out ut MWh
'dger 5,097,825aimy 1,903,266Boardman 428,661Danskin 31,519Bennett Mt 10,335
2008 Nomialized Cost $000
Jim Bridger 82,196Valmy 45,866Boardman 6,146Danskin 1/ 2,230Bennett Mt 749
2008 Normalized Thermal Outnut IMWh
Jim Bridger 5,093,213
Valmy 1,888,365
Boardman 424,490
Danskin 20,570
Bennett Mt 6,627
2008 Nomialized Cost $000
Jim Bridger 82,121
Valmy 45,531
Boardman 6,091
Danskin 1/1,456
Bennett Mt 480
2008 Nomialized Themial Output (MWh)
Jim Bridger 5,091,732
Valmy 1,871,165
Boardman 418,330
Danskin 16,884
BennettMt 5,584
2008 Nomialized Cost $000
Jim Bridger 82,098
Valmy 45,144
Boardman 6,014
Danskin 11 1,193
Bennett Mt 405
2008 Nomialized Themial Outnut MWh
Jim Bridger 5,070,926
Valmy 1,826,621
Boardman 392,089
Danskin 6,837
Bennett Mt 2041
2008 Normalized Cost $000
Jim Bridger 81,762
Valmy 44,141
Boardman 5,671
Danskin 1/487
Bennett Mt 148
2007 Nomialized Themial OUln,,1 IMWh
Jim Bridger 5,090,488
Valmy 1,880,529
Boardman 419,143
Danskin 25,864
Bennett Mt 7879
2007 Normalized Cost $000'
Jim Bridger 82,078
Valmy 45,354
Boardman 6,023
Danskin 1/1,824
Bennett Mt 571
aMW
560
218
49
6
2
$/MWh
$16.12
$24.09
$14.33
$70.16
$72.42
aMW
580
217
49
4
1
$/MWh
$16.12
$24.10
$14.34
$70.74
$72.45
aMW
580
215
48
2
1
$/MWh
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$24.11
$14.35
$70.77
$72.49
s!
560
213
48
2
1
$/MWh
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$24.13
$14.38
$70.67
$72.51
aMW
577
208
45
1
o
$/MWh
$16.12
$24.17
$14.46
$71.27
$72.63
aMW
580
214
48
3
1
$/MWh
$16.12
$24.12
$14.37
$70.52
$72.46
Exhibit No. 105
Case No. IPC-E-08-10
R. Sterling, Staff
10/24/08 Page 1 of 2
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Summary Comparison of Net Power Supply Costs
Net Power
Suoolv Cost PURPA Total
Idaho Power Case $88.4 $63.3 $151.7
Staff Case $77.6 $63.3 $140.9
Difference $10.8 $-$10.8
2007 Normalized Adopted Costs $34.9 $93.1 $128.0
All costs shown are in milion $
Including costs due to transmission losses, the difference between Staffs case and
Idaho Power's case is $11.2 milion.
Exhibit No. 106
Case No. IPC-E-08-10
R. Sterling, Staff
10/24/08
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Case No. IPC-E-08- 10
R. Sterling, Staff
10/24/08 Page 1 of 2
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 24TH DAY OF OCTOBER 2008,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE
NO. IPC-E-08-10, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
DONOV AN E WALKER
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: bkline(iidahopower.com
lnordstrom(iidahopower .com
dwalker(iidahopower .com
PETER J RICHARDSON
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(irichardsonandoleary.com
RANDALL C BUDGE
ERIC L OLSEN
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: rcb(iracinelaw.net
elo(iracinelaw.net
MICHAEL L KURTZ ESQ
KURT J BOEHM ESQ
BOEHM KURTZ & LOWRY
36 E SEVENTH ST STE 1510
CINCINATI OH 45202
E-MAIL: mkurz(iBKLlawfrm.com
kboehm(iBKLlawfirm.com
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH ST
BOISE ID 83702
E-MAIL: bmpurdy(ihotmaiLcom
JOHNRGALE
VP - REGULATORY AFFAIRS
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: rgale(iidahopower.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreading(imindspring.com
ANTHONY Y ANKEL
29814 LAK ROAD
BAY VILLAGE OH 44140
E-MAIL: yanel(iattbi.com
KEVIN HIGGINS
ENERGY STRATEGIES LLC
PARKS IDE TOWERS
215 S STATE ST STE 200
SALT LAKE CITY UT 84111
E-MAIL: khiggins(ienergystrat.com
LOTH COOKE
ARTHUR PERRY BRUDER
UNITED STATE DEPT OF ENERGY
1000 INDEPENDENCE AVE SW
WASHINGTON DC 20585
E-MAIL: lot.cooke(ihq.doe.gov
arhur. bruder(ihq .doe. gOY
CERTIFICATE OF SERVICE
DWIGHT ETHERIDGE
EXETER ASSOCIATES INC
5565 STERRTT PLACE, SUITE 310
COLUMBIA MD 21044
E-MAIL: detheridge($exeterassociates.com
DENNIS E PESEAU, Ph.D.
UTILITY RESOURCES INC
1500 LIBERTY STREET SE, SUITE 250
SALEM OR 97302
E-MAIL: dpeseau($excite.com
CONLEY E WARD
MICHAEL C CREAMER
GIVENS PURSLEY LLP
601 W BANNOCK ST
PO BOX 2720
BOISE ID 83701-2720
E-MAIL: cew($givenspursley.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
E-MAIL: kmiler($snakeri verallance.org
SEC~#~-
CERTIFICATE OF SERVICE