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BEFORE THE IDAHO PUBLIC UTJLITIES COMMISSION
CASE NO. AVU-
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DIRECT TESTIMONY OF RICHARD L. STORRO
REPRESENTING A VISTA CORPORATION
Exhibit (RLS-
Please state your name, employer and business address.
My name is Richard L. Storro. My business address is 1411 East Mission
Avenue, Spokane, Washington, and I am employed as the Director of Power Supply for
A vista Utilities.
What is your educational background?
I participated in a program with the College of Idaho and the University of
Idaho, where upon completion I received a Bachelor of Science degree in physics from
the College of Idaho and a Bachelor of Science degree in electrical engineering from the
Ufliversity of Idaho. hoth in 1973.
How long have you been employed by the Company?
I started working for Avista in 1973 as a distribution engineer. I have
worked in various engineering positions, and have held management positions in line and
gas operations, system operations, hydro production and construction, and transmission. I
joined the Energy Resources Department as a Power Marketer in 1997 and became
Director of Power Supply in 2001. My primary responsibilities involve the oversight of
both the short-term and long-term planning and acquisition of power supply resources for
the Company.
Can you please summarize your testimony?
Yes. First I provide a brief summary of the factors driving power supply
expenses during the review period, July 2002 through June 2003. I then provide more
detail for several specific items. These items include: 1) the Enron long-term contract
termination, 2) the Kettle Falls Bi-Fuellease payments, 3) the delay in the online date of
the Coyote Springs 2 project, and 4) the purchase and sale of fixed price natural gas.
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Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit Nos. _(RLS-1) and _(RLS-2), which
were prepared under my supervision and direction.
SUMMARY
Would you please summarize the power supply expense deferrals during
the review period?
Yes. During the review period, Idaho s share of power supply expenses
exceeded the authorized level by $25 924 662. Of that total, 90 percent or $23 332 195
was deferred. and the Company absorbed 10 percent or $2 592.466.
Power supply expenses were higher than the authorized level due to several
factors. The largest factor was the sale of fixed price gas. Based on the average purchase
and sale price, the fixed price gas purchases added approximately $13.1 million to
Idaho s share of power supply expense. Hydro generation was approximately 12.9 aMW
below the authorized level, which would account for approximately $2.1 million of
increased expense. Colstrip and Kettle Falls together generated approximately 8 aMW
above the authorized. Rathdrum generated approximately 21 aMW below the authorized
level due in part to the relatively low price of electricity compared to natural gas costs.
The Company' other gas-fired generating plants, Northeast turbine, Boulder Park, and the
Kettle Falls combustion turbine generated 2 aMW during the period.
Other power supply expenses during the review period include a payment to
terminate a long-term power purchase with Enron and the final lease payments of $3.
million ($1.3 million Idaho share) related to the Kettle Falls Bi-Fuel generating units.
The $2.9 million Enron buyout payment ($960 000 million Idaho share) occulTed in
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October 2002, and was recorded as a power purchase expense. The Kettle Falls Bi-Fuel
lease payments began in September 2001 and were included in the prior filing for the
review period ending June 2002.
Another factor driving the deferrals is the age of the authorized case.The
authorized case is based on the loads, contracts and resources in place for the period JuJy
1999 through June 2000. During that period, the Company had several large off-system
power sales that generated significant revenue. Almost all of those sales have ended and
as such, the revenue is reduced, which is reflected in a reduction in Account 447, Sale for
Resale, revenue -of $72 minion on a system basis ($24 million Idaho share). Purchased
power expense has also decreased from the authorized level due in part to several long-
term contracts ending. Purchased power expense, however, has decreased by only $24
million on a system basis ($8 million Idaho share). The Company plans to file a general
rate case within the next year to reset the authorized level of power supply revenues and
expenses.
ENRON CONTRACT SETTLEMENT
Please provide a brief overview of the Enron contract buyout.
In 2001 Avista entered into a multi-year power purchase agreement with
Enron. After filing for bankruptcy, Enron advised counterparties that they would be
willing, in conjunction with the Creditors ' Committee , to consider offers of settlement for
the outstanding contractual positions. A vista sent an original proposal for the termination
of the Enron Purchase that was rejected by Enron' s Creditors ' Committee. Subsequent
discussions between A vista and Enron culminated in the final settlement agreement. The
final agreement called for the mark-to-market value of the contract to be determined by a
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third party market price and discounted by 11.5 percent. The calculation of the payment
would be performed based on prices the day prior to the bankruptcy judge approving the
settlement.
How did customers benefit from the buyout?
Customers benefited in a couple of ways. First, the Company removed the
uncertainty of whether or not the energy would be delivered. There was little likelihood
that Enron could deliver the energy and if the contract was sold to another counterparty, it
would raise additional uncertainties as to who the counterparty would be, and its
creditworthiness and ability to deliver power. Second, the customers benefited by the
higher discount rate used to value the contract. The discount rate used to determine the
buyout amount was 11.5%, which is higher than A vista s discount rate and well above the
carrying charge rate on the PCA deferral balance. This higher discount rate resulted in a
$218 000 benefit to Idaho customers. The Company also netted against the contract
settlement payment approximately $1 million of a net accounts receivable owed to Avista
by Enron. These receivables were for transactions that had occurred in 2001, and
reflected revenues that the Company had already credited to customers in prior PCA
deferral calculations. Therefore, through this buyout, A vista preserved for customers
dollar for dollar recovery of these amounts owed to A vista by the bankrupt Enron.
KETTLE FALLS HI-FUEL LEASE PAYMENTS
Please explain the lease payments for the Kettle Falls Bi-Fuel generating
units.
The Company made lease payments on the Kettle Falls Bi-Fuel generating
units from September 2001 through December 2002. An explanation of these leased
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units, together with supporting workpapers, was provided in the prior August 2002 PCA
filing, and a review of these lease payments was conducted in that proceeding. The $1.3
million (Idaho share) of payments during this review period represent the final lease
payments.
COYOTE SPRINGS 2
Could you please provide a brief overview of the Coyote Springs 2
project?
Yes. The Coyote Springs 2 project began commercial operation on July 1
2003 and has been oper~ting reliably. The Company s fifty-percent share of the output
has been in the 115 to 125 MW range.! The plant was originally planned to be on-line
June 2002, but several issues beyond the Company s control, including the Enron
bankruptcy and problems with the generator step-up transformer caused a delay in the on-
line date of the plant.
Please explain the impact of the bankruptcy of Enron and its subsidiary
NEPCO on the CS2 project construction schedule.
Enron filed for bankruptcy in late 2001. Enron ceased making funds
available to NEPCO to pay vendors, equipment suppliers, craft, etc. to complete the CS2
project. In first quarter 2002, the CS2 partners (A vista and Mirant) stepped in and took
over the role of CS2 EPC contractor from NEPCO. The transition process included
dismissing construction staff at the CS2 site and putting in place new management and
The variation in the output is due primarily to the ambient air temperature, i., the warmer
the weather, the lower the output, and vice-versa.
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construction staffing. The replacement of NEPCO added approximately two months to
the project completion timeline, which was extended into August of 2002.
Please explain the delay related to the generator step-up transformer.
The completion of the CS2 project was delayed first by a failure of the
original generator step-up (GSU) transformer in May of 2002 and second by damage to
the replacement GSU transformer that was observed upon its arrival at the project site in
December 2002.
Would you please describe the circumstances of the failure of the first
(JSU transformer?
Yes. On March 3, 2002 the GSU transformer was energized from the CS2
switch yard that is interconnected with the Bonneville Power Administration (BP
500kV transmission system. The generators at CS2 were not operational during that time
frame. On May 6, 2002 the GSU transformer experienced an internal failure, which
resulted in significant damage to the transformer windings and a rupture of tank.
What steps did the CS2 partners, A vista Corporation and Mirant, take to
address the GSU transformer failure?
The CS2 partners investigated options for replacing the GSU transformer
including an investigation into whether there was a compatible spare GSU transformer
available from another company in the industry. One of the first options investigated was
to attempt to find another entity that might have an available three-phase transformer with
the same capacity, winding configuration and respective voltage ratings. Alternatively,
the CS2 partners looked for combinations of transformers that could be used together to
provide the necessary configurations. However, the CS2 partners were unable to locate
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an unused transformer or transformer combination that would match up with the CS2
GSU transformer specifications.
Other alternatives explored at that time included:1) repair of the original
transformer; 2) purchase of a new second transformer from Alstom; 3) purchase of a
new second transformer from a different vendor; 4) change the original design of CS2 to
allow for installation of multiple transformers.
Which of the options did the CS2 partners select to address the
transformer failure?
On June 13, 2002 the rS2 partners decided to purchase a second GSU
transformer from Alstom. The deciding factor was the shorter lead-time for a new
Alstom transformer compared to a new transformer from an alternate manufacturer.
Alstom has over 100 years in the electrical equipment business and is one of the world'
leading manufacturers of electric generation, transmission and distribution equipment.
They have over 30 000 employees in more than 30 countries. Alstom has been
manufacturing transformers up to 525 kV rated voltage and 400 MV A rated power in the
Gebze plant for over 30 years.
Will the CS2 partners be compensated for the failed transformer?
Work with the insurance company for the CS2 project is in progress. At
this time the insurers have indicated that they will pay for the replacement transformer
and a portion of the costs to clean up the site due to the oil spill.
Would you please describe the circumstances related to the damage to the
second GSU transformer?
S tOITO- Di
A vista
Yes. The second transformer arrived at the CS2 site on December 15
2002. After the transformer was moved onto its foundation , Alstom personnel pelformed
an internal inspection and found that the fifth leg of the transformer core had been
damaged. Alstom and CS2 representatives discussed the situation and agreed that the
second transformer could not be repaired in the field and would need to be sent to a
suitable repair facility. Arrangements were made to ship the transformer to the Edison
ESI repair facilities in California. The repairs were completed and the transformer was
The plant began commercial operation July 1 , 2003 and theonsite in May 2003.
, 9. - transformer and the generating plant have been operating reliably.
NA TURAL GAS SALES
Please explain the sales related to the fixed price natural gas contracts.
In early 2001 , the Company purchased approximately 48,000 decatherms
per day of index priced gas. Soon afterwards , the Company entered into four fixed-for-
floating swaps that fixed the price for a portion of the gas purchases. The gas prices are
fixed for 40 000 decatherms per day through October 2003 and for 20 000 decatherms per
day through October 2004. The average price of the 40 000 decatherms per day of fixed
price gas is $6.14 per decatherm and the average price of the 20 000 per day is $6.30 per
decatherm. An explanation of these transactions together with extensive supporting
documentation was provided in the prior August 2002 PCA filing, and a review of these
transactions was conducted in that proceeding.
This natural gas was purchased for which generating plants?
When the Company purchased the gas in early 2001 it was anticipated that
most of it would be consumed at Coyote Springs 2, because it is the Company s most
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efficient gas-fired plant. The deal tickets explaining the fixed-for floating swaps indeed
refer to gas purchased for the Coyote Springs plant. It was understood at the time
however, that the gas could be consumed at any of the Company s gas-fired plants
including, Rathdrum, Northeast, Boulder Park, the Kettle Falls combustion turbine, and
Coyote Springs 2.
The gas was purchased with delivery rights to Malin, Coyote Springs 2 and the
Company s other gas-fired plants. The gas could be used at Rathdrum or also be easily be
laid off or diverted to the Northeast, Boulder Park and Kettle Falls CT projects. This
portfolio of gas-fired plants provides multiple options for Avista. Coyote will normally
be operated as a baseload gas-fired resource. If Coyote is unavailable then the gas can be
used at any of the Company s other gas-fired projects. If, on the other hand, the price of
electricity is less expensive than the cost of running the gas-fired plants, the gas can be
sold and electricity purchased.
As previously explained in the August 2002 filing, hedging the price of natural
gas was less expensive than purchasing power at the prices in the forward market. The
fixed price gas could be used to generate power at the Company s plants for the following
cost:
Generation
Cost ($/MWh)
$45
$58
$57
$75
$85
Plant
Coyote Springs 2
Boulder Park
Kettle Falls CT
Rathdrum
Northeast
This gas was purchased at a time when the comparable cost for electricity was in
the range of $75/MWh to $117/MWh for a flat power product at the Mid Columbia.
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While it was assumed at the time that the Company would consume the gas at
Coyote Springs, since it would be the Company s most efficient unit, the Company
overall gas management strategy remained the same despite Coyote Springs 2 temporarily
not being available.
generation?
How does the Company manage natural gas purchased for thermal
The overall objective of managing natural gas purchased for generation is
to minimize the total power supply expense of the Company. This is done by purchasing
the required energy to serve load at the least cost, either by purchasing gas to fuel power
plants or by directly purchasing electricity. Natural gas purchased for generation of
power is converted to MWh based on the heat rates of the most efficient and economical
plants available. On a daily basis, the cost to generate using gas is calculated using the
forward value of the gas times the heat rate of the plants plus any variable plant O&M.
This cost to generate is then compared to the cost of market electricity for the same
forward period. If the cost to purchase market electricity is lower than the cost
generate at the most efficient plants available, then the gas is sold and if needed, the
power to replace the lost generation is purchased.
Each day the Company reviews its 18-month forward-looking load and resource
monthly imbalance position contained in the daily Position Report and the timing of the
purchase or sale of either natural gas or electricity for delivery in various future time
frames is evaluated. The Position Report incorporates the most current information on
expected future hydroelectric generation levels, thermal generating plant availability and
fueled status, and load forecasts. Monthly imbalance positions in the Position Report are
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Avista
differentiated between heavy load hour and light load hour periods. The Company s Risk
Policy provides over-arching guidance to this evaluation process with respect to short and
long imbalance position limits. The Risk Policy volumetric limits for short and long
positions are larger the further one looks into future periods and more narrow in the near-
term months. The timing of decisions to purchase or sell either natural gas or electricity
in future periods are guided by the Company s Risk Policy and by an assessment of the
daily Position Report in combination with the economic evaluation of the relative
economic choice between generating with natural gas or purchasing electric power.
In the workpapers included with this filing, the Company has provided detailed
information regarding each of the natural gas sales transactions that occurred during the
PCA review period. The documentation for each transaction, which was prepared at the
time the transaction occurred, generally includes the deal ticket, a brief write-up
explaining the reason for the transaction, the daily Position Report showing the
Company s load/resource situation for the relevant period, the market prices for
electricity and natural gas for the period, as well as other supporting information.
Is natural gas ever sold without purchasing market electricity?
Yes, if the Company has a surplus electric power position, selling gas may
create greater value than using the gas to generate electricity and selling electric power.
the sale of gas and resulting decrease in generation does not require a purchase of power
to balance the forward position, the power would not be purchased.
What was the benefit of selling the gas instead of using it for generation?
By selling the gas the Company l()wered total power supply expense over
the review period. The savings can be calculated by first converting the cost of gas to a
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cost of generation (including variable plant O&M) at the plants for which generation was
displaced. This cost is then compared to an actual purchase cost of power in the same
time frame (i.e. peak for August), for equivalent MWh. If it was not necessary to
purchase power, due to estimated electric surplus condition, then a quoted price for power
at the time of the gas sale was used. An example of how the savings are determined and
how the savings are recorded and included in the PCA calculations is shown in Exhibit
No. _(RLS-l).
Gas is often sold months ahead of the delivery period. For example on June 20
0 ,200?, sqS was sold and power purchased for the months of November and December
2002. Gas volumes of 12 000 dthlday at $3.54/dth for November and 5 000 dth/day at
$3.82/dth for December were sold and power (25 MW November flat (g) $33.50/MW and
25 MW December LL (g) $34.00/MW) was purchased. The estimated benefit of this
transaction was about $318 000, as detailed on lines 14 and 15 in Exhibit No. _(RLS-2).
Based on the actual gas sales and power purchases during the review period the
Company estimates a reduction in power supply costs of $11.8 million (system basis
$3.9 million Idaho share) for the 40,000 dthlday of fixed priced turbine fuel sold for the
July 1 2002 through June 30 2003 delivery period. A summary page showing the gas
sales and electric purchases that resulted in these savings is shown in Exhibit No.
(RLS-2).
With higher gas prices, will the Company continue to show a cost in the
deferrals for the sale of gas not consumed?
Yes. The Company may continue .to sell gas and purchase power
depending on the cost relationship between gas and electricity. In fact, in 2002, the
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Company sold some of the fixed price gas that was to be delivered in 2003 and made
electric purchases to replace the energy. Because these gas sales were made before the
price of gas had risen substantially, the sale of the gas will show a loss. Offsetting that
loss, however, are power purchases at relatively low prices compared to current power
prices. These transactions reduced overall power supply expenses even though there is an
expense for the sale of the gas.
Does that conclude your direct pre-filed testimony?
Yes.
- -, - --
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BEFORE THE IDAHO PUBLIC UTJLITIES COMMISSION
CASE NO. A VU-E- 111./
EXHJBIT NO. (RLS-
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vista Corp.
Summary of Savings Obtained by Selling Fixed Priced Gas, Jul 2002 - Jun 2003
(40,000 Dth/day sold)
Line Transaction Deal Delivery Savings from
No.Date Ticket Months Volume Price Power Purchases Related to Sale of Gas not Generating
(dthlday)($/dth)
08-Jan-G0270 Jul 000 $2.No purchases made related to sale of gas due to position length $84 308
03-Apr-G0366 Jul 000 $3.No purchases made related to sale of gas due to position length $110 927
04-Apr-G0370 Nov-oct 03 000 $3,No purchases made related to sale of gas due to position length 629,216
05-Apr-G0372 Nov-oct 03 000 $3.No purchases made related to sale of gas due to position length 385 341
05-Apr-G0373 & 374 Jul 000 $3.No purchases made related to sale of gas due to position length $258,318
17-May-02 G0432 Jul-Oct 000 $3.25 aMW a3 02 ~ $39.75/MW DT 2190 & Oct 02 (i:Y $36,75/MW DT 2191 $663,172
21-May-02 G0439 Aug-oct 000 $3.25 aMW Aug02 ~ $39.50/MW DT 2200, Sept 02 (i:Y $39.50/MW DT 2196 $528 362
& Oct 02 ~ $35.75/MW DT 2195
21-May-02 G0438 & 440 Nov 000 $3,50 aMW Nov 02 ~ $35.83/MW DT 2194 & DT 2195 avg price $219 948
22-May-02 G0444 Sep-oct 000 $3.25 aMW Sep02 ~ 37.95 DT 2202 & Oct 02 (i:Y $35,90 DT 2194 $121 568
23-May-02 G0446 Oct-Dec 000 $3.25 aMW a3 02 ~ $38,00 DT 2199 $172 755
28-May-02 G0448 & 449 Oct 13,000 $3.75 aMW Oct 02 ~ $35.00/MW DT 2204, 2205 & 2211 avg price $73,392
05-Jun-G0464 Dec 000 $3.25 aMW a4 02 LL ~ $30.50/MW DT 2217 $65 929
19-Jun-G0485 July 000 $2.No purchases made related to sale of gas due to position length $117 124
20-Jun-GC488 De'~'OOI)$3.25 aMW Dee 02 LL ~ $34,OO/MWDT 2232 $72 304
20-Jun-G0489 Nov 000 $3.25 aMW Nov 02 flat ~ $33.50/MW DT 2231 $245 639
15-Jul-G0509 Sep 000 $2.50 aMW Sep 02 ~ $24.50/MW DT 2246 & DT 2251 avg price $147 716
15-Jul-G0510 & 511 Aug 30,000 $2.125 aMW Aug 02 ~ $21.221MW DT 2247 2249,2250 2254 2255 avg pr $513,189
13-Aug-o2 G0543 Sep 000 $2.No purchases made related to sale of gas due to position length $67 257
10-Sep-02 G0604 Oct 000 $2.25 aMW LL Oct 02 ~ $27,75/MW DT 2267 $16 995
17-Sep-o2 G0624 Dec 000 $4.No purchases made related to sale of gas due to position length $193 453
01-0ct-G0660 Nov 000 $3.25 aMW Nov 02 ~ $34.50/MW DT 2276 $88,829
01-0ct-G0661 Oct (3-31) 000 $3.48 25 aMW Oct 02 (4-31) ~ $29,25/MW DT 2276 $103 693
20-Nov-G0741 Dec 500 $3.25aMW HL Dec 02 ~ $36.60/MW DT 2293 & 25 aMW LL Dec 02 ~$113 425
$31.40 DT 2294
18-Jul-G0515 Mar-Jun 000 $3.No purchases made related to sale of gas due to position length $714 288
19-Jul-G0516 Apr-Jun 000 $3,No purchases made related to sale of gas due to position length $565 174
15-Aug-02 G0552 Jan 000 $3.No purchases made related to sale of gas due to position length $178,365
15-Aug-02 G0553 Feb 000 $3.No purchases made related to sale of gas due to position length $147 418
15-Aug-G0554 Mar 000 $3.No purchases made related to sale of gas due to position length $68 051
30-Sep-02 G0655 May-Jun 10,000 $3.No purchases made related to sale of gas due to position length $521 647
30-Sep-02 G0656 May 000 $3.No purchases made related to sale of gas due to position length
10-0ct-G0680 Feb 000 $3.No purchases made related to sale of gas due to position length $67,430
1O-0ct-G0681 & 82 Jan 000 $4.50 aMW Jan 03 ~ $39.10/MWh, DT 2279 $561 825
20-Nov-02 G0743 Jan 000 $4.25 MW HLH Jan 03 ~ $39.25/MWh, DT 2295 $88 313
23-Dec-G0792 Feb 000 $4.75 MW HLH Feb 03 ~ $41,25/MWh, DT 2316 & 2317 $178 272
23-Dec-02 G0793 Mar 000 $4.47 50 MW HLH Mar 03 ~ $41.25/MWh, DT 2314 & 2315 $175,831
23-Dec-02 G0794 Apr 000 $4,2 - 25 MW HLH Apr 03 ~ $39.00 & $39.50/MWh, DT 2321 & 2323 $136,243
31-Dec-02 G0804 Feb-Apr 000 $4.25 MW HLH Mar & Apr 03 ~ $4 t.25/MWh, DT 2325
25 MW HLH Mar 03 ~ $42.25/MWh, DT 2324 $361 019
03-Jan-o3 G0810 Feb 000 $4.45 75 MW HLH Feb 03 ~ $41,25/MWh, DT 2316 & 2317 $151 672
06-Jan-G0814 Feb 000 $4.25 MW HLH Feb 03 ~ $41.25/MWh, DT 2318
25 MW LLH Feb 03 ~ $36,OO/MWh, DT 2322
09-Jan-G0822 Mar 000 $4.No purchases made related to sale of gas due to position length $141 031
09-Jan-G0823 Jun 000 $4.No purchases made related to sale of gas due to position length $237,165
10-Jan-G0827 Jun 000 $4.No purchases made related to sale of gas due to position length $137,286
14-Jan-G0831 Feb 000 $4.25 MW HLH Feb 03 ~ $42.00/MWh, DT 2329 $10,851
16-Jan-G0837 Mar 000 $5.25 MW HLH Mar 03 ~ $45.00/MWh, DT 2335 $30,107
25-Feb-G0859 Apr 000 $4,50 MW HLH Apr 03 ~ $44.18/MWh, DT 2353 & 2355
25 MW LLH Apr 03 ~ $36.75/MWh, DT 2354 $292 134
Total Savings from Selling Gas $11 756,982
Storro 2003 PCA ExUD Exh RLS-xls
Exhibit No. - (RLS-
Case No. AVU-
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