20040712Lafferty Rebuttal.pdf

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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR,' i,'-3 iLl Lie
REGULATORY AND GOVERNMENTALlmitUR~ COi'1t1ISSION
A VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
zna'1 JUL I 2 AM 10:
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATEOF IDAHO
CASE NO. A VU-04-
CASE NO. A VU-04-
REBUTTAL TESTIMONY
ROBERT J. LAFFERTY
FOR A VISTA CORPORATION
(ELECTRIC ONLY)
I. INTRODUCTION
Please state your name, employer and business address.
My name is Robert J. Lafferty. I am employed by Avista Corporation at 1411
East Mission Avenue, Spokane, Washington.
Have you previously filed direct testimony in this proceeding?
Yes.
What is the scope of your testimony in this proceeding?
My rebuttal testimony will respond to the testimony of Dr. Peseau on behalf of
Potlatch Corporation, regarding the rate base treatment of Coyote Springs 2 (CS2) and the
costs associated with the natural gas contracts that have been referred to as Deal A and Deal
B. I will also address Mr. Hessing s testimony regarding Deal A and Deal B. Finally, I will
respond to Mr. Sterling s testimony regarding the costs associated with Boulder Park.
table of contents for my testimony is as follows:
Description Page #
Introduction
ll.Coyote Springs 2 - Response to Dr. Peseau
ill.Natural Gas Purchases - Response to Dr. Peseau
IV.Natural Gas Purchases - Response to Mr. Hessing
Boulder Park - Response to Mr. Sterling
Lafferty, Di-Reb
A vista Corporation
Would you please summarize each of the sections of your testimony?
Yes. In response to Dr. Peseau s testimony regarding Coyote Springs 2:
Between July 1 , 2003 and January 15, 2004, Coyote Springs 2 performed
with a 92% availability factor, generating approximately 85 aMW. It is
currently out of service due to a failed transformer, but is expected to
return to service in mid to late August.
. A vista Utilities purchased CS2 at cost.It was selected through a rigorous
RFP process, which was subjected to third-party review and participated in
by Commission Staff. In fact, Staff witness Mr. Sterling concluded in his
testimony, "Staff does not oppose inclusion of these costs in rate base for
the CS2 plant."
In response to Dr. Peseau s testimony regarding natural gas purchases:
The Deal A and Deal B natural gas hedge transactions were required to fix
the price of physical purchases in order for the resulting generation to be
included to cover open positions, as is required by the Energy Resources
Risk Policy.
Through the Deal A and Deal B natural gas hedge transactions, the
Company fixed the price on the physical natural gas purchases in order to
limit exposure to higher prices and provide a measure of price stability for
customers.
The duration of these purchases was not of an unusual length to cover
open power positions. I will provide several examples of similar medium-
term transactions, which have been very beneficial.
The forward price curves at the time Deal A and Deal B occurred provided
a good indication of appropriate pricing since they are based on actual bids
and transactions in the forward markets.
Because Avista Energy did not maintain sufficient short positions during
the durations of Deal A and Deal B, the gas quantities could not have been
carried to term. Dr. Peseau s presumption regarding the amount of profit
made by A vista Energy resulting from Deal A and Deal B is not
legitimate.
Lafferty, Di-Reb
A vista Corporation
In response to Mr. Hessing s testimony regarding natural gas purchases:
The Deal A and Deal B hedge transactions did not violate the Company
Energy Resources Risk Policy or the Company s long-term planning
criteria, and did not create a speculative long position.
It would have been inappropriate for the Company to sell the electric
generation related to Deal A and Deal B. In fact, had the electricity been
sold, the Company would have just re-created the open positions that Deal
A and Deal B were intended to cover.
Mr. Hessing s recommendation of a $6.5 million disallowance for Deal B
is not appropriate. However, if the Commission were to determine that a
portion of the Deal B transactions should be disallowed, I will present two
alternative methodologies for calculating a disallowance.
In response to Mr. Sterling s testimony regarding Boulder Park:
I will show that Boulder Park was constructed at a time when the
Company was facing extreme market conditions and serious financial
difficulties. Given the challenges presented by the market conditions and
the project's unique characteristics, the construction costs were not
unreasonable. Staffs recommendation of a 10% disallowance is not
appropriate.
Lafferty, Di-Reb
A vista Corporation
II. COYOTE SPRINGS 2 - RESPONSE TO DR. PESEAU
On page 13 of his testimony, Dr. Peseau suggests that CS2 is not used and
useful. Do you agree with his conclusion?
No. The CS2 plant began commercial operation on July 1 , 2003. Between
July 1 , 2003 and January 15 2004, CS2 performed very well with a 92% availability factor.
The plant generated approximately 85 aMW during that period.
The plant is currently out of service due to the failure Of the generator step-up
transformer. The failed transformer has been repaired and tested. It is currently being
shipped back to the CS2 site and is expected to arrive at the end of July 2004. Installation is
expected to be completed in the mid to late August time frame, and the plant will again be
available for service. Furthermore, A vista has ordered a second transformer as a spare from a
different manufacturer to help prevent future interruptions at the plant.
In summary, the transformer issue will be resolved shortly, and the plant has already
demonstrated that it will perform at a high availability factor.
Beginning on page 7 of his testimony, Dr. Peseau expresses concern
regarding the purchase cost of CS2. What is your response to this testimony?
A vista Utilities selected CS2 in December 2000 as part of an all-resource RFP
process. The RFP process compared the CS2 project at cost with 32 other supply-side and
demand-side proposals from the market at the time. I have described in my pre-filed direct
testimony the extensive evaluation, screening steps, and economic analyses that were used to
evaluate and compare all of the proposed projects. The Company retained RW Beck to
conduct an independent review of the modeling and economic analyses of the supply-side
Lafferty, Di-Reb
Avista Corporation
resource proposals. Some excerpts from RW Beck's conclusions after its review of Avista
RFP bid analysis are as follows:
Avista s approach provided a fair and reasonable methodology to determine
which bid option is most viable for A vista. The bid review process was based
on sound financial and economic assumptions and the analysis used
appropriate information to make decisions regarding future markets and
Avista s system needs. (Page 8 ofRW Beck Report)
The approach taken by Avista provided for a fair comparison of the resource
options bid as well as the self-build option. The market prices used in the
analysis provide a reasonable level of detail and a wide enough range of prices
so that bids may be assessed fairly under a variety of market circumstances.
(page 8 ofRW Beck Report)
CS2 was acquired at cost from Avista Power. The CS2 project cost was thoroughly
evaluated through the 2000 All-Resource RFP process and compared to market proposals for
other resource options available at that time. The evaluation process was subjected to third-
party review to confirm there was a fair evaluation of all resource options. Commission Staff
representatives from Idaho and Washington also monitored the selection process.
What were Commission Staff's conclusions regarding CS2 following their
review of the costs in this case?
Staff witness Mr. Sterling states on page 24 of his testimony, "I believe the
RFP process was fair in all respects, and not intended to favor specific proposals, locations
technologies or bidders." Later on page 26 of his testimony, Mr. Sterling indicates that Staff
verified CS2 was transferred "at cost" to Avista Corporation. Mr. Sterling concludes the CS2
section of his testimony by stating on page 29 that "Staff does not oppose inclusion of these
costs in rate base for the CS2 plant."
Lafferty, Di-Reb
A vista Corporation
On page 14 of his testimony, Dr. Peseau suggests that Avista Power
overpaid for the assets it purchased from PGE and Enron. Do you have any comments
on this testimony?
Yes. Although Dr. Peseau has testified to his understanding of some of the
details of the CS2 purchase by A vista Power from PGE and Enron, the costs at issue in this
case are the costs paid by A vista Utilities for CS2, as compared to the costs of other resource
alternatives available at the time.As explained above, the costs of the CS2 resource
alternative were thoroughly evaluated together with other resource alternatives through an
extensive RFP process.The costs were demonstrated to be reasonable and should be
approved for recovery in this case.
Beginning on page 12 of his testimony, Dr. Peseau states that Avista
Corporation did not follow through on its announcement in December 2000 to transfer
the CS2 project to A vista Corporation. Do you have any comments on this testimony?
Yes. Immediately following completion of the RFP process in December
2000, A vista announced that CS2 was the preferred resource option. The following excerpts
from Avista s news release, dated December 12 2000, reflect the Company s announcement
of the results of the RFP and the selection of CS2 as a utility resource.
A vista Utilities, today announced the selection of the Coyote Springs 2 site
near Boardman, Ore., as the preferred supply-side resource option and three
demand-side management bids to meet the utility s growing resource needs.
These selections which total about 300 megawatts come from a comparison of
company projects and a pool of 32 proposals solicited through a formal
Request for Proposal (RFP) issued late August.
Under the terms of the project agreements, ownership of Coyote Springs 2 will
be transferred at cost to A vista Utilities from A vista Corp. subsidiary A vista
Lafferty, Di-Reb
Avista Corporation
Power LLC, which acquired Coyote Springs 2 in July from Enron North
America and Portland General Electric.
The Company chose to keep ownership of the plant within the Coyote Springs 2, LLC
until construction was completed. The reasons for keeping the plant within the Coyote
Springs 2, LLC were at least twofold: 1) It is often beneficial to form LLCs to separate costs
and liabilities during the construction of a project. This provides liability protection in the
event of a catastrophic incident occurring during construction. 2) A vista had planned to
obtain separate construction financing for CS2. However, the Company was unable to secure
separate financing due to the difficult financial circumstances facing the Company at that
time.
It is important to note that the oversight of construction for CS2 was provided by
Avista Utilities ' personnel from the very beginning of the project. Avista Utilities' Tim
Carlberg was selected as Project Manager of CS2 in December 2000, immediately following
the selection of CS2 in the RFP process. Construction of the CS2 project began in January
2001.CS2 was transferred to Avista Utilities in January 2003, after construction was
substantially complete. The project began commercial operation for the utility in July 2003.
With regard to Dr. Peseau s testimony concerning the sale of one-half of CS2 to
Mirant in December 2001 , as I explained in my direct testimony, the sale was driven by the
very difficult financial circumstances faced by the Company at the time. The Company
increased debt costs and need for liquidity were caused by the unfortunate combination of
record low streamflow conditions and the unprecedented high wholesale electric and natural
gas market prices, which caused significant increases in power and natural gas costs. The
Company s financial circumstances were compounded by the need to finance the construction
Lafferty, Di-Reb
A vista Corporation
of CS2 at the same time. A vista sold one-half of the CS2 project to relieve some of the
financial strain.
Do you agree with Dr. Peseau s suggestion that the maximum amount of
capital that should be allowed into rate base for CS2 is $84,560,000, based on the cost
for a Surrogate Avoided Resource (SAR) from the 2002 Avoided Cost proceedings?
No. This suggestion presupposes that Avista s RFP was not a legitimate
process for acquiring resources at a fair cost. The RFP was conducted during the second half
of the year 2000 and CS2 was selected as the least cost resource in December 2000. In 2000
the market fundamentals reflected that the region was short of resources, which was reflected
in the price of all resources evaluated at that time.
The Avoided Cost proceedings referenced by Dr. Peseau occurred in 2002 when the
market fundamentals had substantially shifted, the region was in a surplus condition, and
market electricity prices were lower. It would not be appropriate now, after the fact, to apply
a different cost standard to CS2.
Lafferty, Di-Reb
A vista Corporation
III. NATURAL GAS PURCHASES - RESPONSE TO DR. PESEAU
Before you respond to Dr. Peseau s testimony regarding the Deal A and
Deal B natural gas purchases, would you please briefly summarize these transactions?
Yes. The following chart illustrates the natural gas transactions that are at
issue in this case. These purchases were made by Avista in the first half of 2001 to provide
fuel for its natural gas-fired thermal generation.
60,000
50,000
:c 40,000
III
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:Q 5 30,000
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~ 20 000
10,000
Natural Gas Purchase & Hedge Transactions
9 9 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 9 9 9 9 9 9 9
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c. "ZO-'LL:;oOt:;oOt(/)O ~ .~;~:i~:;:;OZO-'LL:;~:i~:;:;o
Physical Natural Gas Purchases
The two shaded areas of the chart reflect purchases of physical natural gas at index
prices for two different time periods. On March 13 , 2001 Avista purchased 27 658 dth/day
for the period November 1 , 2001 through October 31 2004 (36 months). On March 22 2001
Avista purchased 20 000 dth/day for the period June 1 2002 through October 31 2003 (17
Lafferty, Di-Reb
A vista Corporation
months). Prices for both purchases were based on the monthly index price published by
Natural Gas Intelligence at Malin (NGI Monthly Malin Index).
Although these purchases provided A vista with firm delivery of natural gas to run its
gas-fired thermal resources for these time periods, it is important to recognize that these
purchases did not limit in any way the cost of power from the generating projects. The
Company and its customers were still exposed to the volatility of natural gas market prices
during the term of the purchases. Through the financial hedge transactions explained below
the Company fixed the price on the physical natural gas purchases in order to limit exposure
to higher prices and provide a measure of price stability for customers.
Fixed Price Financial Hedge Transactions (Deals A and B)
The solid lines on the chart above reflect the volume of natural gas for which the
Company fixed the price. A vista fixed the price through four different financial swaps as
shown in the table below.
Natural Gas Hedge Transactions
Deal A 04/11/2001 10,000 11/01/2001-10/31/2004 $6.7525
05/02/2001 000 11/01/2001-10/31/2004 $5.9500
Deal B 04/10/2001 000 06/01/2002-10/31/2003 $6.5000
05/10/2001 000 06/01/2002-10/31/2003 $5.3500
The combination of the physical gas purchases and financial hedge transactions
resulted in a firm supply of power (from gas-fired generation) at a fixed price. Based on the
CS2 heat rate, the cost of power from these Deal A and Deal B transactions was in the range
of $38 to $48 per MWh. As will be discussed later, these prices compared very favorably to
forward electric prices at the time.
Lafferty, Di-Reb
A vista Corporation
Beginning on page 16 of his testimony, Dr. Peseau provides testimony
regarding the "distinction" between physical transactions and financial transactions.
Do you have any comments on this testimony?
Yes. On page 21 , line 3 of his testimony Dr. Peseau states the following:
However, I am quite surprised that the Company testimony in this regard
suggests that somehow Deal A and Deal B in any way assisted in covering a
resource-short position. (underscore added)
In addition, on page 21 , beginning on line 19 he provides the following testimony:
The company on March 13 and March 22 2001, entered into 36 month and 17
month physical trades for 27,658 and 20 000 decatherms per day at market
index-based prices. These two gas contracts alone filled the need to cover the
resource deficits discussed by the Company.(underscore added)
The "two gas contracts" that Dr. Peseau refers to above are the physical purchases
natural gas made by the Company at monthly index prices, whereas the "Deal A and Deal B"
transactions that he refers to are the financial hedge transactions that fixed the price of the
physical purchases. In his testimony, Dr. Peseau is suggesting that the physical purchases
were sufficient to cover Avista s resource deficiencies, and the financial hedges were not
necessary. We strongly disagree.
Please explain.
The Company s Energy Resources Risk Policy, dated November 9, 2000
under subsection b of Section E, states as follows:
Resources or loads priced based on index values are considered to be open
positions for the purpose of measuring financial risk. Generating plants may
be included as resources to cover open power positions only to the extent that
fuel has been purchased (other than at index prices)and the plant is available
for operation. (underscores added)
Lafferty, Di-R~b
A vista Corporation
In accordance with the Risk Policy, only fixed-price power purchases or power
generated with fixed-price fuel is netted against load obligations in the Company s Position
Reports. While it is true that the physical purchases of natural gas provided the ability to
generate a firm supply of power from thermal generation, Deal A and Deal B fixed the price
for the generation, therefore reducing the open financial positions. Without the financial
hedges the Company and its customers were still exposed to volatile natural gas market
prices, because the pricing for the physical supply was based on market index prices.
Fixing the price on the natural gas through Deal A and Deal B was consistent with
Avista s prior purchasing practices of acquiring medium-term and long-term firm resources
at fixed prices to serve its electric retail customers. I will discuss this in more detail later.
Beginning on page 24, line 16 of his testimony, Dr. Peseau discusses a
resource portfolio that includes short, medium, and long-term resources. Do you have
any comments on this testimony?
Yes. Beginning on page 24, line 17, Dr. Peseau testifies as follows:
I certainly agree with him (Mr. Lafferty) that any resource portfolio should
have various short, medium, and long-term resources. In this light, I do not
challenge or take issue with Avista s entering into its March 13 and March 22
long-term physical gas purchase contracts, as I previously noted.
Dr. Peseau has underscored the word "physical " apparently to emphasis his belief
that by purchasing the physical natural gas for thermal generation, it covered the open
positions carried by the Company. As I explained above, however, the purchase of the
physical natural gas, standing alone, did nothing to protect customers from the impacts of
short-term wholesale market prices. Because the physical gas was priced based on the NGI
Monthly Malin Index, the price would float each month based on the short-term wholesale
Lafferty, Di-Reb
A vista Corporation
market price. As stated earlier, Deal A and Deal B fixed the price for the thermal generation
therefore reducing the open financial positions.
One of the primary purposes in developing a resource portfolio is to provide for
diversity of pricing to provide a level of price stability for customers. It is important to note
that a resource portfolio could easily be developed to include short-term contracts, medium-
term contracts and long-term contracts, but with all of the pricing based on the same short-
term index price. From a cost perspective, which is what ultimately counts for customers
such a portfolio would not be much of a portfolio at all, since the pricing for all of the
components would be based on the same short-term market price. California experienced
this in 2000 and 2001. Through its restructuring initiatives it required utilities to sell their
generating resources and purchase power at short-term market prices. In fact the utilities
were precluded from entering into longer-term fixed-price transactions.
On page 28 of his testimony, Dr. Peseau made reference to "A vista
normal hedge strategies." Do you have any comments on this testimony?
Yes. Dr. Peseau s testimony refers to the Company s hedging practices for its
retail natural gas business. It is very important that the purchasing practices and hedging
strategies for the natural gas distribution business not be confused with the purchasing
practices and strategies of the vertically integrated electric utility.
In acquiring natural gas to serve its retail natural gas customers, the Company
purchases natural gas in advance at first-of-the-month (FOM) index prices to cover its
expected load requirements. As an additional step, the Company enters into financial hedge
transactions to fix the price on a portion of the natural gas in order to limit exposure to higher
Lafferty, Di-Reb
A vista Corporation
prices and provide a level of price stability for customers. Some of the financial hedges
stretch out for over a year in advance, while other hedges are made for the upcoming winter
heating season. Deals A and B were designed to accomplish the same thing, i., close the
open financial positions, limit customers' exposure to higher prices , and provide a level of
price stability.
A vista does not own natural gas production fields or primary pipelines related to it
retail natural gas business. A vista purchases all of its supply from the marketplace. Over
time A vista has developed its natural gas purchasing practices and hedging strategies in
consultation with the Commission Staffs in Idaho, Washington, and Oregon, both through
informal communications, through the natural gas IRP process and through the current
Benchmark Mechanism. In prior years, a much lower percentage of the natural gas volumes
was hedged. However, in more recent years there has been movement toward hedging a
greater percentage of the volumes due to the increased volatility and level of natural gas
pnces.
With regard to the vertically integrated electric utility, A vista operates and continues
to develop a diversified portfolio of electric resources to serve its retail electric customers.
As Mr. Storro explained in his pre-filed direct testimony, Avista s resource portfolio includes
generation from hydroelectric, coal, wood-waste, natural gas, and wind resources.
addition, the portfolio has regularly included purchases of power on a long-term, medium-
term and short-term basis. These long-term, medium-term and short-term purchases are
generally made at fixed prices
Lafferty, Di-Reb
Avista Corporation
It is worth noting that prior to the acquisition of CS2, the Company s gas-fIred
generating plants were all peaking units. The heat rates of the Rathdrum and Northeast units
are high as compared to a resource like CS2 that has a heat rate of approximately 7 000
BTU/KWh. The ownership of CS2, a base-load gas-fired project, brings with it a greater
need to enter into hedge transactions to cover the open financial positions.
On page 17, line 15 of his testimony, Dr. Peseau suggests that the Deal A
and Deal B transactions are of "unprecedented length." Do you agree?
No. The natural gas transactions at issue were designed to provide a firm
supply of power to A vista s electric retail customers at fixed prices. As I explained earlier
historically A vista has regularly entered into medium-term fixed-price transactions, of two to
five years, in developing its portfolio of resources to serve its electric customers. For
example, in 1997 Avista entered into a purchase of 50 aMW from ESI for the period July 1
1997 through June 30, 2001 at a fixed price of$14.65 per MWh. In 1997 Avista entered into
a purchase of 25 MW on-peak for the period January 1 , 1999 through December 31 , 2001 at a
fixed price of $17.25 per MWh.
More recently, the Company entered into transactions for 100 aMW of firm power at
fixed prices for the period January 1 , 2004 through December 31 , 2006 at an average price of
$29.88 per MWh. And an additional 100 aMW of firm power at fixed prices for the period
January 1 , 2007 through December 31 , 2010 at an average price of $31.68 per MWh.
There are at least a couple of points worth noting related to these contracts. First
these transactions were entered into for multiple years to provide a firm supply of power to
our electric customers at a fixed price, which is precisely what was accomplished through the
Lafferty, Di-Reb
A vista Corporation
natural gas transactions at issue in this case. Secondly, when these types of transactions are
viewed after-the-fact, the pricing for some of them will "turn out to be" favorable, while
others will be unfavorable. That is the reality of hedging or locking in the price of resources
for future periods. The alternative to locking in future prices is to carry large open positions
which would expose the Company and its customers to the impacts of potentially volatile
wholesale market prices.
The medium-term transactions noted above, when viewed with hindsight, were very
favorable.Current market prices are well above the fixed prices for the 2004-2006
transactions, and Avista s customers are currently receiving the benefit from these fixed-price
medium-term transactions.The hindsight approach to proposing a disallowance of
unfavorable transactions while accepting the favorable transactions is not reasonable
balanced, or appropriate.
On page 17, line 15 of his testimony, Dr. Peseau makes reference to a loss
on a system basis of over $62 million related to the Deal A and B transactions. Should
the Commission be persuaded by this figure?
No. First, as described above, it is not appropriate to use an after-the-fact
analysis of transactions in the determination of the prudence or recoverability of the costs.
The Commission has consistently held that the prudence of costs should be determined based
on the information available at the time the decision was made.
Second, if an after-the-fact analysis of transactions were to be considered in any way
in the determination of the prudence or recoverability of costs in this case, it is imperative
that the analysis not be limited to just the few transactions selected by Dr. Peseau. There are
Lafferty, Di-Reb
A vista Corporation
many other transactions that the Company has entered into, which when viewed with
hindsight, are very favorable for customers. For example, a hindsight analysis of Avista
purchase of 200 MW for the period July 2000 through December 2003 shows that it was over
$236 million less expensive than purchasing at index prices. In addition, based on current
market conditions the 100 aMW of more recent purchases described above for the period
2004 through 2010 will provide customers with over $46 million of benefits. Therefore, the
$62 million highlighted by Dr. Peseau is small when compared to the benefits to customers of
other recent and ongoing medium-term fixed-price transactions.
The Company is not proposing that the Commission use an after-the- fact analysis in
its decision-making regarding the prudence or recoverability of costs, but has presented the
information in response to the after-the-fact approach used by Dr. Peseau in order to provide
a more balanced view of the overall transactions entered into by the Company.
Beginning on page 17 of his testimony, Dr. Peseau speculates as to the
roles and responsibilities of Avista Utilities and Avista Energy in the Deal B hedge
transactions, as well as the reasons why A vista Utilities entered into the hedges. Do you
have any comments on this testimony?
Yes. As I explained in my pre-filed direct testimony and earlier in this
testimony, the reason A vista Utilities entered into the transactions was to cover open
financial positions, limit exposure to higher prices, and achieve some price stability for that
portion of its electric resource portfolio. Avista Utilities was not "betting" or speculating on
the future movement of market prices for natural gas or electric power.
Lafferty, Di-Reb
A vista Corporation
The Deal B hedge transactions were purchased to start in June 2002, when CS2 was
expected to become commercial. As such, the Deal B hedge transactions needed to cover a
non-standard term (17 months starting in June). Avista Utilities requested that Avista Energy
enter into the hedge transactions due to the non-standard term. Also, there were limited
counterparties willing to transact with A vista Utilities. The documentation provided in this
case shows that the fixed prices for the hedge transactions properly reflected the market price
of natural gas at the time the transactions occurred.
On page 26 of his testimony, Dr. Peseau suggests that the forward price
curves at the time Deal A and Deal B occurred may not be a good indication of what an
arms-length buyer and seller might agree upon for financial hedges. Do you agree with
Dr. Peseau?
No. Forward market prices for both electricity and natural gas are based on
actual forward transactions and actual price bids and price offers by counterparties in the
marketplace. These forward market prices are commonly used in the electric and natural gas
industry to establish prices for, among other things, medium-term transactions, financial
hedge transactions, and to mark-to-market electric and natural gas portfolios for accounting
purposes.
A vista Utilities is a price-taker in the market and pays prices equivalent to the forward
prices offered by the marketplace. Therefore, the forward market price information provided
in my pre-filed direct testimony is a reasonable and valid comparison for judging the
prudence of the hedge transactions at that time.
Lafferty, Di-Reb
A vista Corporation
Q. On page 22 of his testimony, Dr. Peseau seems to imply that a comparison
the cost to generate power at CS2 with the cost to purchase electric power from the
market is somehow improper. Do you have any comments on this testimony?
Yes. The comparison between the cost to generate with fixed-price fuel and
the cost to purchase electric power in the market is an appropriate comparison continually
made by load serving utilities in the determination of least-cost resources to serve load, and
in the economic dispatch of natural gas-fired generating plants. The comparison made by
Avista was appropriate and proper.
The chart below provides a comparison of the cost to generate power with the Deal A
and Deal B natural gas versus the forward price of electricity at the time. As shown in the
chart, the Deal A and Deal B transactions were clearly a lower cost resource for A vista.
FolWard Electric Prices vs. Cost to Generate at Fixed Natural Gas Prices
350,
300,
250,
200,
.:::::;;;;;
150,
Range of CS2 Cost to Generate
With Deal A & B Fixed Price Gas
100,
50,
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~,~~~#~ #~~~~~,~~~#~ #~~~#~,~~~#~ #~~~
--4/10/2001 --411112001 ~5/212001 ---5/10/2001
Lafferty, Di-Reb
A vista Corporation
On page 22 of his testimony, Dr. Peseau makes reference to an
arbitrage" trade. Do you have any comments on this testimony?
Yes. An assessment of what a power trader might do with an open position to
lock in a profit is not appropriate. A power trader does not face the same circumstances as a
utility such as A vista that has an obligation to serve variable loads. If A vista had sold power
when it hedged the price of natural gas, it would have re-created a short financial and
physical net position, and the Company would have been exposed again to potentially high
and volatile prices in the energy market.
On page 18, line 11 of his testimony, Dr. Peseau makes comments
regarding information on future market prices that mayor may not have been available
at the time Deal B was entered into, and then on page 27, line 15 he suggests that Avista
Energy received substantial benefits from the Deal B transactions. Do you have any
comments on this testimony?
Yes. In his testimony, Dr. Peseau is speculating not only on what Avista
Energy mayor may not have known about future market prices, but also about the status of
Avista Energy s contract portfolio and open positions. Because Avista Energy is not a load-
serving utility, the forward positions that it takes in the market are generally made not only to
capitalize on the movement of prices over time in the same location, but also the movement
in the relationship of prices between locations (location spread), and the change in prices over
time between commodities (e., electricity versus natural gas), among others. At any point
in time A vista Energy will be in a net short or net long position in the market. The net short
or long position is the result of an accumulation of transactions that have been entered into
Lafferty, Di-Reb
A vista Corporation
over time. For any forward month Avista Energy may enter into additional transactions to
reverse a position for a variety of reasons.
A "location spread" is a good example of a transaction where a trading company, such
as A vista Energy, may not care whether the future market prices move up or down. If
positions have been taken related to the difference in prices between locations (location
spread), the controlling factor is the difference in the prices between the two locations, not
whether the overall prices move up or down. Therefore, one would need to be careful when
making assumptions about why certain positions were taken by a trading company, and
drawing conclusions regarding the profitability of isolated transactions.
On page 27, line 15 of Dr. Peseau s testimony he suggests that Avista Energy profited
from Deal B by over $18 million. In reaching this conclusion, however, one would have to
assume that Avista Energy held onto the monthly index-price open positions created by the
Deal B transactions during the entire 17-month term. In other words, Avista Energy would
have needed to hold "short" positions (at index prices) equal to Deal B volumes during the
entire 17 months in order to capture the difference between the Deal B fixed prices and the
monthly index prices. In the absence of short positions at Malin, A vista Energy would not
have been able to take advantage of declining prices during the 17 -month term of the Deal B
transactions. In reviewing the open positions of Avista Energy, we know with certainty that
Avista Energy did not carry "short" open positions at Malin for the majority of the months of
the Deal B term. Therefore, it clearly cannot be assumed that A vista Energy profited by $18
million from the Deal B transactions.
Lafferty, Di-Reb
A vista Corporation
IV. NATURAL GAS PURCHASES - RESPONSE TO MR. HESSING
Beginning on page 17, line 14, of his testimony, Mr. Hessing suggests that
the Company created a speculative long position through the Deal B hedge transactions.
Do you agree?
No. A vista evaluates its load and resource positions and need for resources on
both a long-term and short-term basis. For long-term planning the Company uses the
Integrated Resource Planning (IRP) process, which has guidelines or criteria related to the
resource positions (surpluses/deficiencies) to be targeted by the Company. For short-term
planning and operating purposes the Company operates under a Risk Policy, which includes
guidelines for resource positions for the near-term 18-month period. A review of both the
long-term criteria and the short-term criteria shows that the Deal B transactions did not place
the Company outside of its guidelines, and did not create a speculative position.
Please show how Deal B fits within the long-term planning criteria.
Historically, A vista has planned for resource acquisitions to meet its long-term
load obligations on a critical water planning basis. Critical water was the basis for prior year
Integrated Resource Plans and resource acquisition processes (e., RFP) developed by the
Company. The difference in hydroelectric generation between critical and average water
conditions is approximately 150 aMW. Therefore, as a guideline for long-term planning
purposes, in order to cover all load obligations under critical water conditions, it would
require an additional 150 aMW of resources. This would translate into a surplus under
average water conditions of approximately 150 aMW. For comparison purposes, in 2001
Lafferty, Di-Reb
A vista Corporation
A vista experienced record low streamflow conditions resulting in hydroelectric generation of
181 aMW below average.
Also, at the time the Company entered into Deal B it had also developed addi!ional
criteria to use as a guide in its resource acquisition decisions. The Company conducted a
statistical analysis of the variability of loads and hydroelectric generation, at a 90%
confidence interval, to determine the resources that would be required to cover this
variability. I discussed this in more detail in my pre-filed direct testimony, and I will refer to
it here as "Confidence Interval" planning. The results of the statistical analysis showed that it
would require 170 aMW of additional resources to cover the load and hydroelectric resource
variability. This is slightly higher than the 150 aMW under critical water planning, but not
too dissimilar.
The following chart! illustrates Avista s monthly forward positions as of March 30
2001 under the long-term confidence interval planning criteria. The chart reflects Avista
resource positions just prior to entering into the Deal A and B transactions. As can be seen in
the chart, the Company had resource deficiencies during all months of the Deal A and Deal B
periods.
I This chart was included in Exhibit No., Schedule No. 26 of Mr. Lafferty's pre-filed direct testimony.
Lafferty, Di-Reb
A vista Corporation
Load & Resource Position Summary - Excludinq Un-Hedqed Natural Gas-Fired Generation
90% Confidence Interval (Load & Hydro Variability)
As of 3/30/01
ro w m ro ~
-,
u.
::; " ::; -,~ ~ ~ ~
:11 ~
How does the chart change when you add the Deal A and Deal B
transactions?
Adding the generation related to the Deal A and Deal B transactions results in
the positions shown in the chart below.2 Although there are some surpluses during the spring
run-off months of the Deal B period the average position during the Deal B period from June
2002 - October 2003 is a deficiency of six average megawatts. Therefore Deals A and B
both fall within the long-term planning criteria, and did not create a speculative long position
as suggested by Mr. Hessing.
2 This chart was included in Exhibit No., Schedule No. 26 of Mr. Lafferty's pre-filed direct testimony.
Lafferty, Di-Reb
A vista Corporation
Load & Resource Position Summary -lncludlnQ HedQed Gas-Fired Generation
90% Confidence Interval (Load & Hydro Variability)
Including Deals A & B Fixed Price Fueled Turbines, as of 3/30/01
600
500 ~
400 -
300 Deals A & B Positions
1/02-12-02: (84) aMW
1/03-12/03: (10) aMW
1/04-10/04: (310) aMW200
400
500
600
'i'
~ ~ ~ ~ ~ ~
~ ~ ~ N'i''i'S S S M'i'S S S S S S M'i'S ~'i'
~ ~ ~ ~ ~ ~ ~ ~ ~
'i'
'/'
o!o
' ',/,' "-'-
o!o ffi -i:ffi
-'-~ ~ ~ ~ ~ ~ ' ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ 0 ~ c , ~ ~ ~ ~ ~
~ ~ ~
For Avista s near-term planning under the Risk Policy for an 18-month
period, were the Company s resource positions within the established guidelines when
the Company entered into Deal B?
Yes.The Deal B transactions were completed in May 2001. The 18-month
planning period under the Risk Policy at that time would have run from June 2001 through
November 2002. The Risk Policy limits quarterly surpluses to 150 aMW, as Mr. Hessing
noted on page 9, line 23 of his testimony. The Company s resource positions for each quarter
of2002, including both Deals A and B, are provided in the table below.
Quarter
Lafferty, Di-Reb
A vista Corporation
During each of the quarters the Company is within its policy guideline; i., within
150 aMW. Therefore, the Company s resource positions including Deals A and B were
within the established guidelines in the Risk Policy, and did not establish a "speculative
position that was beyond the guidelines.
On page 16, lines 3-4 of his testimony, Mr. Hessing states that "it is Staff's
position that the Company violated both the intent and the written requirements of its
own Energy Resources Risk Policy" with regard to Deal B. Do you agree?
No. The Company operated within the requirements of its Energy Resources
Risk Policy and does not agree with Staffs conclusion. As stated in Witness Storro s pre-
filed direct testimony, the purpose of the Energy Resources Risk Policy is to provide
guidance with regard to the management of the Company s risk exposure as it relates to
energy resources.
In Section B of the Risk Policy there are statements illustrating the intended operation
of the Risk Policy. The following is an excerpt from Section B of the Risk Policy:
This Policy is intended to focus on short-term power and natural gas supply
management, meaning the period of eighteen months forward from any
current date, as they relate to meeting near-term energy load obligations. The
longer-term energy risks are expected to be addressed through other means
including the Integrated Resource Planning (IRP) process, capital budgeting
and financial planning, load forecasting and econometric models, and
generating facility planning. There is not a clear line between the short-term
focus of this Policy and long-term energy management. Therefore, decisions
and analyses must stretch across arbitrary time boundaries to afford prudent
decisions. The short-term horizon in this Policy provides for visibility in the
most volatile forward periods, including daily position reporting and
transaction authority, but is not intended to be a sufficient tool to manage all
energy risk for long-term business requirements.
Lafferty, Di-Reb
Avista Corporation
The Risk Policy makes it clear that it is an operating tool to guide and manage the
Company s acquisition and sale of energy resources in the short term.However, it
specifically recognizes that there are other tools that guide longer-term resource decisions.
The Risk Policy acknowledges that longer-term decisions will cross the 18-month time
boundary. In the case of the Deal A and Deal B natural gas hedges, the Company took
reasonable medium-term resource acquisition steps and managed its load and resource
positions, exercising management's financial risk judgment, consistent with the intent and
design of the Risk Policy and with the Company s long-term planning criteria.
Beginning on page 17, line 14, of his testimony, Mr. Hessing suggests that
the Company should have sold the electric generation related to Deals A and B, and he
states that "Absent such an electric power sale, the transaction was purely speculation.
Do you agree with this testimony?
No. As I explained above, the Company s resource positions including Deals
and B, under both the long-term and short-term planning criteria, were within the
established guidelines.And the Deal A and Deal B transactions did not establish a
speculative" position that was beyond the guidelines.
Furthermore, if the Company had made an electric sale of the generated power from
Deals A and B, it would have just re-created the short open positions that it had prior to
entering into Deals A and B.Recreating the short positions would have exposed the
Company and its customers to the high and volatile prices that were then present in the
electric power market.
Lafferty, Di-Reb
A vista Corporation
Therefore, it would not have been appropriate for the Company to sell the power it
had just acquired to cover its short positions.
On page 7, line 18 of his testimony, Mr. Hessing expresses concern
regarding the risks associated with the "length of these gas purchase deals for its
(Avista s) electric customers." Do you have any comments on this testimony?
Yes. As I explained earlier in response to Dr. Peseau, the medium-term
natural gas transactions were designed to provide a firm supply of power to Avista s electric
retail customers at fixed prices. Historically, Avista has regularly entered into medium-term
fixed-price transactions of two to five years in developing its portfolio of resources to serve
its electric customers. Many of these transactions have yielded substantial cost savings for
customers, as explained earlier, and the length of the term is consistent with prior purchasing
practices for Avista s electric portfolio.
On page 16 of his testimony Mr. Hessing expresses concern that the use
Avista Energy as a counterparty created a "potential conflict of interest." Do you have
any comments on this testimony?
Yes. The Company recognizes that the use a subsidiary company such as
Avista Energy as a counterparty may subject the transactions to a higher level of scrutiny.
A vista believes that a careful review of these transactions is reasonable and appropriate. To
that end, A vista was thorough in the filing of its direct case in providing information related
to the Deal A and Deal B transactions, and has been very responsive to discovery questions
related to these transactions in an effort to provide the information necessary for a thorough
revIew.
Lafferty, Di-Reb
A vista Corporation
As explained earlier, Avista Utilities sought out Avista Energy to enter into the Deal
B transactions due to the non-standard term and limited counterparties willing to do the
hedges. A vista Utilities evaluated those transactions in the same manner as the transactions
with non-affiliated parties, as discussed in my pre-filed direct testimony. If the prices seem
high, based on today s look-back at the transactions, it is not because the transactions were
with an affiliated company, it is because the market prices were high at the time A vista
Utilities locked in the prices. The level of the prices had nothing to do with Avista Energy
being an affiliated company.
The information provided by A vista Utilities in this case includes supporting
documentation of the forward price of natural gas at the time the Deal B transactions were
completed. The documentation shows that the Deal B prices reflected the appropriate market
prices at the time.
With regard to Mr. Hessing s reference to "lower of cost or market " the cost of the
Deal B financial hedge transactions reflects the cost of natural gas at the time A vista Utilities
chose to lock in prices. The cost of the transactions was the market.The utility determined
that it was necessary to lock in the prices for a 17 -month period, knew what the cost was, and
at that time found the cost to be reasonable and appropriate.
On page 19 of his testimony, Mr. Hessing recommends that $6,496 669 be
removed from the PCA balance related to the Deal B hedge transactions. Do you agree
with Staff's recommendation?
No. The amount of $6,496 669 associated with the Deal B transactions should
not be removed from the PCA balance. The Deal B transactions were entered into to cover
Lafferty, Di-Reb
Avista Corporation
the Company s open financial positions. The Company believes that it was appropriate to
hedge that portion of its natural gas portfolio as part of meeting load obligations given the
high electric power prices present in the market at the time. The Deal B transactions were
not "speculative." It would not have been appropriate to make a sale of the power generated
from that natural gas because it would have re-created a short position for the Company. The
Company s resource positions, including the Deal A and Deal B transactions, were within the
guidelines established by its long-term planning criteria, and the shorter-term 18-month
criteria under the Risk Policy. It was reasonable for the Company to lock in the cost
natural gas for electric generation at a price well below the market price of electricity to
mitigate financial risk in a manner consistent with its planning criteria.
If the Commission was to determine that a portion of the Deal B
transactions should be disallowed, what is the maximum amount that should be
considered?
Mr. Hessing recommends that $6 496 669 be disallowed for Deal B. The
figure of $6 496 669 was calculated by multiplying the volume of natural gas in Deal B by
the difference between the Deal B hedge price and the average selling price in each month of
June 2002 through October 2003. Mr. Hessing s methodology appropriately excludes the gas
that was used to generate electricity to serve retail load.
Another approach to calculating the losses on Deal B gas is to look at the amount that
put the Company in monthly long positions greater than 150 aMW. The loss on the sale of
Deal B gas would be determined by only looking at gas sales that put the Company beyond
that limit. Calculating the losses on the sale of Deal B based on this methodology would
Lafferty, Di-Reb
Avista Corporation
result in a disallowance of $2 748 609 (Idaho allocation, 90% customer share). A spreadsheet
showing that calculation is contained in Exhibit No. 24.
Another method to determine a disallowance related to Deal B is to include the loss
on Deal B gas sales only when those sales were made with no corresponding electricity
purchase. In many cases the Company purchased an equivalent amount of electricity when
gas was sold, which was ultimately used to serve retail load. In these cases, the Company
sold gas because it was more economical to purchase electricity than utilize natural gas-fired
generation. These occasions, where gas was sold electricity was purchased, resulted in lower
total power supply expenses, even though there was a loss on the sale of the gas. Excluding
the loss on gas sales where there is a corresponding electricity purchase is similar to Mr.
Hessing s methodology in that it does not include the loss on energy that was ultimately used
to serve retail load.
Counting the loss on Deal B gas that was sold without the purchase of replacement
electricity results in a disallowance of $3 995 846 (Idaho allocation, 90% customer share).
The spreadsheet showing the calculation of this number is contained in Exhibit No. 25.
Lafferty, Di-Reb
Avista Corporation
V. BOULDER PARK - RESPONSE TO MR. STERLING
Beginning at page 35 of his testimony, Mr. Sterling indicates that Staff
recommends a 10% disallowance of Boulder Park costs. Do you agree with Staff's
recommendation?
No. Given the circumstances, generally stemming from the fast track design-
build approach that the Company chose in order to bring small generation on line as quickly
as possible, the Boulder Park project costs were managed reasonably by the Company.
On page 33 of his testimony, Mr. Sterling expresses concern that the project was not
completed on the planned fast-track schedule. By the summer of 2001 the Western energy
crisis began to subside, but A vista continued to face serious financial difficulties. With
power available at significantly lower wholesale market prices, the Company chose to slow
down the construction schedule on Boulder Park to preserve cash.While the earlier
circumstances justified a fast-track construction schedule, the change in circumstances
supported a change in the schedule.
Although Mr. Sterling references costs associated with other similar projects, he also
notes on page 36 that "cost information for these types of engines is somewhat difficult to
obtain because there are few utilities or public entities that have recently installed these types
of units." We believe it is important to use great care in the use of general estimates of plant
costs for comparisons due to the many factors that may cause the costs of one project to be
different than another; such as emission control issues, sound abatement, and project-specific
configurations related to the plant's location. While Mr. Sterling does not question the
Lafferty, Di-Reb
A vista Corporation
choice of Boulder Park as a resource, it was, nevertheless, somewhat unique, and therefore
created unanticipated challenges during construction.
Does that conclude your rebuttal testimony?
Yes it does.
Lafferty, Di-Reb
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY AND GOVERNMENTAL AFFAIRS
A VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATEOF IDAHO
CASE NO. A VU-04-
REBUTTAL
EXHIBIT NO. 24
ROBERT J. LAFFERTY
FOR A VISTA CORPORTATION
(ELECTRIC ONLY)
Avista Corp.
Calculation of Loss on Deal B Gas Sales
Average Length Deal B Sale Deal B
Date Position 1 Above 150 Above 150 Price Loss
(aMW)(aMW) (GWh)(dth/day)($/dth)
($)
Jun-354 204 147 20,000 017 791
Jul-304 154 114 000 977 984
Aug-2.45
Sep-
Oct-
Nov-115
Dec-177 4,461 296 086
Jan-
Feb-179 795 240,454
Mar-255 105 17,476 4.42 850,493
Apr-173 794 215,359
May-333 183 136 20,000 1,410,466
Jun-427 277 199 000 229 500
Jul-329 179 133 20,000 4.43 966,236
Aug-
Sep-4.48
Oct-
Total Loss 204 370
Allocated Loss 748,609
1) System position including all fixed-price resources.
2) Length in position beyond Risk Policy 150 aMW quarterly long position limit.
3) Deal B natural gas purchases contributing to positions beyond 150 aMW.
4) Actual average monthly sale prices of Deal B natural gas.
5) Effective loss of Deal B sales given average purchase price of $5.985/dth.
6) Sum of Deal B losses.
7) Sum of Deal B losses adjusted for Idaho (33.18%) and PCA (90%) allocations.
Exhibit No. 24
Avista, Lafferty, Rebuttal
Case No. AVU-O4-
Page 1 of 1
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY AND GOVERNMENTAL AFFAIRS
A VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MA TIER OF THE APPLICATION )
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATE OF IDAHO
CASE NO. A VU-04-
REBUITAL
EXHIBIT NO. 25
ROBERT J. LAFFERTY
FOR A VISTA CORPORTATION
(ELECTRIC ONLY)
Avlsta Corp.
Summary of Savings Obtained by Selling Fixed Priced Gas, Jul2002 - Oct 2003
Loss on Deal B Gas Sales
Line Transaction Deal Delivery
!:!Q.llc\(et Months Volume Power Purchases Related to Sale of Gas
(dthldoy)($Idth)
Jan-G0270 Jul 10,000 $2,No purchases made related to sale of gas due to position length
3-Apr-Q2 G0366 Jul 000 $3,No purchases made related to sale of gas due to position length
4-Apr-02 G0370 Nov-Oct 03 000 $3,No purchases made related to sale of gas due to position length
5-Apr-Q2 G0372 Nov-Oct 03 000 $3,No purchases made related to sale of gas due to posilion length
1 8-Jul-G0515 Mar-Jun 000 $3,No purchases made related 10 sale of gas due to position length
19-Jul-02 G0516 Apr-Jun 000 $3,No purchases made related to sale of gas due to position length
30-Sep-02 G0655 May-Jun 10,000 $3,No purchases made related to sale of gas due to position length
9-Jan-03 G0823 Jun 000 $4,No purchases made relaled to sale of gas due to posllion length
10-Jan-Q3 G0827 Jun 000 $4,No purchases made related to sale of gas due 10 position length
5-Apr-G0373 & 374 Jul 15,000 $3,No purchases made related to sale Of gas due to position length
17-May-GO432 Jul-Oct 000 $3,25 aMW 0302 (j $39,75IMW DT 2190 & Ocl 02 (j $36,75/MW DT 2191
21-May-GO439 Aug-Oct 000 $3,25 alvW Aug 02 (j $39,50/1vW DT 2200, Sepl 02 (j $39,501MW DT 2196 &
Oct 02 (j $35,75IMW DT 2195
21-May-Q2 GO438 & 440 Nov 10,000 $3,50 alvW Nov 02 (j $35,83IMW DT 2194 & DT 2195 avg price
22-May-Q2 G0444 Sep-Oct 000 $3,25 alvW Sep 02 (j 37,95 DT 2202 & Oct 02 (j $35,90 DT 2194
23-May-G0446 Oct-Dee 000 $3,25 alvW 03 02 (j $38,00 DT2199
28-May-G0448 & 449 Oct 13,000 $3.75 alvW Oct 02 (j $35,OO/MW DT 2204, 2205 & 2211 avg price
5-Jun-Q2 GO464 Dee 000 $3,25 alvW 04 02 LL (I $30,501MW DT 2217
19-Jun-Q2 GO485 July 000 $2,No purchases made related to sale of gas due to posilion length
2O-Jun-G0488 Dee 000 $3,25 alvW Dee 02 Ll (j $34,OO/MW DT 2232
2O-Jun-GO489 Nov 12,000 $3,25 alvW Nov 02 flat (I $33,5O/MW DT 2231
15-Jul-GO5O9 Sep 22,000 $2,50 alvW Sep 02 (j $24,501MW DT 2246 & DT 2251 avg price
15-Jul-Q2 G0510&511 Aug 30,000 $2,125 aMW Aug 02 (I $21,22/MW DT 2247 2249,2250,2254.2255 avg pr
13-Aug-Q2 GO543 Sep 000 $2,No purchases made related 10 sale of gas due to posilion length
10-Sep-O2 G06O4 Oct 000 $2,25 alvW LL Oct 02 (j $27,75IMW DT 2267
17-Sep-02 G0624 Dee 11,000 $4,No purchases made related to sale Of gas due to position length
1-Oc1-Q2 G0660 Nov 000 $3,25 alvW Nov 02 (I $34,501MW DT 2276
1-Oct-Q2 G0661 Oct (3-31)000 $3,25 alvW Oct 02 (4-31) (I $29,25IMW DT 2276
2Q-Nov-Q2 G0741 Dee 500 $3,25 alvW HL Dee 02 (j $36,601MW DT 2293 & 25 aMW LL Dee 02 (j $31,
DT 2294
1 8-Jul-Q2 G0515 Mar-Jun 000 $3,No purchases made related to sale of gas due to position length
19-Jul-02 G0516 Apr-Jun 000 $3,No purchases made related to sale 01 gas due to position length
15-Aug-Q2 G0552 Jan 000 $3,No purchases made related to sale of gas due to position length
15-Aug-02 G0553 Feb 5,000 $3,No purchases made related to sale of gas due to position length
15-Aug-G0554 Mar 000 $3,No purchases made related to sale of gas due 10 position length
3Q-Sep-O2 G0655 May-Jun 10,000 $3,No purchases made relaled to sale of gas due to position length
3Q-Sep-02 G0656 May 10,000 $3,No purchases made relaled to sale of gas due 10 position length
10-Oct-Q2 G0680 Feb 000 $3,No purchases made relaled 10 sale of gas due to position length
1Q-OcI-Q2 G0681 & 82 Jan 22,000 $4,50 aMW Jan 03 (j $39,101MWh, DT 2279
20-Nov-02 G0743 Jan 000 $4,25 Ivw HLH Jan 03 (j $39,251MWh, DT 2295
23-Dec-O2 G0792 Feb 000 $4,75 Ivw HLH Feb 03 (I $41.251MWh, DT 2316 & 2317
23-Dee-Q2 G0793 Mar 000 $4,50 Ivw HLH Mar 03 (j $41,251MWh, DT2314 &2315
23-Dee-Q2 G0794 Apr 000 $4,2 - 25 Ivw HLH Apr 03 (j $39,00 & $39,501MWh, DT 2321 & 2323
31-Dee-Q2 G08O4 Feb-Apr 000 $4,25 MW HLH Mar & Apr 03 (j $41,251MWh, DT 2325
25 Ivw HLH Mar03 (j $42,251MWh, DT 2324
Jan-Q3 G0810 Feb 000 $4,75 Ivw HLH Feb 03 (j $41,251MWh, DT 2316 & 2317
Jan-G0814 Feb 000 $4,25 Ivw HLH Feb 03 (j $41.251MWh, DT 2318
25 Ivw LLH Feb 03 0 $36,OO/MWh, DT 2322
9-Jan-Q3 G0822 Mar 000 $4,No purchases made related to sale of gas due to position length
9-Jan-Q3 GO823 Jun 5,000 $4,No purchases made related to sale of gas due to position length
1O-Jan-O3 GO827 Jun 5,000 $4,No purchases made related to sale of gas due to position length
14-Jan-Q3 G0831 Feb 000 $4,25 Ivw HLH Feb 03 (j $42,OO/MWh, DT 2329
16-Jan-Q3 G0837 Mar 000 $5,25 Ivw HLH Mar 03 (j $45,OO/MWh, DT 2335
25-Feb-G0859 Apr 10,000 $4,50 Ivw HLH Apr03 (I $44,18/MWh, DT 2353 & 2355
7/1812002 G0515 Jul-Q3 000 39 No electric purchases made related to sale of gas due to position length,
3/20/2003 G0900 Aug 03 000 04 25 Ivw HL (j $54,00 ,DT 2365
312012003 G0901 Sep 03 000 97 25 Ivw HL (j $53,50, DT 2366
3120/2003 G0902 Oct 03 000 90 No electric purchases made related 10 sale of gas due to posilion length,
3/2412003 GO905 Jul03 000 92 No electric purchases made related to sale of gas due to position length,
312512003 GO907 & 908 Jul03 21,000 813 No electric purchases made related to sale of gas due 10 position length,
4110/2003 G0922 Aug 03 - Oct 03 500 98 25 Ivw HL Aug 03 (j $49,25, DT #2407
25 Ivw HL 03 03 (j $46,25, DT 2409
4116/2003 G0930 Aug 03 - Oct 03 000 265 25 Ivw HL Aug 03 (j $49,25,DT 2047
25 Ivw HL 03 03 (j $46,25, DT 2409
5/1412003 G0966 & 967 Aug 03 000 74525IvWHL(j$53,25,DT2412
25 Ivw LLH r03 (j $36,751MWh DT 2354
Total pow.r Supply Savln9. from Salling G..
Total Los. on All G.. 5.1..
Total Loss on De.1 B G.. S.I..
Ictaho Allocation (33.18%)
90% PCACu.tomer Portion of De.1 B Losse.
Total
Savings from Loss on
not Generatin Gas Sales
$84,308 174 900
$110927 $408,425
$1,629,216 $4,611 625
385,341 $4,868,375
$714288 $389,250
$565,174 $393,750
$521 647 $730,500
$237,165 $260,250
$137286 $257,250
$259,318 $1,377 563
$663,172
$528,362
$219,948
$121,569
$172,755
$73.392
$65,929
$117,124 $520,025
$72 304
$245,639
$147716
$513,199
$67,257 $309,150
$16,995
$193,453 $670,065
$99.829
$103,693
$113,425
$714,288 582 950
$565,174 194 375
$179,365 $339,675
$147 418 $319,900
$68,051 $390,525
$521 647 495,350
$761,050
$67,430 $172,620
$561,825
$99,313
$179,272
$175,831
$136,243
$361,019
$151,672
$141,031 $351,540
$237 165 $260 250
$137 296 $257,250
$10,851
$30,107
$292,134
$99,334 $402 225
$75,106
$46,679
$119,703 $169,175
$46,626 $132 060
$411 316 $762,755
$127 963
$169,135
$13,162
$15,039,465
$24 540,828
13,391,039
4,439,829
995.846
Exhibit No. 25
Avista, Lafferty, Rebuttal
Case No. AVU-E-O4-
Page 1 of 4
Gas Sales Volume by Transaction by Month (dthlday)
Total
Sales Qg:.Qg Nov-Q2 Jan-03 Mar-Aor-Q3 Mav-Jun-Aua-Sec-OcI,
000 10,000
000 000
65,000 000 000 000 000 000 000 000 5,000 5,000 000 5,000 000 5,000
65,000 000 000 000 000 000 000 000 000 000 000 000 000 000
000 000
000 000
10,000 10,000
000 000
000 000
15,000 15,000
20,000 000 000 000 000
000 000 000
15,000
10,000 10,000
10,000 000 000
15,000 000 000 000
13,000 13,000
000 000
5,000 5,000
000 000
12,000 000
22,000 22,000
30,000 30,000
000 000
000 000
000 11,000
000 000
000 000
500
500
20,000 000 000 000 000
000 000 000 000
000 5,000
000 000
000 000
20,000 10,000 10,000
10,000 10,000
000 000
22,000 22,000
000 000
000 000
000 000
000 000
15,000 000 000 000
000 000
000 000
000 000
000 000
000 000
000 000
000 000
10,000 10,000
000
000
000 000
000 000
000
000
000
000 21,000
21,000
500 500 500 500
000 000 000 000
000 000
622,000 40,000 40,000 40,000 40,000 40,000 40,000 41,500 40,000 40,000 40,000 40,000 40,000 40,000 40,000 21,500 19,500 19,500
Exhibit No. 25
Avista, Lafferty, Rebuttal
Case No. AVU-E-o4-
Page 2 of 4
Deal B Loss on Gas Sales by Month
al B Purchase Price $5,985 $5,985 $5,985 $5,985 $5,985 $5,985 $5,985 $5,985 $5,985 $5,985 $5,985
,ys In Month
Month Jun-02 .!!!!:Qg Nov-Dec.Q2 Jan-Mar-Aor-03
174 900
$408 425
$350,250 $350,250 $361 925 $361,925 $326,900 $361,925 $350,250
$369,750 $369,750 $382,075 $382,075 $345,100 $382,075 $369,750
$389,250
$393,750
$730,500
$260,250
$257,250
$1,377 563
$520 025
$309,150
$670,065
$402,225 $389,250
$393,750
$338,675
$319,900
$380,525
$172,620
$351,540
Total Loss on Gas Sale $2,751 000 $3,480,913 $309,150 $720,000 $1,414 065 082 675 164 520 $1,878,290 503 000
Total Gas Sold 40,000 40,000 40,000 000 40,000 40,000 500 40,000 40,000 000 40,000
Average Loss on Gas Sale $2,$2,$0,$0,$0,$0,$1.10 $0,$1.$1,$1.
Deal B Loss on Gas Sale 375,500 740,456 $154,575 $360,000 $681 477 $541 338 $582,260 $939,145 $751 500
Total Deal B Loss $13,381,039
Idaho Allocation (33,18%)$4,439,829
~% PCA Customer Portion $3,995846
Exhibit No. 25
Avista, Lafferty, Rebuttal
Case No- AVU-O4-
Page 3 of 4
Deal B Loss on Gas Sales by Month
\al B Purchase Price S5,985 S5,985 S5,985 S5,965 S5,985 S5,985 S5,985
lYS In Month
Month Jun-Mav-03
S350,250 S361 ,925 S350,250 S361 ,925 S361 ,925 S350,250 S361 ,925 S369,750 S382,075 S369,750 $382,075 S382,075 S369,750 S382,075S389,25O
$393,750
$730,500
$260,250
S25725O
$402,225 S389,250
$406,875 S393,750
S754,850 S730,5oo
S761 ,050
S260,250
S257 250
$402,225
S168 175
S132,060
S762 755
Total Loss on Gas Sale $2,751,000 S3,O69,Ooo S2,751 000 S2,O41 O40 S744,Ooo S720,000 S912,175
Total Gas Sold 40,000 40,000 000 40,000 21,500 19,500 19,500
Average Loss on Gas Sale S2,S2,$2,S1,S1,S1,S1,
Deal B Loss on Gas Sale 375,5oo S1,534,5oo S1,375,5oo S1,020,520 S692,093 S720,ooo S912,175
Total Deal BLoss S13,381 039
Idaho Allocation (33,18%)$4,439,829
1% PCA Customer Portion 995,846
Exhibit No. 25
Avista, Lafferty, Rebuttal
Case No. AVU-O4-1
Page 4 of 4