Watters.pdf

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Q. Please state your name, business address and position with PacifiCorp (the
Company).
A. My name is Stan K. Watters. My business address is 825 NE Multnomah,
Portland, Oregon, 97232. My present position is Vice President of Wholesale
Energy Services.
Qualifications
Q. Please describe your education and business experience.
A. I joined the Company in 1982 and I have held various positions in engineering,
finance, and wholesale prior to my current position. In my position as Vice
President of Wholesale Energy Services, I am responsible for the Company’s
wholesale sales and trading functions including the economic dispatch of
PacifiCorp’s system resources. I graduated from Oregon State University in 1981
with a Bachelor of Science in Civil Engineering.
Purpose of Testimony
Q. What is the purpose of your testimony?
A. My testimony addresses the Company’s overall power supply strategy during the
deferral period, focusing in particular on the cause of the significantly higher net
power costs incurred above the level included in rates and the actions that the
Company took to keep net power costs as low as possible.
The Company’s 2000-2001 Power Supply Strategy
Q. Would you describe the Company’s overall approach in securing the necessary
power supply to serve its retail customers?
Watters, Di 1
PacifiCorp

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A. Yes. During the 2000-2001 period, the Company generally relied upon the
market for balancing the system portfolio and supplying incremental
requirements. As part of this strategy, PacifiCorp, similar to any load serving
utility, uses a complex process that evaluates its load and resource balances well
in advance of the scheduled delivery of energy, so that the Company can meet its
objectives of reducing risks associated with market price and supply while serving
customers safely and efficiently. This process is continually revisited because
load and resource balances can and do change frequently due to a variety of
factors. Those factors include higher or lower than expected retail loads, changes
in market prices, thermal unit outages, weather and hydro conditions.
Q. Please explain the major causes of the significant increase in net power costs the
Company incurred during the deferral period.
A. The significantly higher net power costs experienced by the Company during the
deferral period are primarily attributable to the extraordinary increase in
wholesale prices beginning in late spring 2000. This situation was exacerbated by
other, unrelated circumstances including (1) the impact of the sale of Centralia,
(2) the Hunter 1 failure, (3) abnormally poor hydro conditions, and (4) retail load
growth. The Company’s losses were further compounded by the impact of
FERC’s unanticipated rule changes adopted June 19, 2001, and the resulting price
decreases in market prices after those FERC rule changes. I will discuss each of
these circumstances in my testimony.
Watters, Di 2
PacifiCorp

Extraordinary Increase in Wholesale Prices 1
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Q. Please describe the extraordinary and volatile price conditions that existed in the
wholesale market during the deferral period.
A. Beginning in late spring 2000, wholesale energy markets changed unexpectedly.
Prices and price volatility surged dramatically to unprecedented levels, and the
supply became more constrained. For example, the daily on-peak wholesale
market price for January 2000 at COB averaged $31.62 per MWh compared to
$180.82 per MWh in June 2000, $129.96 per MWh in July 2000 and $213.73 per
MWh in August 2000. The significant increase in price volatility was evident in
the changes in market spreads between peak and off-peak prices. For example,
the COB average market spread between peak and off-peak prices changed from
$6.62 per MWh in January 2000 at COB to $117.94 per MWh in August 2000.
Q. Did market price forecasts vary by a large amount from May 2000 through the
deferral period?
A. Yes. As shown on Exhibit No. 1, the variation in market prices was at
unprecedented levels, and the prices were substantially higher than our historical
experience. Using August 2001 as an example, in late May 2000 the forecasted
price for this particular month was $80 per MWh, in April 2001 the forecast price
increased to $598 per MWh, and then unexpectedly declined dramatically to $67
per MWh in July 2001.
Q. How did market prices compare to the level included in rates for short-term
purchases?
Watters, Di 3
PacifiCorp

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A. The average market price of short-term purchased power included in the
Company’s rates was approximately $21.50 per MWh compared to an average
price of approximately $139 per MWh during the deferral period, or
approximately 6.5 times the level included in rates. In this environment, the
Company’s strategy of relying on the market to fill in during the “peaks” of a
generally balanced load and resource situation became very costly. The market
purchases used to fill in the occasional short-term deficiency in supply were no
longer priced at $20-$30 per MWh, but at prices dramatically higher, as I
discussed above.
Q. What were the Company’s options for meeting load requirements with the near
term implications of these unforeseen price levels and volatility?
A. Based upon forward price projections available at the time, it appeared likely that
market prices would stay higher than historical averages for the foreseeable
future. We had two options for meeting near term resource requirements: the
Company could buy forward to cover the bulk of resource requirements or leave
most of the balancing to the extremely volatile day-ahead and real-time markets.
Q. How did the Company respond?
A. The Company rejected reliance on the day-ahead and real-time markets to balance
its system, and determined that the inclusion of some forward purchases provided
a better balance to meeting load requirements. As the Commission is aware, the
failed California deregulation attempt featured reliance on these markets. This
approach resulted in the bankruptcy of one major utility, a second major utility
teetering on the brink of bankruptcy, and the state of California with an additional
Watters, Di 4
PacifiCorp

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$9.0 billion of debt related to energy purchases that it did not expect. The
Company did not adopt the California approach, but rather chose to prudently buy
resources forward, in support of the load requirements during the deferral period
to hedge risk.
Q. When did the Company begin buying energy to meet load requirements for the
deferral period?
A. The Company began purchasing energy during June 2000 to meet expected
energy requirements during the deferral period. At that time the purchases were
predominately for the 2001 summer season because the loss of Hunter 1 and the
upcoming poor hydro conditions were not known. Provided, as Exhibit No. 2, is a
summary of forward purchases executed for June 2001, July 2001 and August
2001 prior to June 18, 2001.
Q. Does the Company employ a specific process when balancing its system forward?
A. Yes. The Company continually evaluates its position and requirements so that it
buys and sells energy in the most advantageous locations to optimize the
Company’s system and keep costs as low as possible given the various constraints
present in the Company’s system and the market at that time. Sales and purchases
are entered on a gradual basis because large transactions can have the unintended
effect of driving prices either significantly higher or lower. In addition, a gradual
process utilizes the concept of price averaging, which is beneficial.
Q. Did the Company undertake additional activities to handle the high price volatility
and reduce its exposure to the wholesale market?
Watters, Di 5
PacifiCorp

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A. Yes. The Company undertook a series of non-traditional transactions to deal with
the unexpected risks the Company was experiencing under the unprecedented
conditions occurring in the wholesale energy market. In addition to buying
energy forward, the Company entered the following transactions to reduce
reliance on the wholesale market.
• Purchase of Incremental Generation – the purchase of generation output via
bilateral contracts from entities owning generation that was previously off-
line.
• Purchase of Displaced Generation – the purchase of generation output from
entities that either had invoked, or intended to invoke, their option to displace
operating generation and take retail service at tariff prices.
• Purchase of Operating Reserves – the purchase of load reduction options
that qualify as a supplemental reserve pursuant to North American Reliability
Council criteria, thus, freeing up additional PacifiCorp generation to serve
load.
• 10/10 and 20/20 Challenge Programs – the implementation of two customer
buyback programs under which residential customers that reduced their load
10 percent or 20 percent from 2000 summer peak levels were rewarded with a
10 percent or 20 percent price reduction on their remaining energy
consumption.
Watters, Di 6
PacifiCorp

• Advertising - the implementation of advertising programs in conjunction with
the 20/20 and 10/10 programs to make customers aware of the high cost of
resources and to encourage voluntary conservation.
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• Gadsby Peakers – the lease of 100 MW of gas peakers at the Company’s
Gadsby Power Plant from May 15, 2001 through November 15, 2001. The
additional generation provided intermediate peaking capacity and reduced the
Company’s exposure to the forecast high market prices during super peak
hours.
• Demand Exchange Program – the implementation of a daily demand
exchange program whereby qualified retail customers are able to bid in
verifiable load reductions.
• Continued Conservation – the continuation and expansion of existing
conservation programs, such as the Compact Fluorescent Light Program
whereby customers are given compact fluorescent lights and educated as to
their use.
• Load Reduction - securing bilateral agreements with retail customers to
curtail load for various time periods.
• Incremental Transmission - the acquisition of incremental transmission
rights to improve the Company’s ability to delivery power to our customers.
Q. Did the Company’s customers benefit from these transactions?
A. Yes. Customers benefited from the fact that these programs helped insure supply
to meet load requirements. In addition, some customers benefited monetarily
Watters, Di 7
PacifiCorp

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from customer buy-back programs where the savings were shared with customers.
For example, customers that had generation were paid the cost of generation plus
an amount of the difference between the day-ahead power market and the cost of
generation. The cost of generation was based on the heat rate of their unit(s)
multiplied by an appropriate gas index used to reflect their fuel cost plus variable
O & M on their generation. The Company then shared the difference between
this cost of generation and the index price of electricity at an appropriate delivery
point into the Company’s system. This structure insured that the customer
recovered their cost of generation and received a profit on the difference between
the day-ahead power market index and the generation cost. All of PacifiCorp’s
customers received a benefit of power purchases at prices below the day-ahead
power market prices.
Q. Was the Company also facing a supply risk during the deferral period?
A. Yes. As shown on Exhibit No. 3, there were a significant number of power
emergencies declared in California. During 2000 and through the first few
months of 2001 parts of California experienced rolling blackouts, which affected
hundreds of thousands of customers. Further, there were forecasts that the 2001
summer season would be even worse and that the problem could spread to other
parts of the WSCC.
Q. What did the Company do to reduce the risk that supplies would be inadequate?
A. The Company’s strategy of buying forward and the other innovative transactions
the Company entered ensured that customers had adequate power supplies. As a
Watters, Di 8
PacifiCorp

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result, our customers had none of the supply interruption problems encountered
by the California utilities.
Impact of Other Factors 3
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Q. Apart from these conditions in the wholesale markets, what other factors
contributed to the high power costs during the deferral period?
A. As I mentioned above, the extraordinary circumstances in the wholesale market
were exacerbated by other, unrelated factors including (1) the impact of the sale
of Centralia, (2) the Hunter 1 failure, (3) abnormally poor hydro conditions, and
(4) retail load growth.
Q What was the impact of the Centralia sale?
A. The Company sold the Centralia plant to TransAlta prior to the run up in
wholesale market prices that began in May 2000. The Centralia transaction was
approved by this Commission (in Order No. 28296) as well as the other state
commissions that regulate the Company. This sale, net of the associated
replacement power contract with TransAlta, eliminated approximately 1.2 million
and 1.4 million MWh’s from the Company’s long-term resource portfolio in 2000
and 2001, respectively.
Q. Did the Company indicate in the Centralia proceeding that it would be relying on
market purchases to replace the Centralia output?
A. Yes. As described in Order No. 28296, the Company indicated that without
Centralia, it intended to balance its loads and resources with market purchases.
(Under the Company’s medium market price forecasts, customers were shown to
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PacifiCorp

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be better off if the plant were sold.) This is the strategy the Company pursued, as
a majority of the replacement power was purchased from TransAlta, with the
balance of the requirement obtained from the general market. There was a
recognition at the time of the Centralia sale that the economic analysis associated
with the Centralia transaction was sensitive to small changes in critical
assumptions. The Commission recognized as well “the vagaries inherent in long-
term forecasting,” and agreed with Staff’s characterization of the Company’s
decision to sell “as an exercise of business judgment.” (Order No. 28296)
Q. What was the Hunter 1 failure, and how did that affect the level of power cost
deferrals?
A. On November 24, 2000, the Company experienced a catastrophic outage at its
Hunter 1 unit, a 430-MW baseload generating station. This outage, which lasted
through May 8, 2001, contributed approximately another .3 million and 1.1
million MWh’s of short-term purchase requirements in 2000 and 2001,
respectively.
Q. How did hydro conditions affect the level of power cost deferrals?
A. The 2000-2001 water year, commencing on October 1, 2000, was second worst
water year on record. These poor hydro conditions added another .5 million and
2.3 million MWh’s of short-term purchase requirements in 2000 and 2001,
respectively.
Q. What was the impact of load growth?
Watters, Di 10
PacifiCorp

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A. The Company’s retail load growth in 2000 and 2001 added additional short-term
purchasing requirements above the level included in rates. The Company’s
strategy has always been designed to match loads and resources, thereby
minimizing the extent of the Company’s exposure to purchases from the
wholesale market. As a result of load growth, the Company’s resources were
needed earlier than expected. Of course, without the significant increase in
wholesale market prices, the slight mismatch between projected and realized
loads and resources would not have been expensive. Combined with the
conditions in the wholesale markets, however, the failure to achieve a precise
matching of loads and resources -- an impossible feat under the best of
circumstances -- had exaggerated consequences.
Q. Given these circumstances, how much has the Company relied on the wholesale
market to balance its system load requirements?
A. As Table 1 below shows, the Company generally matched its short-term sales and
purchases fairly well prior to 2000. The circumstances described above caused
the Company to increase slightly its reliance on short-term purchases in 2000 and
2001. Had these circumstances not occurred, net market purchases would have
been 4.1% in 2000 and the Company would have had a net short-term sales
surplus during the first 10 months of 2001of approximately 1.1 percent. Even
with all of these impacts, net short-term purchase requirements in 2000 and 2001
represented a fairly small amount – about 6.6 percent and 7.1 percent
respectively- of the Company’s system requirements. This means that the
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PacifiCorp

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Company was not being overly aggressive in the wholesale market and exposing
customers to unreasonable market price risk.
Table 1
PacifiCorp 1996-2001
Net Short-Term Purchases as a Percentage of System Requirements

Year
Total System
Load
(Million MWH)
Net Short Term
Purchases
(Million MWH)

% of System
Requirements

1996 62.9 0.9 1.4
1997 66.1 1.8 2.7
1998 68.3 2.3 3.4
1999 67.5 1.7 2.5
2000 68.1 4.5 6.6
20011 52.3 3.7 7.1
1 Through October 2001

The Impact of FERC’s Price Mitigation Measures 3
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Q. Although you claim that PacifiCorp’s customers benefited from purchasing power
below the day-ahead power market, wasn’t there a risk associated with buying
forward?
A. There is always some risk in forward-looking transactions, because variables can
and do change, as I explained above. That is why the Company continually
evaluates the options for minimizing risk. In this case, the Company decided that
the risk of balancing the system forward coupled with the risk of falling prices
due to various factors was less than the potentially unlimited risk of balancing the
system in the extremely volatile day ahead and real time markets.
Q. Was the Company successful at reducing its exposure to the wholesale market?
Watters, Di 12
PacifiCorp

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A. Yes. Based on the Company’s load and resource position and the average cost of
that position on March 6, 2001, the Company had a mark-to-market value of
approximately $700 million associated with its forward purchases for the ensuing
year. In other words, had the Company been able to close all of its forward
purchases on that date, at the then current forward price curve prices, net power
costs would have been approximately $700 million lower than they would have
been had the Company not previously engaged in forward purchases. Therefore,
the Company had prudently met its objective of reducing market price risk.
(Actually closing the Company’s position at that time was not an acceptable
alternative, however, as it would have defeated the purpose of the forward
purchases: the Company would have been exposed to unlimited risk for the
energy still expected to be necessary to meet load requirements.)
Q. Wasn’t the risk associated with forward purchases increased by the fact that the
Company and numerous other parties had urged FERC to impose wholesale price
caps?
A. It is true that various interested parties and individuals including senators,
governors, public utilities and municipalities had requested price caps. Given that
the Bush Administration and FERC repeatedly stated that price caps would not be
implemented, however, the Company had no reason to believe price caps or other
measures would be implemented that would effectively lower prices. For these
reasons, the Company prudently acquired resources to limit risk. As a matter of
fact, the Company’s opinion was only reinforced when the FERC implemented
“Soft Caps” in January 2001.
Watters, Di 13
PacifiCorp

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Q. Please explain.
A. When the Soft Caps were implemented they tended to do more damage than good.
The price caps did not have a firm dollar limit and were limited to the state of
California. Power marketers soon realized that power could be acquired in
California under the price caps, moved outside the state, mixed with other power
and resold back to California at prices well above the price caps. The failure of
the soft caps only reinforced the Company’s view that “hard” price caps would
not be implemented by FERC.
Q. Without these price caps, did the Company expect that wholesale market prices
would fall in the near future?
A. No. The Company believed that extremely high wholesale prices would continue
until new gas fired resources came on-line to provide adequate supply. With
construction lead times in the range of two and three years, depending upon the
type of plant built, the Company expected that wholesale prices would not start to
decline until at least late spring or summer of 2002.
Q. Did the Company monitor actions at FERC and other agencies to remain informed
about potential changes that could affect prices in the wholesale markets?
A. Yes. The Company monitored formal proceeding as well as statements by
individual FERC Commissioners in various public forums. The Company’s
senior management attended a special FERC Western states forum in Boise at
which then-FERC Chairman Curt Hebert forcefully reiterated the Commission
position against price caps. Company officials met with other key federal energy
policy makers throughout the period to gain insight. Based on the information the
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PacifiCorp

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Company obtained, we believed there would be no changes forthcoming from the
FERC that would materially affect the price of energy in the wholesale market.
As a matter of fact, as late as May 26, 2001, Vice President Dick Cheney
expressed his strong opposition to any price caps. He stated price caps
“are a mistake. It’s not a solution; it’s adding to the problem. There isn’t
anything that can be done short-term to produce more kilowatts this
summer.”
With statements like these, the Company had no expectations that measures
would be implemented that would lower prices.
Q. How did circumstances change when FERC implemented its price mitigation
measures?
A. FERC unexpectedly implemented a new price cap Order effective June 19, 2001.
The FERC Order not only placed a cap on market prices, but also fundamentally
changed the market place with two other rules that were contained in the Order.
First, FERC required generators in California to exclude emission costs from their
incremental generation costs. This lowered the fundamental dispatch curve in the
WSCC by the level of these emission costs, which at times were approximately
$130 per MWh. Second, FERC required each generator in California to offer
their power into the market unless their units were legitimately down for
maintenance. Generators could no longer withhold generation from the market in
order to keep prices high. These two unexpected changes significantly lowered
the price of power in the WSCC.
Q. Did the Company anticipate the FERC Order?
Watters, Di 15
PacifiCorp

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A. No. As I explained earlier, there was no reason to expect the implementation of
measures that would materially lower prices. And the market did not anticipate
the change in market fundamentals. Prior to the FERC rule changes and the
fundamental changes in the market, the Company continued to believe that FERC
would not implement changes that would significantly alter the market price of
energy. Accordingly, the 2001 summer was expected to be robust from an energy
use perspective. As shown on Exhibit No. 1, at the end of May 2001 the market
forecast August 2001 prices to be $391 per MWh.
Q. Please explain the causes of the significant increase in net power costs during the
period following the FERC Order.
A. The primary cause was the sudden and unforeseen drop in wholesale market
prices which was precipitated by lower than expected retail loads, lower gas
prices and the unexpected rule changes adopted in concert with the FERC Order
that was implemented on June 19, 2001. Unfortunately, the Company had hedged
against potential market price risk at prices much higher than the historical norm,
but less than the then current forward price curve, to cover the usually high
resource requirements of the summer peak period, plus the impact of the second
worst water year on record. To make matters worse, loads were less than
expected because of a cooler summer, customer conservation and a slowing
economy. Market prices were driven still lower in part because of lower than
expected gas prices. As a result, the once extremely valuable long shoulder
period position, which had previously been created through the Company’s
forward purchases, was now a liability, because the average price of the long
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PacifiCorp

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shoulder period position was now substantially above then existing wholesale
market prices.
Q. What do you mean by “shoulder position”?
A. Sometimes we enter into near-term contracts knowing that some of the power that
will be delivered under them is surplus to our needs. There are “standard”
products in the market, for example a “Heavy Load Hour” product that provides a
“6 x 16” block of deliveries (16 hours per day for six days). To the extent we do
not purchase “standard” forward products, we are forced to rely more on hourly
purchases at unpredictable prices. Therefore we may purchase a “Heavy Load
Hour” product as the most economical and lowest-risk means of meeting our
“super-peak” needs during eight hours each day of an upcoming six-day period,
with the expectation that we will sell surplus energy in hourly markets for the
eight “shoulder” hours of each of those days. At other times, we enter into term
contracts and expected load does not materialize, requiring us to sell surplus
energy into near-term markets.
Q. Why didn’t the Company close some of its surplus shoulder positions prior to the
FERC rule changes?
A. There are two primary reasons. First, as I previously mentioned, the Company
had no reason to believe FERC would implement effective measures that would
materially lower the market price of energy. Second, the Company could not
have closed any of the long shoulder period positions before market prices
dropped without increasing market price and supply risk during the extremely
volatile super-peak period, because the forward market only trades standard
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PacifiCorp

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products such as 6x16, 5x16 and 7x24 products. Trading standard products to
reduce the long shoulder position would have resulted in the Company being
further short during the super-peak period and therefore exposed to more risk.
Q. Did other parties buy forward at prices that are now significantly above market?
A. Yes. The State of California for one, through the California Department of Water
Resources, bought a significant amount of energy many years into the future at
prices that are now quite a bit above market. In addition, several other utilities
have requests before various commissions seeking recovery of significantly
higher net power costs. The Company’s request is thus not an isolated request
that should be viewed with skepticism; rather, it is a somewhat common, yet
unfortunate, problem that faces many utilities in the WSCC.
Q. Why is it appropriate for the Company to recover the costs of these forward
purchases under such circumstances?
A. Utilities were generally encouraged during the period prior to the June 19 FERC
Order to engage in such forward purchases to reduce reliance on spot or short-
term markets and instead increase reliance on term products. Having engaged in
these actions, the Company should have an opportunity to recover the costs we
incurred. The Washington Utilities and Transportation Commission (“WUTC”),
for its part, has commented to FERC that it would be unfair to penalize utilities,
such as PacifiCorp, that prudently purchased in the forward market prior to the
FERC Order. In comments filed with FERC on August 17, 2001, the WUTC
stated:
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PacifiCorp

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It is fundamentally unfair to preclude load-serving entities from the
opportunity to recover in wholesale markets the cost of term products they
purchased pursuant to load-service obligations incurred in those markets
prior to the Commission’s action to implement price mitigation. Load-
serving utilities are fundamentally different from marketers because they
do not have the choice to enter the market—they must obtain the power to
serve their statutory obligations. Between December 15, [2000] and
June 19, 2001, the Commission admonished purchasers in the wholesale
power market to reduce reliance on spot or short-term markets and
increase reliance on term products. To ignore now the consequences of
costs incurred by utilities that followed that advice would be to punish
those that heeded the Commission’s directives and, perversely, would
benefit those that did not.

(WUTC Comments, p. 12) For the same reasons, we believe we should be
provided an opportunity to recover the costs of these forward purchases.
Conclusion
Q. Please summarize why the Company’s deferred power costs should be recovered
in rates.
A. The Company reasonably responded to the extraordinary and volatile conditions
in the wholesale electricity markets in the western United States since May 2000
by engaging in forward purchases to minimize availability and price risks to
customers. As described in my testimony above, the level of deferral in this
proceeding arises from a number of factors beyond the Company’s control,
including the impact of extraordinary and unprecedented high prices and volatility
in the wholesale markets, the Hunter 1 outage, the second worst water year on
record and the consequences of actions outside the Company’s control – such as
the FERC Order and rule changes – on the Company’s forward power purchases.
Moreover, it would be punitive and unfair to penalize the Company for events
beyond the Company’s control – primarily FERC’s June 19, 2001 Order imposing
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PacifiCorp

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price caps and new rules – when the strategy followed by the Company to balance
its system was prudent based on then-existing circumstances and expected future
conditions at the time. Had these unusual and unexpected events not occurred,
net power costs would have been substantially lower than the level incurred.
Q. Does this conclude your direct testimony?
A. Yes.
Watters, Di 20
PacifiCorp