20040622Hessing Direct.pdf

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BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NA TU RAl GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN
THE STATE OF IDAHO.
) CASE NO. AVU-O4-) AVU-O4-
DIRECT TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTiliTIES COMMISSION
JUNE 21 , 2004
Please state you~ name and business address
for the record.
My name is Kei th D. Hessing and my business
address is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
What is your educational and experience
background?
I am a Registered Professional Engineer in
the State of Idaho.I received a Bachelor of Science
Degree in Civil Engineering from the Uni versi ty of Idaho
in 1974.Since then, I worked six years for the Idaho
Department of Water Resources, and two years for
Morrison-Knudsen.I have been continuously employed
the Commission since August 1983.
As a member of the Commission Staff , my
prlmary areas of responsibility have been electric
utility power supply, revenue allocation and rate design.
What is the purpose of your testimony in
this proceeding?
My testimony discusses electric issues
including Jurisdictional Separations, Class Cost of
Service and PCA issues including Deal ~An and Deal ~
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
gas purchase issues carried into this case from Case No.
AVU-03-6 by Commission Order No. 29377.I al so propose
a change in PCA methodology.My testimony concludes with
a brief discussion of average rate changes for each
customer class and an exhibit showing the overall effects
of Staff's rate proposal.
Please summarize your testimony.
I recommend that the Commission accept the
Jurisdictional Separation study proposed by the Company.
I also recommend that the Class Cost of Service
methodology proposed by Avista be accepted by the
Commission.I provide Cost of Service resul ts, that
include Staff's accounting adjustments, to Staff witness
Schunke which he uses as the starting point in allocating
revenue requirement to the various customer classes.
I recommend that the Commission accept the
Company s calculation of base power supply costs for use
in future PCA calculations.I recommend that losses on
the purchase and subsequent sale of Deal ~Bn gas in the
amount of $6,496,669 not be charged to customers.I al
propose a reduction in PCA rates.
I propose that the PCA rate design
methodology be changed once the current deferral balance
is eliminated.Currently increases and decreases are
spread to customer classes based on each class
CASE NOS. AVU-04-1/AVU-04-
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HESSING, K (Di)
STAFF
percentage of total revenue and recovered in the energy
charge for each class.I propose that PCA increases and
decreases be surcharged or rebated to customers on the
basis of energy consumption.My proposal would apply an
equal cents per kWh rate to all customer classes except
lighting classes which would receive the average
percentage lncrease or decrease.
My testimony concludes with an exhibit
showing the combined average revenue changes for each
customer class caused by Staff's base rate proposal, DSM
Rider rate proposal and PCA rate change proposal.The
overall net electric increase proposed by Staff is 2.4%.
JURISDICTIONAL SEPARATIONS AND CLASS COST OF SERVICE
What Jurisdictional Separation and Class
Cost of Service methodology is used by the Company?
The Company applied the same Jurisdictional
Separation methodology accepted by the Commission in its
last general rate case, Case No. WWP-E- 98 -11.The
methodology directly assigns revenues, costs and
investment to jurisdictions where appropriate and
allocates the remaining amounts.The methodology uses
2002 test year booked amounts without adjustment.All
adjustments are included on an Idaho System basis at the
beginning of the Cost of Service process.
The Company used the same Peak Credit Cost
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HESSING, K (Di)
STAFF
of Service methodology that it used in its last general
rate case with minor modifications.The Commi s s ion
accepted that methodology as the starting point for
revenue allocation in that case.Staff proposes only an
incremental move toward full cost of service in
recognition of the fact that cost of serVlce results are
not precise and unacceptably large increases to some
classes would occur.Staff witness Schunke discusses
revenue allocation to the various customer classes in his
testimony.
Is there value in applying consistent
Jurisdictional Separation and Class Cost of Service
methodology from case to case?
Yes, there is.It allows the usage and
customer characteristics that form the allocators and the
accounting data to drive the resul ts.There are
substantial changes caused by these factors wi thout
changing the methodology.
Does the Staff accept the methodology and
allocation factors used by the Company in its filing?
Yes.
Have you prepared an exhibi t that shows the
Class Cost of Service resul ts that have been used as the
starting point for revenue allocation in Staff's case?
Yes, I have.Staff Exhibit No. 138 shows
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
Class Cost of Service resul ts based on a total revenue
requirement of $169,326,876 which is a $23,078,876,
15.78% increase above existing base rates.This
information was provided to Staff witness Schunke for
revenue allocation purposes.
PCA ISSUES
Deal "A" and Deal "
Please summarize the Deal ~An and Deal ~
lssue carried into this case by Commission Order No.
29377 from Case No. AVU-03-6, which was the Company
last PCA case.
In March 2001 , Avista Utilities purchased
gas at index to operate its gas-fired resources for the
purpose of producing electrici ty.Deal ~An deliveries
were for 27 658 dth/day for a 36-month period beginning
November 1, 2001.Deal ~Bn deliveries were 20,000
dth/day for a 17-month period beginning June 1 2002.
Total Deal ~An and Deal ~Bn purchases were exactly the
quanti ty of gas required to run the Coyote Springs 2 CCCT
at its full generating capacity of 280 MW.
In April and May of 2001 , using 4 separate
transactions, the Company fixed the price, using hedges,
for 40,000 dth/day, which is 84 percent of the gas.The
hedged price averaged approximately $6.00 per decatherm.
The other 16 percent of the gas remained at index.The
CASE NOS. AVU-04-1/AVU-04-
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HESSING, K (Di)
STAFF
Company s Confidential Exhibit 7 , Schedule 16, summarlzes
the Deal ~An and ~Bn transactions.
When the various gas price hedges were
established , electric forward market prices were high and
if the electric prices would have persisted in real time
a number of good things could have happened to the
Company and its customers using the fixed price gas.
discuss those later in this testimony.However, between
the time that the price was fixed and the time the gas
supplies were to be delivered, electric and gas market
prices dropped precipi tously.After this happened, the
best plan for the Company and its customers was to sell
the gas at a loss and purchase the Company s electric
needs from the wholesale electric market each month.The
Company had losses on Deal ~An and Deal Bn which it
proposed to include in the PCA.The PCA would have
passed 90% of the losses for the Idaho jurisdiction on to
customers while the Company s shareholders would have
been responsible for the other 10%.In its comments in
the referenced case , Staff proposed that only Deal ~
losses be excluded from PCA treatment and recovery from
ratepayers.In its final order in that case, the
Commission did not rule on the issue but required that
both Deal ~An and Deal ~Bn losses be examined in more
detai I in thi s proceeding.Staff Exhibi t No. 139 is a
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
copy of the Staff Comments filed in Case No. AVU-03-
The detailed discussion of Deal ~An and Bn begins on
page 6.An understanding of the referenced comments and
testimony is essential to full understanding of the Deal
An and ~Bn issues in this case.
Please summarize Staff's conclusions in that
case.
With regard to the Company s Energy
Resources Risk Policy, the Staff concluded that Deal ~
purchases violated risk policy provisions.Al so, Deal
Bn price hedges were entered into with Avista Energy
(AE) , an unregulated affiliate of the regulated utility.
Staff concluded that appropriate safeguards were not
place or followed to protect customers when the regulated
utility does business with its affiliate.Safeguards
could include a proper Code of Conduct or a requirement
for lower-of -cost or market pricing.The Staff also
concluded that the Company took unusual risks when
hedging the price for the length of these gas purchase
deals for its electric customers.Similar risks were not
taken for its natural gas customers.
What has changed with regard to Deal ~An and
Bn purchases since the Staff filed its comments in the
last PCA case?
Several months have passed and the time
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
frame for gas delivery under Deal ~Bn is over.It ended
at the end of October 2003.In the last few months of
the deal, Avista sold some of the gas at a loss but
burned some of the Deal ~Bn gas profitably.
Has Staff's position changed since its PCA
filing?
No, but Staff does recognlze that some Deal
Bn gas has since been burned profitably.It is only
fair that the savings on the price of the gas when the
market is above $6.00 be netted against losses when the
market is below $6.00.Staff's position in this case
that the net of Deal ~Bn profits and losses, net losses,
should not be included in the PCA.
Does the Company s filing in this case
address the concerns that Staff raised in its filed
comments in Case No. AVU-03-
Only partially.In his testimony, Company
witness Lafferty presents and discusses Deal ~An and Deal
Bn purchases from a longer-term , resource planning,
point of view instead of the near term, risk policy,
point of view presented by Staff in its previously
referenced PCA comments.
Please discuss some of the differences in
the two approaches.
The risk policy perspective Vlews resource
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HESSING, K (Di)
STAFF
decisions for the coming 18 -month period.This process
initially assumes normal load and resource conditions and
updates both based on forecasts as they become available.
Forecasts become more accurate as they near real time.
The policy includes written rules and maximum long and
short position limits that vary based on the period of
time remaining before energy lS needed, real time.
general the Company' s ~position n is the difference
between expected loads and expected resources.
The long-term planning view presumably
guides resource decisions that are made for periods
further than 18 months out.It assumes cri tical water
conditions resulting in approximately 150 average MW'
less available generation than under normal water
condi t ions.Eighteen months out from real time , where
the planning criteria time period and operating criteria
time period meet, loads and resources that are perfectly
balanced based on the long-term critical water planning
criteria result in an approximate 150 MW long position
under the risk policy review criteria because the risk
policy is based on normal water condition assumptions.
Eighteen months out, the long limit allowed in the risk
management plan is 150 MW above normal water conditions.
Therefore, the Company would move into the risk policy
analysis period with the largest amount of extra
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STAFF
resources that the plan allows.Of course, if the
Company is just a little long based on long-term critical
water planning criteria, it transitions into the risk
policy period above the established limits and would
immediately have to sell energy to get below the long
limit contained in the Company s Risk Policy.
Does Company witness Lafferty suggest that
there are concerns, other than cri tical water , that the
Company should be allowed to consider when it purchases
fuel for its gas fired resources?
In addition to water conditions Mr.Yes.
Lafferty suggests that loads and outages should also be
considered.He states that actual loads could be higher
than expected by 87 MW and that a unit outage at Colstrip
could reduce generating capability by 100 MW.Pg. 4 3 )
Does it make sense to purchase energy or
fixed price fuel to produce energy for 300+ MW of unusual
def iciencies?
No, not before the deficiencies become
known.The chances of all three events occurrlng
together are extremely improbable.
Is it reasonable to have some energy reserve
to address these types of deficiency causing events
they do occur?
Yes, it is.The Company s risk policy very
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
specifically provides for this by establishing a long
limi t of 150 MW.The Company s Risk Policy says,
Reasons to maintain long positions may include
strategies to mitigate potential negative impacts of
unplanned loss of resources, adverse changes in hydro
conditions, or adverse impacts of load variations as
compared to the forecastn (Exhibit 139, Energy Resources
Risk Policy, Attachment J, Pgs. 3 and 4 of 15)
Do the differing perspectives concerning
appropriate reVlew cri teria cause the Company and Staff
to reach different conclusions?
I think so.The long-term perspective used
by the Company to justify these transactions is very
different than the Company s near term risk policy
perspective used by the Staff.
How are the Deal ~An and ~Bn purchases
initially positioned relative to the 18-month transition
point between the long-term and short-term analytical
approaches?
As indicated in Staff comments in the last
PCA case, both purchases were ongoing at the 18 -month
transition point which was about October 2002.
Why does Staff utilize the Company
shorter-term risk policy method of analysis to evaluate
the merits of the gas transactions?
CASE NOS. AVU-04-1/AVU-04-06/21/04
HESSING, K (Di)
STAFF
The Energy Resources Risk Policy is written
and well defined.It is designed to address the very
situations that the Company says could occur.The
Resource planning process that Staff is familiar with,
the Integrated Resource Planning (IRP) process, does not
incl ude cri teria for acquiring energy or gas to produce
energy which is the issue being addressed here.
Was the Company using a long-term planning
process like the one discussed in its testimony and used
to justify its long out-of-limit position before the Deal
An and Bn gas purchases?
I f the Company was using it's long termNo.
resource acquisition plan , its resource positions would
have been long, probably even long out of limits in its
Position Reports.As shown on the Company s Posi tion
Limit Chart for March 7 , 2001 (Exhibit No. 139,
Confidential Attachment K , pg. 1), the load resource
balance is short coming into the 18 month planning period
and remains short or minimally long, 35 MW maximum , for
the entire period.This report reflects the Company
position just prior to Deal ~An and ~Bn transactions.
This is not consistent with the long-term acquisition
process the Company says it uses.
In Staff's previously mentioned PCA
comments, Staff pointed out that Avista s gas operations
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
did not make the same kind of long-term purchases for its
gas customers in early 2001.What information do you
have that supports this position?
Staff Exhibit No. 140 was provided by the
Company in response to Staff Production Request No.2 7 .
The Exhibit shows that in early 2001 the Company did not
purchase gas two and three years into .the future for its
gas customers.The fact that the Company failed to
purchase gas with the same kind of long-term deals for
its gas customers that it did for its electric customers
demonstrates the Company s inconsistency.If long-term
gas purchases were expected to be beneficial to the
electric utility, why would they have not been expected
to be beneficial to the gas utility?Staff Exhibit No.
140 shows that in the same time frame, the Company rarely
purchased gas for its gas customers at Deal ~An or ~
prices and never made fixed price purchases for use more
than two years in the future.
In its PCA comments the Staff discussed the
hedge transactions between Avista Utilities and Avista
Energy (AE) that fixed the gas cost for Deal Bn in April
and May of 2001.Do you have anything further to add to
that discussion?
When the gas cost was fixed withYes.
Avista Energy, both AE and the utility along with its
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
customers were exposed to risk.AE's risk was that gas
prices would go up and that when it needed gas for
delivery it would be more costly.
The utility was exposed to several types of
risk.It had the risk that gas prices would go down and
gas would cost less when it was needed.The utility also
had the risk that electric and gas prices would go down
such that the gas could not be economically used to
produce electricity and the gas would have to be sold
a loss.Of course, through the PCA 90% of any loss would
be recovered from customers.This created a si tuation
where one affiliate essentially bet against the other
affiliate.One was going to prof i t and one was going to
pay and because of the PCA, Avista shareholders were
substantially protected from paying.Because the deal
with AE was not provided to Avista Utilities at cost, AE
had the opportunity to profit by keeping the difference
between the actual cost and fixed price of gas sold to
the regulated utility.In fact a counter party such as
AE would not have made the deal if it did not expect to
profi t.In the end, AE profited and the regulated
utility is proposing that its customers pay 90% of the
costs.If AE chose not to hedge its risks on the
transactions , it profited by the difference between
actual and fixed price.In the end regulated utility
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HESSING, K (Di)
STAFF
shareholders paid 10% of the AE profit and utility
ratepayers paid the other 90% of AE's profi t.It is
Staff's position that whether AE profi ted or not, Deal
Bn was not at the lower-of-cost or market and,
therefore, constituted an inappropriate affiliate
transaction.Staff's Deal ~Bn proposal in this case,
that net losses on the gas sales should not be allowed in
the PCA , amounts to giving the customer the bet ter deal,
cost or market.
Why does Staff propose to disallow Deal ~
loss recovery and accept Deal ~An loss recovery?
Deal ~An hedges were not done with an Avista
affiliate, but Deal ~Bn hedges were.Also, the Deal ~
gas purchase did not put the Company over the long I imi t
contained in it's Risk Policy, the Deal Bn purchase
which was executed at a later point in time caused the
utility to exceed the long limit.Not only did the
transaction place Avista above the long limit, but
Avista s position continued to stay above the limit.
Has the information provided by the Company
changed Staff's position regarding disallowance of Deal
Bn net losses from PCA treatment?
It remains Staff's position that netNo.
losses on the sale of Deal ~Bn gas should not be included
in the PCA.
CASE NOS. AVU-04-1/AVU-04-
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HESS ING, (Di)
STAFF
What is the basis for this conclusion?
It is Staff's position that the Company
violated both the intent and the written requirements of
its own Energy Resources Risk Policy.The Company
purchased gas for electric generation that exceeded the
limits allowed by the policy, then fixed the price which
created a speculative posi tion that led to the losses.
Also in executing the Deal ~Bn price hedges with its
unregulated affiliate, Avista Energy, the Company created
a potential conflict of interest.In order to avoid
potential abuse or even the appearance of abuse, the
Company needs to provide its customers with the best deal
by recording the transaction at the lower-of -cost or
market absent other specific rules established to protect
customers.Staff believes that it was extremely risky to
lock the price of gas at a traditionally high price in
gas market with prices falling even though forward
electric prlces were high.
What other reasons could have caused the
Company to take the risks that it took in the Deal ~
and ~Bn purchases?
Avista needed the Coyote Springs 2 plant to
reduce its dependence on what had become a highly
volatile energy market.Coyote Springs 2 was to be one
of the most efficient combined cycle gas-fired combustion
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
turbines in the reglon with a 7 000 BTU/kWh heat rate.
Avista was financially stressed and needed to obtain a
gas supply in order to secure financing for the proj ect.
Deal ~An provided the necessary gas transportation along
wi th gas supply.If electric prices held at or near the
forward level at the time of the Deal ~An and ~Bn hedges,
the operation of CS 2 would have been profitable.Power
needed by customers could be generated at a cost below
the market price.If the Company was long on supply, it
could generate power and sell the power for profit.Ten
percent of the prof it would go to shareholders, whi Ie 90
percent of the prof it would go to the PCA to buy down PCA
balances and reduce customer rates.
This philosophy could have worked if the
electric sale of the long energy had also been made
the same time to lock in the gain and reduce the long
posi tion.Absent such an electric power sale, the
transaction was purely speculation.
Al so, if all had gone according to the
Company s plan , Coyote Springs 2 would have been
demonstrated to be used and useful and therefore, easily
rate based.
The Company fixed the gas prlces for 84% of
the Deal ~An and ~Bn gas.Could Avista have fixed
electric forward prices as well?
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HESSING, K (Di)
STAFF
Yes, but the cost may have been substantial
and may have reduced or eliminated the expected profits.
If the cost of fixing the electric forward
prlces was high or prohibi ti ve, what would this tell
Avista about the risk of the transaction?
If the parties who sell this type of
financial instrument wanted a high premium to fix the
forward price of electricity they obviously believed that
there was a great deal of risk in selling forward at a
fixed prlce.If there is a great deal of risk that
forward electric prices would be lower than forecast , the
Company should have chosen shorter term less risky deals
that would have captured the benefi ts of layering or
dollar cost averaging.Again as previously stated,
absent electric sale transactions this acti vi ty was based
on speculation.Customers should not pay for Avista to
speculate.
In two different places in his testimony,
Company witness Lafferty characterizes Staff's proposal
that electric forward prices could have been hedged along
with gas prices as ~retrospective
(pg.
47) or ~after the
factn
(pg.
51) views.Would you please comment.
It is a common practice in the energy
business to capture the benefits of a deal by locking in
all prices.It requires no hindsight to see the
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
advantages of so doing in the Deal ~An and ~
transactions.By not locking the electric forward prlces
in these transactions the Company gambled that electric
prices would not decline substantially.The Company lost
on that gamble.As stated previously, customers should
not pay for speculation or a gamble.
What amount does Staff recommend be removed
from the PCA deferral account to reflect Deal ~Bn losses?
Deal ~Bn losses are calculated on Staff
Confidential Exhibit No. 141.The bottom line shows that
90% of Idaho jurisdictional losses on Deal ~Bn that have
been deferred for recovery are $6 496,669.This is the
amount that Staff recommends be removed from the PCA
deferral account.
Does Staff Exhibit No. 141 also show the
Deal ~An losses that Staff is not proposing to remove
from PCA treatment?
Ninety percent of the IdahoYes.
jurisdictional share of Deal ~An losses are shown to be
$8,677 766.
Upda ted PCA Components
Are base PCA net power supply costs to be
updated as a resul t of this general rate case?
Staff proposes that base power supplyYes.
costs be updated as a resul t of this case.The Company
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
proposed the same.Company wi tness Johnson shows the new
base amounts on Exhibi 10, Schedule
What are base power supply costs used for in
the PCA?
The PCA calculates the difference between
actual and authorized base Idaho jurisdictional power
supply costs and, after appropriate sharing and a load
change revenue adjustment, defers the difference for
later recovery or rebate.
Does Staff support the base amounts proposed
by the Company as shown in Company wi tness Johnson
Exhibi t 10, Schedule 4?
Yes.
Is there another PCA component that the
Company proposes to update in this case?
In his testimony, Company wi tnessYes.
Johnson proposes to update the load change revenue
adj ustment mul tiplier.
What change is proposed in the mul tiplier?
The Company proposes that the multiplier be
changed from 21.23 $/MWh to 36.38 $/MWh.
How is the multiplier used?
The multiplier is the average annual
variable power supply cost of meeting new load as
determined from the Company s power supply model.It is
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
multiplied times the difference between base and actual
loads to determine the cost of load changes that occur
and accrue in the PCA.The resul ting cost is used to
adjust the power supply cost deferral for changes in
power supply costs associated with load growth or
decline.By removing this resul ting amount from the PCA
calculation, power supply costs associated wi th load
change are reserved for consideration in general rate
cases.
Does Staff agree wi th the Company
calculation of the load change revenue adjustment
mul tiplier.
Yes.
PCA Rate Reduction
Does the Company recommend a reduct ion in
current PCA rates?
In its filing the Company estimated aYes.
deferral balance of approximately $23 million at the end
of September 2004.The Company proposes to implement
reduced PCA rates in this case designed to recover $11.
million of the estimated balance each year for two years.
What is Staff's PCA rate proposal?
Staff proposes to reduce the Company
actual end of May 2004 balance of $26,261 334 by
$ 6, 496, 669 in Deal Bn losses and calculate rates to
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
recover the remalnlng balance over 2 years.This reduces
the PCA revenue requirement by $17 963,835 per year.
Staff believes it is more appropriate to use actual
amounts than estimates even though the PCA trues the
amounts up to actual.
Other PCA Matters
Does Staff propose a change in the PCA
mechanism?
Staff proposes to change the way ratesYes.
are calculated in the PCA mechanism once the current PCA
deferral balance is eliminated.The current PCA
mechanism assigns class revenue responsibili ty based on a
uniform percentage of revenue spread to each class and
then assigns recovery to the energy portion of the rate
wi thin each class.Staff proposes that PCA costs be
recovered from Avista ratepayers on a uniform cents per
kWh basis. The PCA rate would be the same for all
schedules except lighting schedules.Lighting schedules
would pay/receive the Idaho average increase/decrease.
Why should this change be made?
The allocation of PCA costs to individual
rate classes based on a percentage of total revenue
assumes and relies on a mix of fixed and variable costs
like those allocated to each customer class through the
Cost of Service process.Above or below normal power
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STAFF
supply costs that are captured in the PCA mechanism are
directly related to the variable costs of providing
energy.The fixed costs of power supply are not captured
in the PCA.Therefore, it is more appropriate to recover
variable power supply costs wi th an equal cents per kWh
charge that applies to all energy use.
When does Staff propose this change be made?
Staff proposes that this change be made when
the current deferral balance is eliminated.
Why not make the change with the new rates
that will resul t from this case?
As pointed out by the Company in this case
there is a very substantial PCA deferral balance that has
accumulated and that will be recovered from customers in
the next few years.Staff believes that because the
balance was accumulated under the current methodology
is fair to recover this balance under the current
methodology.However , when the balance is eliminated,
the methodology should be changed.The proposed
methodology causes high load factor customers,such as
Potlatch and others,pay/receive a larger percentage
of surcharges/rebates.To impose such a change when
there is a large balance to surcharge would initially
penalize high load factor customers.It is only fair to
make the change when the current balance is at or near
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STAFF
zero and, golng forward, there is an equal probability of
credi t or surcharge.
FINAL REVENUE ALLOCATION
What rates does Staff propose to change as
the resul t of this case?
Staff proposes that base rates change based
on the revenue requirement spread included in Staff
witness Schunke s testimony.His testimony also provides
Staff's proposed base rates.In addition , Staff witness
Anderson proposes a change in DSM Rider rates.Finally,
my testimony recommends changes to PCA rates. I propose
that these PCA rate changes stay in place until October
2005 when an annual review of the deferral balance could
cause them to change.Staff Exhibit No. 142 shows all of
the revenue requirement changes by customer class and the
resul ting net percentage lncreases and decreases measured
from existing rates.As shown on the exhibi t , the
overall change is a 2.4% lncrease above existing rates.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NOS. AVU-E- 04 -1/AVU-G- 04-06/21/04
HESSING, K (Di)
STAFF
CERTIFICA TE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 21ST DAY OF JUNE 2004
SERVED THE FOREGOING DIRECT TESTIMONY OF KEITH HESSING, IN
CASE NO. AVU-04-l/AVU-04-, BY MAILING A COpy THEREOF POSTAGE
PREP AID, TO THE FOLLOWING:
DAVID J. MEYER
SR VP AND GENERAL COUNSEL
VISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
KELLY NORWOOD
VICE PRESIDENT STATE & FED. REG.
VISTA UTILITIES
PO BOX 3727
SPOKANE W A 99220-3727
CONLEY E WARD
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
DENNIS E PESEAU, PH. D.
UTILITY RESOURCES INC
1500 LIBERTY ST SE, SUITE 250
SALEM OR 97302
CHARLES L A COX
EV ANS KEANE
111 MAIN STREET
PO BOX 659
KELLOGG ID 83837
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH ST
BOISE ID 83702
CERTIFICATE OF SERVICE
HECE1VED ill
lLED
F'-
2.DII11 JUN 2' Pi; \: 58
'" '", '" ""' ,! (
UT 11-(:( IE;;.! C~i;1i'~hS'SlON
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR
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. AVU-O4-) AVU-O4-
EXHIBITS OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
JUNE 21 2004
ALLEGEDLY PROPRIETARY DATA HAS BEEN
DELETED FROM THESE EXHIBITS
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LA!\;......0;
I-JSCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOIS;:, IDAHO 83720-0074
[phone]
BAR NO. 1895
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Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE SUBMISSION OF
THE SCHEDULE 66 PCA STATUS REPORT OF )
AVISTA CORPORATION AND APPLICATION
FOR CONTINUATION OF A SCHEDULE 66
POWER COST ADJUSTMENT (PCA) SURCHARGE.
CASE NO. A VU-O3-
COMMENTS OF THE
COMMISSION STAFF
CONIES NOW the Staff of the. Idaho Public Utilities Commission, by and through its
Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of
Application, Notice of Modified Procedure, Notice of Comment/Protest Deadline and Notice of
PCA/Energy Discussion issued on August 27 2003 submits the following comments.
BACKGROUND
On August 11 , 2003 , Avista Corporation dba Avista Utilities (Avista; Company) filed a
Power Cost Adjustment (PCA) Schedule 66 Status Report with the Idaho Public Utilities
Commission (Commission) and an Application requesting approved recovery of excess power
costs deferred through June 30, 2003 and further continuation of a 19.4% ($23.6 million) PCA
surcharge currently scheduled to expire on October 11 , 2003. Following a public hearing, the
19.40/0 surcharge was originally authorized by the Commission in Order No. 28876 dated
ST AFF COMMENTS SEPTEMBER 30, 2003
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deferral balance at a higher level than the current rate for customer deposits. Staff and the :J :J cr ~
Company agreed to a compromise solution adopted by the Commission in Order No. 29323 , dateo"" ~ Ci ~
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October 11 , 2001 in CaseNo. A VU-Ol-11. A 12-month continuation of the surcharge was
authorized following a public workshop and comments in Order No. 29130 in Case No.
A VU-02-
ST AFF REVIEW
Audit Results
Staff has performed a review and audit of the amounts that went into the deferral balance
in the current filing. Staff s review covered expenses incurred for the period July 2002 through
June 2003. Staff was able to look at a representative cross section of transactions included in the
Purchased Power account (FERC 555), Thennal Fuel account (FERC 501), CT Fuel account
(FERC 547) and the Power Sales account (FERC 447). Based 011 its review' of these sale
transactions, Staff concludes that the transactions appear reasonable at the time they were entered
into. Other than the net fuel expense item that will be discussed in detail later in these comments
Staff finds the amounts recorded to be correct and recommends that they be included in the
deferral balance as of June 30, 2003.
The PGE credit recognizes continued 18-year amortization from the monetization of a
contract A vista had with Portland General Electric in the last rate case. A line item in the PCA
mechanism recognizes this credit by reducing a surcharge or increasing a rebate., The Company
received approval to accelerate the amortization from 18 years to fifteen months in order to offset
the impact of low water and high market prices. The accelerated amortization of the PGE credit
directly benefited the customers as the amount of the PCA surcharge is less and the length of the
surcharge is shorter by its inclusion. The amounts recorded in the PCA deferral balance are
correct. The PGE credit is $2 309 280 per month and expired at the end of 2002. In this current
PCA filing, the PGE credit contributed $13 855 680. Staffnotes that this benefit will not be
included in future PCA deferrals.
Interest Rate Adjustments
On May 16, 2003, the Company filed an Application requesting that the Commission issue
an Order setting the interest rate that applies to the Company s Power Cost Adjustment (PCA)
STAFF COMMENTS SEPTEMBER 30, 2003
August 21 , 2003. A 200 basis point increase will be allowed in the interest rate applied to year
end deferral balances during recovery based on the first in first out (FIFO) method of accounting.
The customer deposit interest rate would continue to apply to new deferral balances accnled
during the calendar year. This interest rate methodology would begin January 1 , 2003 and
continue through June 30, 2005.
Commission Order 29323 was issued after the Company filed its status report in this case.
As such, the new interest methodology was not applied in the case as filed by the Company. Staff
proposes to include the results of the new methodology in this current PCA year s deferral balance
and calculations. The result of Staffs adjustment increases the current year s deferral amount by
$256,727. This amount reflects the application of a 200 basis point adder to the current years
customer deposit rate of 20/0, calculated on the existing balance throughout the months of January
through June 2003; and the application of the customer deposit rate of 20/0 on the new deferrals
which continues to be calculated at simple interest. The Staff s calculations are shown in
Attachment A.
Deferral Balance Components
The Company is requesting Commission approval for recovery of the Unrecovered
Deferral Balance of $27 843 108 as of June 30, 2003. The Unrecovered Deferral Balance at June
, 2003 is calculated by starting with the Unrecovered balance at June 30, 2002, adding in the net
deferral activity for the current period of July 1, 2002 through June 30, 2003; and subtracting the
anlortizations related to surcharge revenues.
Unrecovered Balance at June 30, 2002
Net Deferral Activity (July 2002 - June 2003)
Amortization s Related to Surcharge Revenues (July 2002 - June 2003)
Unrecovered Balance at June 3 , 2003
$45 600 228
6,789 503
(24,456,623)
$27 843 108
Exhibit No. 139
Case No. AVU-04-1/
A VU 04-
, K. Hessing, Staff
6/21/04 Page 3 of 30
STAFF COMMENTS SEPTEMBER 30, 2003
The net deferral activity consists of several pieces. The Company s Application lists the
deferral activity detail that goes into the Net Deferral ,Activity (July 2002 - June 2003) in the
amount of$6 789 503. The net deferral activity is comprised of the follow items and amounts:
Net Increase in Power Supply Cost
Centralia Capital and O&M Credit (Order No. 28876)
PGE Monetization Accelerated Amortization (Order No. 28876)
Small Generation Capital Costs and Interest (Order No. 29130)
Intervenor Funding Payment (Order No. 29147)
Interest
$23 383 629
($2 817 996)
($13 855 680)
($921 184)
138
$999 596
The Centralia Capital and O&M- Credit reflects the Centralia capital costs such as return on
investment and Centralia O&M expense. Since base rates were set, the Centralia power plant has
been sold. The Centralia credit is designed to offset the Centralia revenue requirement that is still
part of base rates. The Centralia credit is not subject to 90/1 0 sharing.
. The PGE Monetization reflects the accelerated amortization of the credit balance related to
the Monetization of a Portland General Electric (PGE) sale agreement. This credit balance is now
zero.
The Small Generation Capital Costs and Interest were disallowed in the last PCA filing,
Case No. A VU-02-6. The costs included in the deferral balance that represented capital costs
and the interest thereon, were excluded from deferral balance and subsequent recovery.
The intervenor funding payment resulted from Order No. 29147 in Case No.
GNR-02-1 dated October 31 2002, an Order dealing with published rate eligibility and contract
length for PURP A proj ects. The Commission directed the three participating utilities to equally
share the intervenor funding amount, to book the payment as a purchased power expense and"
...
to recover same in their next Power Cost Adjustment (PCA) filing or general rate case.
The largest component of the net deferral activity is the Net Increase in Power Supply
Cost. The total net increase in power supply cost, $23 , 383 629, is comprised of the following
items:
1. Purchased Power
2. Thermal Fuel
3. CT Fuel4. Sales for Resale5. PGE Capacity Revenue True Up
6. Potlatch 25 aMW
7. Kettle Falls Bi-Fuel
($7 083 766)
($5 942 944)
($948 195)
$21 605 030
($2,483 328)
260 572
102 506
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 4 of 30
STAFF COMMENTS SEPTEMBER 30, 2003
8. Net Fuel Expense - Loss on Natural Gas Resold
9. Idaho Retail Revenue Adjustment
10. Wood Power Inc. Amortized Expense
11. Reverse Coyote Test Power Sales
$11 817 650
$651 882
$352 788
$51 434
1. Purchased Power represents the difference in costs the Company incurred for power
purchases when compared to base rates. The negative amount represents a benefit to
ratepayers - the Company bought less power in the market than is currently built into base
rates.
2. Thernlal Fuel is the amount spent for fuel, primarily coal, used to produce electricity. This
item is the difference in costs the Company incurred for thermal fuel when compared
base rates. The negative amount represents a benefit to ratepayers - the Company bought
less coal than is currently built into base rates.
3. CT Fuel is the cost of natural gas burned in the Company s conlbustion turbines. This
amount represents the difference in costs the Company incurred for CT fuel when
compared to base rates. The negative amount is a benefit to ratepayers.
4. Sales for Resale represents revenues the Company is able to generate through long-tenn
and short-term off-system sales. These revenues reduce the revenue requirement for
ratepayers. The positive amount represents a decrease in off-system sales. This amount
represents an increased cost to customers over what is currently built into rates.
5. The PGE Capacity Revenue True up adjustment was approved in Order 28775 , Case No.
A VU-OI-, when the PCA mechanism was modified. The Adjustment records an
additional amount of revenue to the recorded revenue in Account 447 so that there is no
PCA impact of the PGE capacity sale.
6. The Potlatch conlponent is a direct assignment to Idaho of Potlatch costs and revenues
(Lewiston faciE ty).
7. The Kettle Falls Bi-Fuel colnponent is the final payment on the Company s lease of
temporary generators for the Kettle Falls Bi-Fuel project. Temporary generators were
leased and placed at Kettle Falls to avoid additional high-cost purchases of energy from the
that the lease costs for these temporary generators was properly included in the PCA.
8. Net Fuel Expense is discussed in more depth in the next section.
short-term wholesale markets. The projects represented the lowest cost resource options
available at the time. In Order No. 29130, Case No. A VU-02-, the Commission found
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SEPTEMBER 30, 2003STAFF COMMENTS
9. The Idaho Retail Revenue Adjustment is an adjustment for changes in load. If the load
grows, revenue is added, if the load declines, there is an adjustment to reflect the decreased
load. A revenue credit of retail load is computed,using a variable cost of power supply of
21.23 mills/kWh multiplied by the growth in load.
10. Wood Power operated a PURP A qualified wood waste powered generation facility at
Plummer, Idaho. Washington Water Po'wer entered into a power sales agreement with Wood
Power on August 19 1982 to purchase the energy and capacity from that facility.
September 30, 1996, Washington Water Power entered into an agreement with vVood Power
and Rayonier tenninating the 1982 power sales agreement. In Order No. 26751 , Case No.
WWP-96-, the Company received authorization for rate ,making and accounting treatment
of the buy-out of the Wood Power, Inc. contract. The Commission found that the deferral and
amortization of the buy-out over eight years 'was reasonable. This amount is the current year
amortization of the buy-out of that contract.
11. The Coyote Springs test power sales are included in the Sales for Resale accounts. When
testing was being done at the Coyote Springs II facility, the power was sold and the sales
recorded in the Sales for Resale account. This adjustment removes them from the PCA
deferral balance.
A significant portion of the net increase in Power Supply Costs is due to the expiration of
long-tenn power sales contracts. The expiration of profitable contracts reduced Sales for Resale
revenue dramatically. In the PCA, Sales for Resale revenue is an offset to Power Supply Costs.
The loss of revenue from expired contracts is partially offset by reductions in fuel costs and
Purchased Power costs. Total long-term sales contracts fell from twenty-one in the base case to
eight in June of2003. The reduction in recent time periods of energy sales and associated revenue
is shown on Attachment B.
Net Fuel Expense
Avista Utilities has an obligation to provide electrical service to its customers. To satisfy
this obligation, the Company both generates and buys electricity. Part of the utility s generating
resources are fueled by natural gas. When gas prices are low enough that electricity can be
uses it to produce electricity.
generated at a cost below the cost of buying electricity on the market, the Company buys gas and
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 6 of 30
SEPTEMBER 30 2003STAFF COMMENTS
In the last PCA case, A VU-02-, Staff questioned the circumstances surrounding
acquisition and later sale of natural gas purchased by the Company to fuel the Coyote Springs II
CCCT (Combined Cycle Combustion Turbine). The Company maintains that at the time natural
gas was purchased, it was anticipated that Coyote Springs II would be operational and more
economical to operate,than making market energy purchases. As it turns out, Coyote Springs II
\vas neither operational nor was it economical to use the gas at the Company s other facilities
given the price of the gas with previously purchased fixed-for-floating financial swaps. The effect
is an abnonnally high percentage of hedged gas to serve available resources at prices found to be
uneconomical when cOlnpared to energy purchased from the mar~et.
In Case No. A VU-02-, Staff proposed that the Commission withhold judgment on
$578 748 in net fuel expense incurred in June of2002 to serve Coyote Springs until a more
complete evaluation was conducted regarding anticipated online dates, reasons for the operational
delay and timing of the sale of gas acquired for use at the plant. Pending further investigation, the
Commission in its Order removed the $578 748. As part of its current PCA investigation and as a
result of concerns raised regarding the circumstances surrounding acquisition and sale of natural
gas in Case No. A VU-02-, Staff has completed a comprehensive review of gas purchase and
sales transactions that generated losses on fuel resold and the excess net fuel costs requested for
recovery in this case.
In March of 2001 , A vista entered into two contracts to secure gas and gas transportation
for its Coyote Springs II gas fired power plant. Initially Coyote Springs II was scheduled for
testing in early 2002 and \-vas expected to be commercially available in July of2Q02. The two
purchases for Coyote Springs II, with five corresponding financial swap transactions, are of
primary concern to Staff. These purchases and financial swaps are shown in detail on Staff's
Confidential Attachment C. The first gas supply contract (Deal A) was to be delivered November
2001 through November 1 2004. The fixed-for-floating financial swaps associated with this
supply contract consist of two transactions. See Confidential Attachment C for specific volumes
and prices. Since the delivery period did not begin for another 6 months, the price for October
2004 was locked 3 1/2 years into the future without additional documentation showing analyses
beyond October 2002. Additional analyses that should have been fully documented with the swap
order should include volatility analyses, price trend analyses and load requirements for the time
STAFF COMMENTS SEPTEMBER 30 , 2003
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period involved.
The second gas supply contract (Deal B) was for delivery to begin June 1 , 2002 and
continue through October 31 2003. Avista entered into two fixed-for-floating financial swap
contracts that were subsequently combined into one contract, for the entire delivery period. This
transaction locked in the price of gas for a period of 17 months. Since the delivery period did not
begin for another 13 months, the October 2003 price was locked 2 1/2 years into the future.
Gas from both contracts is sufficient to operate Coyote Springs II at its full 180 MW
generating capacity through October 31 , 2003. At the time the Deals were first entered into and at
the time the prices were locked, forward prices for electricity for an 18-month period were
expected to be very high and the Company expected substantial purchased povver cost savings
and/or sales for resale revenues from the gas purchases. A portion of these savings or revenue
credits would have flowed through the PCA to benefit Idaho ratepayers and a portion would have
benefited Company shareholders. During June of2001 , day ahead electric market prices fell
below $1 OO/MWh for the first time in a year and by Septen1ber they were approximately
$25/MWh, which is near the historic nonnal wholesale electric price. See Staff Attachment
Given approximately $6.00 gas, the drop in electric prices made it uneconomical to operate any of
Avista s gas fired plants to make electricity. Instead Avista simply purchased its power needs on
the electric market and sold the gas back into the gas market at a loss because gas prices had also
declined. See Staff Attachments E through H.
In A vista s PCA filing last year, which covered the time period July 2001 through June
2002 , losses on the sale of gas from Deal A amounted to approximately $5.6 million and were
approved for recovery. (See Confidential Attachment I) The loss on Deal B last year was
approximately $0.6 million. This amount was not recovered in the last PCA, but deferred to the
current PCA year for evaluation. In this year s PCA, which covers July 2002 through June 2003
A vista has included $11.8 million in losses due to gas sales. It is likely that there will be more
losses on the sale of this gas through the end of the longest contract, which ends on November 1
2004.
In Order No. 29130 the Commission directed Staff to investigate and assess the
reasonableness of Avista s Risk Management Policy and how it affects the Company s short-tenn
resource acquisition decision and to submit its findings and conclusions in the Company s next
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comments. A vista has an electric Risk Policy for managing the financial risk associated with
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providing electric energy to its customers. (Confidential Attachment J; A vista Corp.s Energy
Resources Risk Policy.) The policy addresses the purchase and sale of electricity as well as the
purchase and sale of natural gas acquired to generate electricity. In general, this Policy defines a
mechanism that eliminates differences between loads and resources as the actual time of need
approaches. The Company s Risk Policy typically extends 18 months out, and tracks surpluses
and deficiencies month by month down to projected needs in the coming month. Avista s Risk
Policy (dated November 9 , 2000, page 1 of 15) specifically states
, "
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." Deficits are eliminated with relatively small purchases that may occur over several
months. Surpluses are eliminated with sales in the saIne way. The plan does not take a price view
- that is, there are no purchases or sales made based on speculative judgments as to whether
electric market prices are going up or coming down. ' Surpluses or deficits are systematically
eliminated over time without speculation with regard to price. Such a plan is designed to reduce
the financial risks that might otherwise be associated with large quantity, long-term sales or
purchases made at a single point in time.
In theory, Staff does not oppose entering into financial swaps or hedges to fix the price of
gas. However, Staff is concerned about the length of the swaps that A vista entered into and the
apparent lack of additional support 2 Y2 and 3 Y2 years in the future. The Company previously
received from the Commission an accounting Order authorizing the deferral of the costs of a
financial hedge for Avista s gas operations; however, that financial transaction was entered into in
December 2000 for delivery during January through March 2001. That transaction occurred
shortly before delivery was taken, and only covered a period of 3 months. The financial swaps
that Avista entered into for the March 9, 2001 transaction covered 3 years, and delivery was not to
begin for another 6 months in the future. Because the swaps locked prices for the last month 3 'lj
years out, these swaps were inherently risky instruments.
The gas deals that A vista entered into were unusual. A vista Electric had no recent history
of entering into purchase or sales arrangements that went outside of its normal 18-month position
report planning period. A vista Gas Operations did not make purchases outside of a 12-month
period that it uses to balance its gas need for its gas customers.
STAFF COMMENTS
Exhibit No. 139
Case No. A VU-04-
A VU 04-
K. Hessing, Staff
6/21/04 Page 9 of 30
SEPTEMBER 30, 2003
Staffbelieves that the losses on the sale of gas from the two purchases resulted from
substantial risks that the Company took when it locked in the price for large quantities of gas for a
period of time up to 3 1/2 years after the date of the purchase. The risk substantially stems from
the price paid, the fact that the price was established at only 2 points in time approximately 30
days apart, gas price levels and trends over time, the volume of gas purchased, the length of
forward analysis and the duration of the purchases.
Prices averaging $6.00 per dth are historically high. Gas prices for the period of months
leading up to the Company s purchases had been very high and very volatile. The Company
should have known that locking in gas prices at historical highs based prilnarily on long-tenn
future po\ver prices with volatile and/or illiquid forward markets was very risky.
The March 2001 contracts for gas delivery assured the gas and transportation. The April
and May 2001 financial swaps were entered into to lock in the price of gas. Locking in a high
purchase price at 2 points in time approximately one month apart for long-term purchases does not
capture the risk reducing benefits of layering or cost averaging that would be captured with
monthly purchases or reduced volumes at fixed prices spread over the period of power need.
Risks could have been reduced if smaller quantities of 2 , 3 or 5 thousand dthlday had been
purchased over time instead of 4 financial swaps entered into over the period of a month totaling
000 dth/day (decathenn/day) for much of the entire 3-year period. Not only did the Company
lock into the purchase side of the gas transaction at historically high gas prices, in large volumes at
essentially one point in time, it failed to mitigate the risk by also securing some mechanism to lock
in the power sale side of the transaction for the excess energy. If the Company had locked into
forward electricity sale agreements for the excess power generation, some of the risk of the gas
fixed-for-floating financial swap purchase could have been mitigated. The Company appears to
have done nothing to mitigate the risk of locking in the price of the gas. Historical trends and
changes in rig counts and production levels support that prices should decline and if the Company
continued with the initial Deals, i.e. index plus a small adder, the risk would have been
significantly smaller. If the financial transactions had never taken place, the gas, ifbumed, would
have been purchased at a price within pennies of the spot price, and if the gas had been sold, it
would have been sold at a price within pennies of the spot price. These risk considerations are the
type of issue where stakeholder and customer input into the Risk Policy would be beneficial.
ST MF COMMENTS SEPTEMBER 30, 2003
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The Company s decisions were contrary to the previously cited principals of good risk
management. The Company s Risk Policy allows for purchases that exceed 18 months in the
future with proper authorization. These purchases met the Company s authorization requirements.
However, Staff contends the documentation to support these substantially longer transactions is
lacking. The Deal tickets provided some explanation as to why the long-tenn purchases were
made at this point in time. The workpapers reiterate again and again that the purchases were
entered into for the sole purpose of securing financing for the Coyote Springs II Project. The
financial swaps were completed on May 10 , 2001. Board Minutes and other documents reflect
that the financing package for construction financing for the development of the Coyote Springs II
Project was proposed to and approved by the Board of Directors at the quarterly meeting on May
, 2001. The primary reason for locking in gas supply and price for the Coyote Springs II Proj ect
appears to be for the purpose of obtaining outside financing for the proj ect. This may explain why
the Company undertook financial transactions that Staff believes were largely outside its existing
Risk Policy. To the extent the transactions were made for the purpose of financing Coyote
Springs II, they were to meet Avista s cash flovv requirements that were not necessarily associated
with u~ility operations. Ironically, the project financing was not achieved with this approach.
Whether the transactions were implemented for the purpose of obtaining proj ect financing
or not, the effect of undertaking financial swaps beyond the generally accepted period of
months as specified in the Company s Risk Policy was $39 465 033 in losses on a system basis.
This amount, which translates to $11 785 048 on an Idaho jurisdictional basis after sharing,
consists of losses during the period of July 2002 through June 2003 for the swaps entered into on
April 10, 2001 and May 2, 2001 , and losses associated with swaps during the months of June 2002
through June 2003 entered into on April 11 , 2001 , May 10, 2001 and rolled into one swap on June
, 2002. As previously mentioned, losses on these financial swaps during future PCA periods is
also likely.
Deal B Adjustment
However, while Staff has been critical of the Company with respect to its overall gas
acquisition approach for Coyote Springs II and questions the reasonableness of the long-tenn
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STAFF COMMENTS SEPTEMBER 30, 2003
losses during the PCA period at issue in this case. Instead, Staff limits its recommended
adjustment to losses associated with Deal B during the period from June 2002 through June 2003.
Gas losses incurred under Deal B carryall of the risk concerns previously identified with
one additional concern, the purchase put the Conlpany in a long position outside of established
risk management limits. Staff recommends that losses on the sale of Deal B gas not be allowed to
be deferred for PCA recovery.
After Avista entered into Deal A on March 9 2001 , the next Company position report
generally showed that A vista s resource/load balance stayed within established risk guideline
limits for the delivery period. When A vista entered into Deal B the position reports showed
A vista to be surplus beyond the established limits. A vista resisted selling the above limit energy
for a period of time by getting a waiver from its Risk Ivlanagelnent COlllillittee but eventually sold
the gas and took the loss. At this point in time all the gas purchased under Deals A and B was sold
at a loss and energy needs were purchased from the electric market because it was the most
economic choice. Less electrical energy was purchased than could have been generated with the
gas because the Company did not need all the energy the gas would have generated. The
additional gas purchase activity more clearly falls under the definition of taking a "Speculative
Position" as defined on p. 11 of 15 in the Company s Risk Policy. It is speculative because the
generation is not needed for load; it focuses on future price changes and is not documented and
shown to reduce "Business Risk."
The Company provided Staff with a sample of daily Position Reports and Position Limit
Charts. The Position Limit Charts show projected energy surpluses and deficits for Heavy Load
Hours (HLH) and Light Load Hours (LLH) in average Megawatts for a period of 18 months along
with their relationship to risk linlits. Confidential Attachment K, pages 1 through 4 are copies of
Position Limit Charts on 4 selected days. Page 1 shows the Company s projected positions on
March 7, 2003 , which is prior to either of the gas purchase deals. For the period beginning
November 2001 and beyond it shows small surpluses and deficits except for two substantial
deficits that are outside the short position limits. Page 2 shows the Company s projected positions
on March 21 2001. This chart shows the Conlpany s projected positions after it acquired gas
under Deal A but before it entered into Deal B. The purchase of gas to be used to generate energy
moved all of the Company s 2002 positions in the surplus direction, as one would expect. At this
STAFF COMMENTS SEPTEMBER 30 , 2003
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point in time, the chart shows no long or short positions outside of risk management limits.
3 shows the Company s projected positions on March 28 2003. At this point in time the
Company had entered into Deal B, which was the additional gas purchase that began in June of
2002. At this point in time all 2002 positions are surplus and LLH in the third quarter are surplus
beyond the limit. To be surplus outside of the risk managen1ent limits in one quarter 18 months
out does not cause Staff a great deal of concern. However, it is the only full quarter shown on that
chart that captures the effect of both gas purchases., In order to show the effect on the Company of
both gas purchases the next position limit chart is for June 20 2001. Staff proposes that this chart
be viewed in three parts. July 2001 through November 2001 show positions that are long and
short but all within position limits. December 2001 through May 2002 show the time period that
Deal A gas is to be delivered. Positions are long and in 2 months slightly outside of position
limits. June 2002 through December 2002 is the period of time when gas is to be delivered to
generate power under both Deal A and Deal B. In general, positions are quite long and in all
month HLH or LLH energy or both are outside of position limits.
The calculation of the loss on the gas sales is shown on page one of Staff Confidential
Attachment 1. Staff calculated the purchase amounts of Deal A and B by multiplying 20 000
dth/day times the price, times the number of days in each month for each deal. Staff calculated the
sale amounts by multiplying the 20 000 dth/day times the number of days in each month times the
average 'weighted price for the month. Staff used workpapers supplied during the audit to
calculate the average monthly sales price received for sales of gas purchased and resold. When
the Company prepares DJ 042 entries (Diarized Journal 042), the average price per therm that the
gas is sold at is calculated. The worksheets Staff obtained during the audit provided the
information necessary to calculate sales price of the gas resold on a monthly basis. Staff used that
amount to calculate the loss on the sale of the gas.
The loss on the sale is the monthly difference between the purchase price of the 20, 000
therms per day of gas, and the sales price of the 20 000 thenns per day of natural gas.
Staff separated the loss between Deal A and Deal B. The amounts are then multiplied by
the jurisdictional allocation factor (33.18%, the Production and Transmission allocation ratio) and
then multiplied by 900/0 to reflect the customer portion after the 90/1 0 sharing.
Staff calculated the loss on each Deal for the months of November 2001 through June of
2003. Staff calculated the loss on each Deal for the months of November 2001 through June of
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STAFF COMMENTS SEPTEMBER 30, 2003
June 2003, in the amount of$5 849 100, with associated carrying charges of$87 343 , for a total
adjustment of $5 933,433.
Staff s decision to limit its recommendation to the losses associated vvith Deal B is due to
several factors. The most obvious is the market conditions faced by the Company at the time the
transactions were made. Forward prices for both natural gas and electricity were high for periods
beyond 18 months. The Company s existing Risk Policy was sufficiently broad to allow deviation
with sufficient authorization and without specific documentation. While the Policy needs to be
modified in this regard, Staff does not necessarily believe that an adjustment incorporating all
losses beyond the 18-month policy period is warranted. Finally, Staff cannot ignore the financial
impact that such an adjustment could have on the Company. While Avista s financial situation
has improved since 2001 , and Staff believes the Company can and should absorb the losses
associated with Deal B, cost recovery adjustment beyond that level could cause significant
, negative impact.
Rate Impact
Staff proposes that the loss on the sale of gas associated with Deal B be removed from the
PCA deferral account along with associated interest
The swaps on Deal B were-entered with Avista Energy. The electric operations have
claimed no dealings with Avista Energy so proper pricing mechanisms with safeguards have not
been established. Absent an approved mechanism, the affiliate transactions with A vista Energy
should be priced at the lower cost or market. Therefore, the losses on Deal B should be repriced at
market with the Company absorbing the loss rather passing it to customers through the PCA.
The loss on the sale of gas captured in the Idaho PCA deferral balance amounts to
849 100 and reduced interest amounts to $87 343 , which reduces the deferral balance to
$21 906 665 dollars as of the end of June 2003. Existing PCA rates are designed to recover
approximately $23.6 million in a year. If PCA rates were adjusted based on Staff s calculations
the rates vvould be reduced frorh19.4% to 18.00/0. However, Staff proposes that existing PCA
rates be continued until the next PCA regardless of the final decision reached in this case. Rates
can remain unchanged because in the future any differences between deferred costs and PCA
revenues including accrued interest will be trued-up. Staff Attachment L shows the deferral
STAFF COMMENTS SEPTEMBER 30, 2003
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balance as a result of Staff s adjustments.
CONSUMER ISSUES
The Application filed by A vista on August 11 , 2003 contained both the customer notice
and press release. Both met the requirements of IDAP A 31.21.02.102. A vista sent its customer
notifications beginning with customer bills on August 12, 2003 and ending September 11 , 2003.
The IPUC held public workshops in both Lewiston and Coeur d'Alene regarding Avista
proposed continuation of its 19.40/0 surcharge. One customer attended the Lewiston workshop and
no customers attended the Coeur d' Alene workshop.
From the time Avista filed its PCA and through September 29, 2003, the Commission
received 6 written comments from customers. The deadline for filing comments is September 30
2003. None of those who commented were in favor of the continuation of the surcharge.
One custon1er suggested in her comments that A vista implement a program similar to
V erizon ' s ITSAP program. The Idaho Telecommunications Service Assistance Program (ITSAP)
participants save $13.62 per month on local telephone bills. The program is mandated by Idaho
Code and monies are recovered from residential and wireless telephone users; it is not a program
initiated by Verizon. While some states have additional funds available for energy assistance for
low-income residents, Idaho does not mandate electric companies in Idaho to collect funds from
residential customers to assist low-income customers with energy costs. The customer added in
her comments that she qualifies for and receives heating bill assistance from the federally funded
energy assistance program called Low Income Home Energy Assistance Program (LIHEAP).
In July of2003 , Avista donated $50 000 to Project Share in north Idaho. Project Share is a
fuel fund that helps qualified customers pay heating bills. Although some states mandate electric
companies to donate to fuel funds, Idaho does not. Project Share monies come from the utility
company, customers, and organizations who voluntarily give donations. The administrator for
Proj ect Share in northern Idaho said the funds this year ani ved from A vista in July and some were
used immediately to help low income customers pay electric bills who needed power connected
run electric fans during this past summer s exceptionally high temperatures. Customers may
receive financial assistance from both LIHEAP and Project Share. Project Share is sometimes
used to assist those "vho might be in a wage group slightly above the income requirements needed
to receive federal LIHEAP funds.
STAFF COMMENTS SEPTEMBER 30, 2003
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Avista also continues to offer rebate programs to customers who convert to energy
efficient heating or water heating equipment.
A vista continues to promote Comfort Level Billing to help customers level out payments
over a twelve-month period. Comfort Level Billing is often a helpful budgeting tool for customers
\-vho have difficulty paying high bills in the heating months and yet have low electric bills in the
summer. Approximately 13 % of A vista s customers use Comfort Level Billing.
Since the last PCA was approved in October of2002 , the Commission s Consumer
Assistance Staff received 150 complaints and inquiries from customers regarding electricity
issues. Forty-five percent of those complaints and inquiries were related to credit and collection
issues, with the majority being about discolmection for non-payment of the customer s electric
bill. (These figures are typical for Idaho electric companies). The number of complaints and
, inquiries regarding electric issues decreased by 25% between the months of October 2002 through
September 2003 when compared with the corresponding time period of October 2001 through
September 2002. In both time periods, approximately one-half of the complaints were related to
disconnection of service for non-payment.
RE CO lVIMEND A TI 0 NS
Staff proposes that the Commission accept the filing with the following recommendations
and modifications. Staff specifically recommends that:
1. The current surcharge be continued until the next PCA filing regardless of the final
decision reached by the Commission in this case. Staff also recommends any actual
remaining deferral balance at June 30 2004 be subject to review by the Commission
prior to establishing a surcharge for an additional period of time, as provided for in
Order No. 28876, Case No. A VU-01-11.
2. The net fuel expense for losses on natural gas CT fuel sold rather than burned under
Deal B" be denied for recovery in the PCA in the amount of$5 849 100 and interest.
3. That the deferral balance be modified to include Staff s adjustments and corresponding
adjustments to the carrying charges.
4. The Conlpany work with the Commission Staff and customers in developing an
acceptable Risk Policy for the Utilities division of Avista Corporation.
Exhibit No. 139
Case No. A VU-O4-
, '
C ,\., ,J-u ,
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6/21/04 Page 16 of 30
ST AFF COMMENTS SEPTEMBER 30, 2003
Respectively submitted this
Technical Staff:Kathy Stockton
Maril yn Parker
Keith Hessing
i :umisc/commen ts/a vueO3. 6swklskhmp
STAFF COMMENTS
7'1\ day of September 2003.
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 17 of 30
SEPTEMBER 30, 2003
Idaho Public Utilities Commission
Staff Adjustment A
Interest Calculation
Avista Utilities Idaho PCA
Case No. AVU-O3-
6/30/2002 Balance excJudino interest 568 103 Interest
Jul-Deferral 927 566
PGE amortization RJ216 309 280)
Surcharge Amortization 822 555)
7/31/2002 Balance before interest 363 834
Interest ;:jj!;10j~~i~~9"7 /31/2002 Balance excludinq interest 363 834
Aug-Deferral 885 964
PGE amortization -RJ216 (2,309 280)
Surcharge Amortization (1,962 847)
8/31/2002 Balance before interest 977 671
Interest
8/31/2002 Balance excluding interest 977 671
Sep-Deferral 372 898
PGE amortization -RJ216 309 280)
Surcharge Amortization 917 598)
9/30/2002 Balance before interest 123 691
Interest ;j:i;:;:t;11~~~~~'9/30/2002 Balance excluding interest 123 691
Oct-Deferral 2,416 760
PGE amortization RJ216 309 280)
Surcharge Amortization 821,411)
10/31/2002 Balance before interest 409 760
Interest
10/31/2002 Balance excludinq interest 31,409 760
Nov-Deferral 364,437
Intervenor Funding Order 137
PGE amortization -RJ216 309 280)
Surcharge Amortization 069 140)
11/30/2002 Balance before interest 396 914
Interest :;I;(:ii!\il~Q~~~~~:'11/30/2002 Balance excluding interest 396 914
Dec-Deferral 348 526
PGE amortization -RJ216 (2,309 280)
Surcharge Amortization 317 523)
12/31/2002 Balance before interest 118 637
Interest
12/31/2002 Balance excludinq interest 118 637
Total Interest to Date 807 074
Deferral Balance 12/31/02 with Interest $30 925 711
Beqin New Interest Calculation Old Balance Continue Simple Interest on New Balance
Jan-Deferral $30 925 711 3,454 572
Surcharge Amortization 421,489)
1/31/2003 Balance before interest ?R 1:;".11.
???
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1/31/2003 Balance excludinq interest Balance 607 308 3,454 572
Feb-Deferral 245 118
Surcharge Amortization 227 385)
2/28/2003 Balance before interest 379 923 699 690
Interest 10~;:J;;:::!:liill~11i;11i;1;jl:j:
$~:~~~~~;
i;1jiji;;!itiA~;~~~;'2/28/2003 Balance excludinq interest Balance 26.475 2B1 699 690
Mar-Deferral 626 742
Surcharge Amortization (2,184 726)
3/31/2003 Balance before interest ?4 ?a" 1:;1:;1:;326 432
Interest j)lii)j;,;\iti~jl!I,I.ii:iii;I~~l~~~.jll,ji:;111!:jliizt~~~J;;3/31/2003 Balance excludinq interest Balance 378 806 326 432
Apr-Deferral 332 541
Surcharge Amortization 052 1 B7)
4/30/2003 Balance before interest ?? "I?~ ~ 1 9
.,..~~.~~~~.~?? ,
Interest .ll11jl)!~f~g~~I,:::i':ili\id,~1~S;'4/30/2003 Balance excludinq interest Balance 22,407 B82 658 973
May-Deferral 488 717
Surcharge Amortization 864 170)
5/31/2003 Balance before interest '0 !;4~712
;:j)j;ji!~~~~~~.Interest ill;;;;I;j;;i;:II!~!'!I.I!r~;~~~:5/31/2003 Balance excludinq interest Balance 618 405 147 690
Jun-Deferral 101 792
Surcharge Amortization 885 592)
6/30/2003 Balance before interest 1 ~~~I~~~~~~249.482
Interest
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6/30/2002 Balance excludinq interest Balance 1 B 801 541 249,482
Simple interest and $744 944
Compound interest $511 379
Total Interest for 2002-2003 PCA Period 256 323
Company accumulated interest for Jan 1 2003 through June 2003 $999 596
Difference due Case No.AVU-03-$256 727
Exhibit No. 139
Case No. A VU-04-
A VU-04-
K. Hessing, Staff
6/21/04 Page 18 of 30
Attachment A
Case A VU-03-
Staff ConTInents
9/30/03
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Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 20 of 30
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ATTACHMENT I IS CONFIDENTIAL
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 26 of
ATTACHMENT J IS CONFIDENTIAL
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 27 of 30
ATTACHMENT K IS CONFIDENTIAL
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 28 of 30
Idaho Public Utilities Commission
Staff Adjustment L
A vista Utilities Idaho PCA
Deferred Cost Balances
Case No. A VU-O3-
Company 2002-2003 Deferral Calculation
Deferral Activity Detail
Net Increase in Power Supply Cost
Centralia Capital and O&M Credit
PGE Monetization Accelerated Amortization
Transfer Small Generation Capital Costs and Interest
Intervenor Funding Payment
Interest
Company Deferral for July 2002 - June 2003 period
$23 383 629
817 996
$13 855 680
$921 184
138
999 596
789 5031
Staff 2002-2003 Adjustment to Deferral Balance
Staff Adjustment to Loss on Natural Gas Sales
Interest Adjustment due to Staff Adjustment
Adjust In~ef~$t C~lculation for Case No. AVU-03-
Total Staff Adjustment to Company Deferral for 2002-2003
!Staff Proposed Deferral for July 2002 - June 2003
849 100
$87 343
$256 727
679 716
109 787
Unrecovered Balance at June 30 , 2002
Staff Net Deferral Activity (July 2002 - June 2003)
Amortizations Related to Surcharge Revenues (July 2002 - June 2003)
, Unrecovered Balance at June 30, 2003
$45 600 228
109 787
$24 546 623
$22 163 392
Exhibit No. 139
Case No. AVU-04-
VU -04-
K. Hessing, Staff
6/21/04 Page 29 of 30
Attachment L
Case No. A VU-03-
Staff Comments
9/30/03
CER TIFI CA TE OF SER VI CE
HEREBY CERTIFY THAT I HAVE THIS 30TH DAY OF SEPTEMBER 2003
SERVED THE FOREGOING COlVIMENTS OF THE COMMISSION STAFF, IN CASE
NO. AVU-03-, BY MAILING A COpy THEREOF POSTAGE PREPAID TO THE
FOLLOWING:
DAVID J. MEYER
SR VP AND GENERAL COUNSEL
VISTA CORPORATION
PO BOX 3727
SPOKANE W A 99220-3727
KELLY NORWOOD
VICE PRESIDENT
VISTA CORPORATION
PO BOX 3727
SPOKANE W A 99220-3727
MAILED TO DON FALKNER AT:
dfalkner~avistacorp. com
SECRETARY
CERTIFICATE OF SERVICE
Exhibit No. 139
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 30 of 30
VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.
Idaho
A VU-O4-01 / A VU-O4-
IPUC
Data Request
Staff 27 -Supplemental
DATE PREPARED:
WITNESS:
RESPOND ER:
DEP ARTMENT:
TELEPHONE:
05/10/2004
R. Gruber
Energy Resources
[phone]
REQUEST:
A vista has recently relied on financial hedging to provide some level of natural gas price
stability. Please provide all data on all hedges executed from 1999 to present. Please provide
the analysis that indicates that maintaining this practice is preferred (operationally and/or
financially) to reacquiring all of Avista s storage resources.
SUPPLEMENTAL RESPONSE:
Avista s original response inadvertently omitted the data requested on all hedges executed from
1999 to present. A spreadsheet listing all hedges executed by A vista for Washington/Idaho for
the period requested is attached. These hedges are all fixed for float swaps and represent only
deals done for natural gas utility core load. All of the hedges with transaction dates up to and
including May 16, 2001 were executed by the Utility outside of the Benchmark Mechanism.
Hedges transacted after that date were executed by A vista Energy on behalf of the Utility as part
of the Benchmark Mechanism as modified effective April of 2002.
Exhibit No. 140
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 1 of 2
Avista Corporation
Benchmark Mechanism Evaluation
Natural Gas Prices Fixed for Washington & Idaho
Lock.in Quantity
Date DthiDa Term Basin Price
12/4/2000 5000 January 2001 through March 2001 Sumas 12.6500
12/4/2000 5000 January 2001 through March 2001 Alberta 200012/4/2000 5000 January 2001 through March 2001 Rockies 4000
12/4/2000 5000 January 2001 through March 2001 Sumas 12.650012/14/2000 4739 November 2001 through March 2002 Alberta 25 Cdn
2/5/2001 5000 November 2001 through March 2002 Rockies 0400
3/7/2001 5000 November 2001 through March 2002 Alberta 3000
3/7/2001 5000 April 2001 through October 2001 Alberta 16003/7/2001 5000 November 2001 through October 2002 Alberta 7750
3/7/2001 5000 April 2001 through October 2001 Rockies 7500
3/7/2001 5000 November 2001 through October 2002 Rockies 63504/23/2001 5000 November 2001 through October 2002 Alberta 8100
4/23/2001 5000 November 2001 through October 2002 Sumas 9000
5/2/2001 5000 November 2001 through October 2002 Sumas 25005/8/2001 5000 November 2001 through October 2002 Alberta 22005/15/2001 5000 November 2001 through March 2002 Alberta 7450
5/15/2001 5000 November 2001 through March 2002 Rockies 59505/16/2001 5000 November 2001 through March 2002 Sumas 7.30004/4/2002 3000 November 2002 through March 2003 Alberta 3300
4/4/2002 1000 November 2002 through March 2003 Rockies 42504/4/2002 1000 November 2002 through March 2003 Sumas 78005/22/2002 6000 December 2002 through January 2003 Alberta 74005/22/2002 2000 December 2002 through January 2003 Sumas 33505/22/2002 2000 December 2002 through January 2003 Rockies 77005/3012002 3000 December 2002 through February 2003 Alberta 52005/30/2002 1000 December 2002 through February 2003 Sumas 83005/30/2002 1000 December 2002 through February 2003 Rockies 59005/30/2002 3000 November 2002 through February 2003 Alberta 3.48005/30/2002 1000 November 2002 through February 2003 Sumas 75005/30/2002 1000 November 2002 through February 2003 Rockies 51006/13/2002 3000 November 2002 through March 2003 Alberta 33006/13/2002 1000 November 2002 through March 2003 Sumas 67006/13/2002 1000 November 2002 through March 2003 Rockies 30507/12/2002 6000 November 2002 through October 2003 Alberta 20007/12/2002 2000 November 2002 through October 2003 Sumas 35507/12/2002 2000 November 2002 through October 2003 Rockies 97507/14/2002 3000 November 2002 through March 2003 Alberta 20007/14/2002 1000 November 2002 through March 2003 Sumas 50007/14/2002 1000 November 2002 through March 2003 Rockies 07008/29/2002 3000 December 2002 through March 2003 Alberta 39708/29/2002 1000 December 2002 through March 2003 Rockies 3.20308/29/2002 1000 December 2002 through March 2003 Sumas 848011/7/2002 5890 December 2002 through March 2003 Alberta 3.405011/7/2002 2010 December 2002 through March 2003 Sumas 700011/7/2002 2010 December 2002 through March 2003 Rockies 29004/15/2003 2745 November 2003 through March 2004 Alberta 03504/15/2003 1005 November 2003 through March 2004 Sumas 53504/15/2003 1250 November 2003 through March 2004 Rockies 12006/13/2003 2010 November 2003 through March 2004 Sumas 67006/13/2003 5490 November 2003 through March 2004 Alberta 34506/13/2003 2500 November 2003 through March 2004 Rockies 28007/14/2003 2745 November 2003 through March 2004 Alberta 78507/14/2003 5490 April 2003 through October 2004 Alberta 02507/14/2003 2010 April 2003 through October 2004 Sumas 06007/14/2003 1005 November 2003 through March 2004 Sumas 15007/14/2003 2500 April 2003 through October 2004 Rockies 25807/14/2003 1250 November 2003 through March 2004 Rockies 25808/22/2003 2745 December 2003 through March 2004 Alberta 02508/22/2003 1250 December 2003 through March 2004 Rockies 11008/22/2003 1005 December 2003 through March 2004 Sumas 34008/14/2003 2745 November 2003 through March 2004 Alberta 81008/14/2003 1250 November 2003 through March 2004 Rockies 86008/14/2003 1005 November 2003 through March 2004 Sumas 11008/22/2003 5490 December 2003 through February 2004 Alberta 11508/22/2003 2500 December 2003 through February 2004 Rockies 19008/22/2003 2010 December 2003 through February 2004 Sumas 56008/22/2003 5490 December 2003 through January 2004 Alberta 11608/22/2003 2500 December 2003 through January 2004 Rockies 20108/22/2003 2010 December 2003 through January 2004 Sumas 570010/20/2003 2010 December 2003 through March 2004 Sumas 945010/20/2003 5490 December 2003 through March 2004 Alberta 655010/20/2003 2500 December 2003 through March 2004 Rockies 810010/31/2003 2500 October 2004 Rockies 060010/31/2003 2010 October 2004 Sumas 135010/31/2003 5490 October 2004 Alberta 045010/31/2003 2500 April 2004 Rockies 033010/31/2003 2010 April 2004 Sumas 003010/31/2003 5490 April 2004 Alberta 00304/14/2004 2500 November 2004 through March 2004 Alberta 5.46504/14/2004 1250 November 2004 through March 2004 Rockies 60504/14/2004 1250 November 2004 through March 2004 Sumas 6800
Staff DR-027 -Supp_Attach.xls Staff Data Request No. 27-Supplemental Response
Exhibit No. 140
Case No. A VU-04-
A VU -04-
K. Hessing, Staff
6/21/04 Page 2 of 2
5/10/2004
STAFF EXHIBIT NO. 141 IS CONFIDENTIAL
Exhibit No. 141
Case No. A VU-O4-
VU -O4-
K. Hessing, Staff
6/21/04
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