20031118Final Order No 29377.pdf

Office ofthe Secretary
Service Date
November 18, 2003
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE SUBMISSION OF
THE SCHEDULE 66 PCA STATUS REPORT
OF A VISTA CORPORATION AND
APPLICATION FOR CONTINUATION OF A
SCHEDULE 66 POWER COST
ADJUSTMENT (PCA) SURCHARGE ORDER NO. 29377
CASE NO. A VU-O3-
On August 11 , 2003, Avista Corporation dba Avista Utilities (Avista; Company)
filed a Power Cost Adjustment (PCA) electric 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 19.4% surcharge was originally authorized by the Commission in Order No. 28876 dated
October 11 , 2001 in Case No. A VU-Ol-l1. 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-In its Order continuing the surcharge, the Commission stated:
As we did last year, we find it reasonable to continue a close monitoring of
the Company s PCA decisions and thus require the Company to file a PCA
status report 60 days prior to the expiration of the PCA surcharge. As before
if the status report and our review of the actual PCA deferral balance supports
continuation of the surcharge, we anticipate continuation of the surcharge for
an additional term.
Order No. 29130, p. 16. The Idaho PCA deferral balance carried on the Company s books as of
June 30, 2003 is $27 843 108.
In this Order the Commission removes a Staff-proposed Coyote Springs II (Deal B)
net fuel adjustment ($5 849 100) with related interest pending further consideration of same in
the Company s next general rate case, removes a related Coyote Springs II (Deal A) net fuel loss
($5 935 948) with related interest also for later consideration, authorizes an interest adjustment to
comport with prior Commission Order No. 29323, approves a June 30, 2003 deferral balance of
$16 150 379 and pending further consideration authorizes a continued 12-month PCA surcharge
of 19.4%.
ORDER NO. 29377
Status Report - Application for Extension
The details of the deferred cost balance as reflected in the Company s PCA account
are as follows:
Unrecovered Balance at June 30, 2002
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
789 503 *
(24.546,623)
$27 843 108
Deferral Activity Detail
Net Increase in Power Supply Cost
Centralia Capital and O&M Credit
PGE Monitization Accelerated Amortization
Transfer Small Generation Capital Costs & Interest
Intervenor Funding Payment
Interest
Net Deferral Activity (July 2002 - June 2003)
$23 383 629
817 996)
(13 855 680)
( 921 184)
138
999.596
$ 6 789 503
During the review period, Avista reports that Idaho s share of power supply expenses
exceeded the authorized level by $25 924 662. The Company states that power supply expenses
were higher than the authorized level due to several factors:
The largest factor was the sale of fixed price gas. Based on the average
purchase and sale price, the fixed price gas purchases added approximately
$13.1 million to Idaho s share of power supply expense. Hydro-generation
was approximately 12.9 aMW below the authorized level, which would
account for approximately $2.1 million of increased expense. Colstrip and
Kettle Falls together generated approximately 8 aMW above the authorized.
Rathdrum generated approximately 21 aMW below the authorized level due
in part to the relatively low price of electricity compared to natural gas costs.
The Company s other gas-fired generating plants, Northeast Turbine, Boulder
Park, and the Kettle Falls Combustion Turbine generated 2 aMW during the
period.
Other power supply expenses during the review period include a payment to
terminate a long-term power purchase with Enron and the final lease
payments of $3.7 million ($1.3 million Idaho share) related to the Kettle Falls
Bi-Fuel generating units. The $2.million Enron buy-out payment
($960;000 Idaho share) occurred in October 2002, and was recorded as a
power purchase expense. The Kettle Falls Bi-Fuellease payments began in
September 2001 and were included in the prior filing for the review period
ending June 2002;
ORDER NO. 29377
Another factor driving the deferrals is the age of the authorized case. The
authorized case is based on loads, contracts and resources in place for the
period July 1999 through June 2000. During that period, the Company had
several large off-system power sales that generated significant revenue.
Almost all of the sales have ended and, as such, the revenue is reduced which
is reflected in a reduction in Account 447, Sale for Resale, revenue of $72
million on a system basis ($24 million Idaho share). Purchased power
expense has also decreased from the authorized level due in part to several
long-term contracts ending. Purchased power expense, however, has
decreased by only $24 million on a system basis ($8 million Idaho share).
The Company plans to file a general rate case within the next year to reset the
authorized level of power supply revenues and expenses.
A vista contends that continuation of the current surcharge is not only justified by the
current level of unrecovered power cost deferrals, but is essential to the continued improvement
in the financial health of the Company. Investor concerns surrounding cash flows , deferral
balances, and the ability to recover costs in a timely manner, the Company states, have had an
impact on the Company s financings. The Company s credit ratings were lowered by credit
rating agencies to below investment grade in October 2001. Because of Avista s present credit
ratings, debt is more expensive. A vista contends that it is imperative for both the Company and
its customers that A vista continue to improve its financial condition so that investment grade
credit ratings can be restored and so that longer-term debt can be refinanced on more reasonable
terms.
Current proj ections indicate that with continuation of the 19.4% surcharge, the PCA
deferral balance would reach zero in mid-2005. The actual point when the deferral balance
reaches zero is dependent upon factors such as hydroelectric conditions, wholesale market prices
contract changes, etc., during the relevant period.
The Company requests that the Commission continue the PCA surcharge for an
additional 12 months, beginning October 12, 2003 and continuing through October 2004.
The Company requests that its Application be processed pursuant to Modified Procedure, i., by
written submission rather than by hearing.
On August 27, 2003, the Commission issued a Notice of the Company s PCA filing
and scheduled dates in Lewiston (Sept. 08) and Coeur d' Alene (Sept. 09) for customers to
ORDER NO. 29377
discuss Avista s PCA/energy issues with Commission Staff. The Commission in its Notice also
made a preliminary determination as to the appropriateness of processing the Company
Application under Modified Procedure, i., by written submission rather than by hearing, and
established a September 30, 2003, comment deadline. Reference IDAPA 31.01.01.201-204.
Comments were filed by Commission Staff and a few of the Company s customers.
On October 8, 2003, the Commission issued Order No. 29351 continuing the existing
19.4% Schedule 66 PCA surcharge for 60 days beyond the scheduled October 11 , 2003
expiration or until such time as the Commission might issue an Order accepting, rejecting or
modifying the Application in Case No. A VU-03-06. The extension was authorized to provide
the Company an opportunity to file a written reply to Staff comments and to make a procedural
recommendation regarding Staff's proposed net fuel adjustment ($5 849 100).
STAFF COMMENTS
Staff recommends a $5 849 100 adjustment (net fuel expense for losses on natural gas
combustion turbine (CT) fuel sold rather than burned) to the deferral balance, a related
adjustment for carrying charges ($87 343), a $256 727 interest rate adjustment to conform with a
prior Commission Order, and a continuation of the existing 19.4% surcharge with true-up in the
Company s next PCA filing. Staff also identifies a shortcoming and needed change in the
Company s Risk Management Policy.
Staff performed a review and audit of the amounts that went into the Company s PCA
deferral balance. Other than the net fuel expense item, Staff found the amounts recorded in the
purchased power, thermal fuel, CT fuel and power sales accounts to be correct and recommends
that they be included in the deferral balance as of June 30 2003. Staff notes that the Pacific Gas
& Electric (PGE) credit is now fully amortized and will not be included in future PCA deferrals.
In the current PCA filing, the PGE credit contributed $13 855 680.
Interest Rate PCA Deferral Balance
Staff notes that on May 16 2003, Avista filed an Application in Case No. A VU-03-
4 requesting that the interest rate for the Company s Power Cost Adjustment (PCA) deferral
balance be set at a level higher than the rate for customer deposits. Staff and the Company
agreed to a compromise solution adopted by the Commission in Order No. 29323 , dated
August 21 , 2003. As reflected in the Commission s Order, a 200 basis point increase will be
allowed in the interest applied to year end deferral balances during recovery based on the first
ORDER NO. 29377
in/first out (FIFO) method of accounting. The customer deposit interest rate would continue to
apply to new deferral balances accrued during the calendar year. This interest rate methodology
began January 2003 and continues through June 30, 2005. The new interest methodology was
not applied in the current PCA case filed by the Company. Staff includes the results of the new
interest methodology in its current PCA year deferral balance calculations and proposes the same
for Commission . consideration. The result of Staff's adjustment increases the current year
deferral amount by $256 727. This amount reflects the application of a 200 basis point adder to
the current year s customer deposit rate of 2%, calculated on the existing balance throughout the
months of January through June 2003; and the application of the customer deposit rate of2%
the new deferrals, which continue to be calculated at simple interest.
As reflected in Staff's comments , the largest component of the Company s net
deferral activity for the current period of July 2002 through June 30 2003, is the Net Increase
in Power Supply Costs. The total net increase in power supply costs, $23 383 629 is comprised
of the following items:
1. Purchased Power
2. Thermal Fuel
3. CT Fuel
4. Sales for Resale
5. PGE Capacity Revenue True Up
6. Potlatch 25 aMW
7. Kettle Falls Bi-Fuel
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
* includes $578 748
No. A VU-02-
removed Commission
($7 083 766)
($5 942 944)
($948 195)
$21 605 030
($2 483 328)
260 572
102 506
$11 817 650 *
$651 882
$352 788
$51 434
III Order CaseNo. 29130
Net Fuel Expense Loss on Natural Gas Resold
Staff in its comments speaks to each component of power supply costs and
specifically addresses the Net Fuel Expense portion. In the Company s last PCA case, A VU-
02-, Staff questioned the circumstances surrounding the acquisition and later sale of natural gas
purchased by the Company to fuel the Coyote Springs II (Coyote) CCCT (combined cycle
combustion turbine). The Company in that case maintained that at the time natural gas was
ORDER NO. 29377
purchased, it was anticipated that Coyote would be operational and more economical to operate
than making market energy purchases. As it turns out, Coyote was neither operational nor was it
economical to use the gas purchased for Coyote at the Company s other facilities. Instead
A vista simply purchased its power needs on the electric market and sold the gas back into the gas
market at a loss because gas prices also had declined.
In Case No. A VU-02-, Staff proposed that the Commission withhold judgment on
$578 748 in net fuel expense incurred in June of 2002 to serve Coyote 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 the use of the plant. Pending further investigation, the
Commission in its Order removed the $578 748. As part of its current PCA investigation, Staff
has completed a comprehensive review of the gas purchase and sale transactions that generated
losses on fuel resold and the excess net fuel costs requested for recovery in this case. The results
of Staff's investigation are set forth in its Comments.
Staff recounts two contracts (purchases and financial swaps) entered into by A vista in
March 2001 to secure gas and gas transportation for Coyote Springs II, i., Deal A and Deal B.
The first gas supply contract (Deal A) was to be delivered November 1 , 2001 through
November 1 , 2004. The price for October 2004 gas was locked three and one-half years into the
future. Staff investigation reveals no documentation analyses beyond October 2002. Additional
analyses that should have been fully documented with the swap order, Staff contends, should
have included volatility analyses, price trend analyses and load requirements for the time period
involved.
The second gas supply Contract (Deal B) in Case No. A VU-02-, was for delivery
to begin June 1, 2002 and continue through October 31 , 2003. The October 2003 price was
locked two and one-half years into the future. The $578 748 previously removed pending further
evaluation was for Deal B gas. The net loss attributed to Deal B gas has increased to $5 849 100
(as of June 30, 2003). Staff contends that the Deal B purchase was speculative and put the
Company in a long position outside established risk management limits.
Avista s Risk Management Policy
Pursuant to Commission direction in last years' Order No. 29131 , Staff investigated
and assessed the reasonableness of Avista s Risk Management Policy (Staff Confidential
Attachment J) and how it affects the Company s short-term resource acquisition decisions. The
ORDER NO. 29377
Company s Risk 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 and 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. As reflected in the
Company s Risk Policy "this policy is intended to focus on short-term power and natural gas
supply management, meaning the period of 18 months forward from any current date, as they
relate to meeting near-term energy load obligations." Such a plan, Staff contends, 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 states it does not oppose entering into financial swaps or hedges to fix
the price of gas. However, the gas deals that Avista entered into for Coyote, Staff contends
were unusual. Staff is concerned about the length of the swaps and the apparent lack of
additional support 2 ~ and 3 ~ years in the future. A vista Electric, Staff states, had no recent
history of entering into purchase or sales arrangements that went outside of its normal 18-month
position report planning period. Nor during this period did Avista Gas operations make
purchases outside of a 12-month period that it uses to balance its gas need for its gas customers.
Staff believes that the losses on the sale of gas from the two purchases for Coyote 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 ~ years after the date of the purchase. The risk substantially stems from
the price paid, the fact that the price was established at only two points in time approximately 30
days apart, gas price levels and trends over time, the volume of gas purchased, the lack of
forward analysis and the duration of the purchases.
The risks incurred by the Company related to Coyote could have been reduced, Staff
contends, if smaller quantities of two, three or five thousand dth/ day (decatherms/ day) had been
purchased over time instead of four financial swaps entered into over the period of a month
totaling 40 000 dth/day for much of the entire three 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, Staff contends that it failed to mitigate the risk by also securing
some mechanism to lock into the power sale of the transaction for the excess energy. Staff
contends that the Company s decisions were contrary to principals of good risk management.
ORDER NO. 29377
The Company s Risk Policy allows for purchases that exceed 18 months in the future with
proper authorization. Although the Deal A and B purchases were authorized, Staff contends that
the documentation to support these substantially longer transactions is lacking. The Deal tickets
provided some explanation as to why the long-term 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 project. To the extent that the transactions were
made for the purpose of financing Coyote, Staff contends that they were to meet A vista s cash
flow requirements and were not necessarily associated with utility operations.
While Staff is critical of the Company with respect to its overall gas acquisition
approach for Coyote, both Deal A and Deal B, Staff limits its recommended adjustment to only
losses associated with Deal B during the period from June 2002 through June 2003. The Deal B
purchase, Staff contends, put the Company in a long position outside of established risk
management limits. The Deal B purchase, Staff contends, was speculative because the
generation was not needed for load; it focused on future price changes and was not documented
and shown to reduce "business risk." Staff notes that the swaps on Deal B were entered with
Avista Energy. The Company s electric operations have claimed no dealings with Avista Energy
so proper pricing mechanisms or safeguards have not been established. Absent an approved
mechanism, the affiliate transactions with Avista Energy, Staff contends, should be priced at the
lower cost or market. Staff recommends that the losses on Deal B be repriced at market with the
Company absorbing the loss rather than passing it to customers through the PCA. Staff
recommends disallowing the losses from Deal B for the months of June 2002 through June 2003
in the amount of $5 849 100, with associated carrying charges of $87 343 , for a total adjustment
of$5 933 433.
Existing PCA rates are designed to recover approximately $23.6 million in the period.
IfPCA rates were adjusted based on Staff's calculations the rates would be reduced from 19.4%
to 18.0%. 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 in its filed comments proposes that the Commission accept the Company s PCA
filing with the following recommendations and modifications:
ORDER NO. 29377
1. The current 19.4% 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 any additional period of time, as provided for in Order No. 28876
Case No. A VU-Ol-l1.
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 $87 343
interest.
3. That the deferral balance be modified to include Staff's adjustments and
corresponding adjustments to the carrying charges.
4. The Company be required to work with the Commission Staff and customers in
developing an acceptable Risk Policy for the utilities division of Avista Corporation.
CUSTOMER COMMENTS
The Commission Staff held public workshops in both Lewiston and Coeur d' Alene
regarding Avista s proposed continuation of its 19.4% surcharge. Only one customer attended
the Lewiston workshop. No customers attended the Coeur d'Alene workshop. From the time
Avista filed its PCA through September 29, 2003, the Commission received six written
comments from customers. The deadline for filing comments was September 30 2003. None of
the customers who commented were in favor of the continuation of the surcharge.
Staff in its comments recounts the energy assistance programs available for low-
income customers. Staff notes that Avista continues to offer rebate programs to customers who
convert to energy efficient heating or water heating equipment. The Company also continued to
promote Comfort Level Billing to help customers level out payments over a 12-month period.
COMPANY REPLY
On October 3, 2003 , Avista filed Reply Comments. Avista does not agree with
Staff's recommended disallowance of approximately $5.9 million of deferred costs associated
with certain natural gas costs for Coyote thermal generation. The transactions related to the costs
at issue, the Company contends, were entered into in the spring of 2001 , at a time when
wholesale electric prices were at unprecedented highs, federal regulators were continuing to
refuse to intervene, and A vista was facing the worst hydroelectric conditions in its history. The
Company believes that a careful review of the information available at the time the transactions
ORDER NO. 29377
were entered into will show that the Company s decisions were reasonable given the
circumstances at the time.
Avista requests the opportunity to fully respond to Commission Staff's recommenda-
tions through evidentiary hearings. Avista contends that it would be administratively more
efficient for the Company to respond to Staff's recommendations in its upcoming general rate
case, which A vista plans to file in the first quarter of 2004. If evidentiary hearings were to
proceed in this case, the Company contends that they would likely overlap the general rate case
proceedings. Staff does not oppose the Company s procedural recommendation.
A vista recommends continuation of the existing surcharge rates until the next PCA
(through October 11 , 2004). Avista commits to fully respond to the issues raised by Staff in this
case, in its pre-file testimony in a general rate case, to be filed by the Company no later than
March 31 , 2004.
COMMISSION FINDINGS
The Commission has reviewed the filings of record in Case No. A VU-03-
including the comments and recommendations of Commission Staff and Company customers.
The Commission has also reviewed the Company s Reply Comments and procedural
recommendation. The Commission continues to find it reasonable to process this case pursuant
to Modified Procedure. Reference IDAP A 31.01.01.204.
Avista has requested recovery of excess power costs deferred through June 30, 2003
($27 843 108) and further continuation of a 19.4% ($23.6 million) PCA surcharge.The
Commission Staff in its filed comments recommends a disallowance of $5 849 100 in net fuel
expense (losses on sale of Coyote Springs II Deal B gas) together with $87 343 in related
carrying charges, for a total net fuel adjustment of $5 933,443. Staff contends that the purchase
was speculative and put the Company in a long position outside of established risk management
limits. Avista in its filed Reply requests the opportunity to fully respond to Staff's proposed net
fuel adjustment. The Company requests that the issue be deferred until the Company s next
general rate case, to be filed no later than March 31 , 2004. Staff does not oppose the Company
request. The Commission in reviewing Staff's Comments finds that many of the arguments
advanced by Staff as to Coyote Deal B gas are equally applicable to Coyote Deal A gas. In both
cases, it is alleged that gas was purchased and prices were locked in as of a single point in time
for future delivery, Deal A gas at 3-1/2 years into the future and Deal B gas at 2-112 years into
ORDER NO. 29377
the future. Both Deal A and Deal B purchases extend beyond the Company s normal 18-month
position report planning period (reference Avista s Energy Resources Risk Policy-Staff
Confidential Attachment J). In both cases, there is alleged to be a lack of sufficient analysis and
documentation for the time period involved.We therefore find it reasonable to defer
consideration of all losses related to Coyote Springs II gas for future consideration, both Deal A
and Deal B gas. The Commission finds that the public interest and the interest of the Company
customers will not be harmed by deferring consideration of Staff's proposed Coyote Deal B net
fuel adjustment and the Commission deferred Coyote Deal A losses until the Company s next
general rate case, to be filed no later than March 30, 2004. In doing so, we expect the Company
to present any arguments it may have regarding recovery of losses associated with Coyote Deal
A and Deal B gas as a separate and distinct part of its direct testimony filing.
We find that Staff's proposed interest adjustment ($256 727) comports with our prior
Order No. 29323 in Case No. A VU-03-4 and we accordingly find it reasonable to approve
same.
This filing by the Company has provided the Commission with an opportunity to
revisit the Company s PCA deferral account, its hydro position and its related power
purchase/sale transactions. The level of the Company s PCA deferral balance and the annual
surcharge rate requested permit us to defer a decision regarding the losses assocated with Deal A
and Deal B gas for Coyote Springs II and to conduct further proceedings and consideration of
same in the Company s anticipated general rate case without suspending or reducing the existing
19.4% surcharge. We remove Staff's proposed net fuel adjustment ($5 849 100) and related
interest adjustment ($87 343) pending further consideration. We also remove pending further
consideration the related losses associated with Coyote Deal A gas ($5 935 949) and related
interest ($77 064). The unrecovered Idaho PCA deferral balance as of June 30, 2003, that we
approve in this Case is $16 150 379. See Attachment A to this Order.
Staff in its comments raises concerns regarding the Company s risk management
policy as it pertains to long-term fuel supply contracts for periods extending greater than
months. We find it reasonable to direct A vista to work with Staff and interested customers to
address this concern. We expect the Company to present an acceptable risk management
protocol for long-term sales or purchases as part of its PCA deferred case in its rate case filing.
ORDER NO. 29377
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over A vista Corporation dba
Avista Utilities and the issues raised in Case No. A VU-03-06 pursuant to the authority granted
the Commission in Idaho Code, Title 61 and pursuant to the Commission s Rules of Procedure
IDAPA 31.01.01.000 et seq.
ORDER
In consideration of the foregoing and as more particularly described above, IT IS
HEREBY ORDERED and the Commission does hereby authorize a continued 12-month electric
Schedule 66 Power Cost Adjustment (PCA) surcharge of 19.4% ($23.6 million) for an effective
date of October 12, 2003. (Reference Order No. 29351). Avista is directed to file a PCA status
report with the filing of the Company s next electric general rate case and 60 days prior to
expiration of the authorized surcharge.
IT IS FURTHER ORDERED and the Commission approves Staff's proposed
adjustment increasing the current year s deferral amount by $256 727 to be effective January 1
2003 , to reflect the Commission approved change in the PCA interest rate methodology.
Reference Order No. 29323, Case No. A VU-03-
IT IS FURTHER ORDERED and the Commission defers decision regarding losses
on the sale of Coyote Springs II Deal A ($5 935 949 plus $77 064 interest) and Deal B
($5 849 100 plus $87 343 interest) gas pending further consideration in the Company s next
electric general rate case , to be filed no later than March 31 , 2004. The Commission approves
subject to further consideration and true-up an unrecovered Idaho PCA deferral balance as of
June 30, 2003 , of$16 150 379. See Attachment A to this Order.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) may petition for reconsideration within twenty-one (21) days of the
service date of this Order with regard to any matter decided in this Order. Within seven (7) days
after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code ~ 61-626.
ORDER NO. 29377
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 1111--
day of November 2003.
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~E.
Commission Secretary
vld/O:A VUEO306 sw2
ORDER NO. 29377
Idaho Public Utilities Commission
A vista Utilities Idaho PCA
Deferred Cost Balances
Remove Deal A and Deal B for Future Consideration
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
ICompany Deferral for July 2002 - June 2003 period
Commission 2002-2003 Adjustment to Deferral Balance
Commission Adjustment to Loss on Natural Gas Sales - Deal A
Interest Adjustment due to Commission Adjustment - Deal A
Commission Adjustment to Loss on Natural Gas Sales - Deal B
Interest Adjustment due to Commission Adjustment - Deal B
Adjust Interest Calculation for Case No. AVU-03-
Total Commission Adjustment to Company Deferral for 2002-2003
ICommission Deferral for July 2002 - June 2003
Unrecovered Balance at June 30, 2002
Commission Net Deferral Activity (July 2002 - June 2003)
Amortizations Related to Surcharge Revenues (July 2002 - June 2003)
Unrecovered Balance at June 30 2003
$23 383 629
817 996
$13 855 680
$921 184
138
999 596
789 503
935 949
$77 064
849 100
$87 343
$256.727
$11 692 729
903 226
$45 600 228
903 226
$24 546 623
$16 150 379
ATTACHMENT A
ORDER NO. 29377
CASE NO. A VU-O3-