20030508Comments.pdf

LISA D. NORDSTROM
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5733
F!LED
RECEIVED
2003 MAY -8 PI~ 4: 38
\);,) r'UdLiC
UTILI! IlS CGi"\i'iISSION
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 APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY)
TO IMPLEMENT A POWER COST
ADJUSTMENT (PCA) RATE FOR ELECTRIC
SERVICE FROM MAY 16, 2003 THROUGH
MAY 15, 2004.
CASE NO. IPC-03-
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Lisa D. Nordstrom, Deputy Attorney General, and in response to the Notice
of Application, Notice of Modified Procedure and Notice of Comment Deadline issued in Order
No. 29229 on April 17, 2003, submits the following comments.
On April 15, 2003 , Idaho Power Company (Idaho Power, Company) filed an Application
with the Commission for authority to decrease Power Cost Adjustment (PCA)! rates. Idaho
Power supplies electricity to approximately 380 000 customers in southern Idaho. The PCA
mechanism is traditionally comprised of two major components: 1) true up of abnormal
Company power supply costs collected during the preceding twelve (12) months, and 2) the
1 In March 1993, the Commission authorized Idaho Power to file proposed Power Cost Adjustment (PCA)
surcharges or rebates to take effect in May each year. Order No. 24806 (Case No. IPC-92-25).
STAFF COMMENTS MAY 8, 2003
projection2 ofthe next year s power supply costs based on expected3 Snake River stream flows
and storage. This year the PCA contains a third component for amounts small commercial
industrial and irrigation customers carried over from last year to this year, thus reducing the
amount of their respective rate decreases. The Company s request, if approved, would decrease
its overall revenues by approximately $114 million and lower overall rates by an average of
18.2% effective May 16, 2003.
STAFF ACCOUNTING ANALYSIS
Staff performed an audit of the Company s revenues and expenses associated with the
proposed surcharge. The audit included a detailed review of: 1) purchased power and power
sales; 2) Commission Orders allowing additional items to flow through the PCA accounts; 3) the
implementation of the Astaris Voluntary Load Reduction Stipulation and payments; 4) the
natural gas and transportation purchases for the Danskin facility; 5) the IDACORP Energy
proposed settlement; 6) the Risk Management Committee process and documentation; and 7)
other true up expenses and credits. Staff presents the following findings and recommendations.
Power Supply Purchases and Sales
Staff has performed a detailed audit of the Company s electricity purchases and sales
made during the last PCA year. Idaho Power purchased from and sold day-ahead and real-time
energy to only IDACORP Energy (IE) through July 31 2002. Staff verified that the day-ahead
energy purchased from IE was priced at the Mid-C index as authorized by the Commission in
past Orders.4 After July 31 2002, Idaho Power used in-house traders to buy and sell energy
using a variety of counter parties, but continued to supply IE with load following purchases and
sales through December 31 , 2002. These transactions were associated with a load following
contract IE had with a third party.
2 The Company may recover 90 percent of the difference between the projected power cost and the Commission
approved base power cost. Order No. 25880.
3 This forecast is based upon an Aprill projection of April through July Brownlee inflow.
4 See Order No. 28852.
5 Load following requires a service provider to make available energy supplies to meet moment-to-moment
demand in the distribution system served by its customer, and/or keep generating facilities available to
insure that it is providing neither too little nor too much energy to supply the customer s needs.
STAFF COMMENTS MAY 8, 2003
In its Application, the Company proposes to price the real-time transactions with IE
based on the weighted average of all IE real-time transactions. This methodology is consistent
with what the Company used in the last PCA.6 Staff has reviewed the Company s analysis and
confirmed that customers receive a greater benefit using this methodology during three of the
four months Idaho Power used IE to manage its real-time needs than they would have had with
the Federal Energy Regulatory Commission s (FERC) proposed high-low methodology.? During
the fourth month, July 2002, the energy needs were more expensive under the weighted average
methodology than under the high-low methodology. This result may be due to the winding down
oftrading operation at IE with fewer transactions to calculate the weighted average from June
2002 forward. As of this date, Idaho Power s case before the FERC has not been resolved as to
the pricing mechanism for real-time power. In its March 17, 2003 proposal to the FERC, Idaho
Power committed to give its customers the benefit of the best mechanism. The Company stated:
The Settlement revises the real-time pricing in the Agency Agreement to use the
real-time methodology preferred by the IPUC or the Applicants' May 14 2001
compliance filing proposal, whichever is more favorable to Idaho Power over the
life of the Agreement
In other words, the Company proposed to the FERC that the customers receive the best
treatment possible to help avoid gaming the system by IE. Staff recommends that the
Commission accept the first three months of real-time pricing as proposed by the Company using
the weighted average methodology because it is more favorable for customers. For the month
July, Staff recommends that the Company use the high-low methodology for calculating the real-
time prices because it provides greater customer benefits than the weighted average
methodology. Staff believes that in this case, it is reasonable to compare methodologies on a
monthly basis given the purpose of the settlement to resolve pricing discrepancies between Idaho
6 During the PCA period ending in March 2002, the Company proposed changing its real-time transaction pricing
from the FERC methodology to a weighted average methodology. See Case No. IPC-02-2 and IPC-02-3 and
Order No. 29026.
7 The FERC proposed that real-time purchases by Idaho Power from IE be priced at the lowest price IE was willing
to sell to another entity during that hour. Conversely, real-time sales from Idaho Power to IE shall be priced at the
highest price IE pays for power to another entity during that hour. The Company states that this method is not as
advantageous to customers as the weighted average method. The Company has performed an analysis that shows
customers benefit more using the weighted average method during three of the four months during the PCA period
Idaho Power s real-time needs were managed by IE.
8 The Company s settlement proposal was sent to the FERC on March l7, 2003 by the Company attorney Gary
Morgans. The section referred to by Staff is found on page 3 of the settlement proposal.
STAFF COMMENTS MAY 8, 2003
Power and IE. The Company assured FERC that it would use the methodology most favorable
for Idaho Power and its customers over the life of the agreement. A difference in methodologies
for the month of July 2002 is reasonable due to the change in operations resulting from the
winding down of trading at IE. Ratepayers should receive the benefit on a monthly basis and not
be penalized for changes in operations at IE. After the month of July 2002, it is no longer
necessary to compare methodologies because Idaho Power began managing its own real-time
needs. Staff recommends that $50 242.47 be removed from July 2002 purchases and sales to
reflect this pricing procedure. After jurisdictional and Company sharing, customers would
receive a benefit of$38,435.49.
While conducting its audit, Staff identified a missing payment from IE to Idaho Power
relating to a contract termination with Montana Power. When Staff asked the Company why the
payment had not been made, it was stated that IE personnel had inadvertently forgotten and
would forward the amount immediately. Staff proposes to flow through the $63 229.16 relating
to the IE payment to customers during the month of September 2002 when it should have been
made. After jurisdictional and Company sharing, customers would receive a benefit of
$48 370.32.
Astaris Voluntary Load Reduction Payments and Credits
On April 10, 2001 in Order No. 28695 , the Commission approved a Letter Agreement
between Idaho Power and Astaris to receive payments from Idaho Power for a 50 MW firm load
reduction at its Pocatello manufacturing facility. This load reduction was made available to
Idaho Power for 24 months beginning April 1 , 2001 and ending March 31 2003. In Case No.
IPC-01-, the Commission authorized an investigation regarding payment amounts and the
circumstances surrounding the Letter Agreement. As a result of that investigation, the
Commission issued Order No. 29050 authorizing a settlement and stipulation between all the
parties. The settlement provided that the Voluntary Load Reduction (VLR) payments Idaho
Power makes to Astaris under the terms of the Letter Agreement will be reduced by $5 000 000.
The benefit of this reduction will flow through Idaho Power s PCA mechanism to the general
body of ratepayers. Idaho Power has also agreed that its jurisdictional PCA share of the VLR
savings, approximately $425 000, shall be distributed to Idaho ratepayers through the PCA
mechanism. Finally, the parties agreed that the remaining $1 million Astaris take-or-pay credit
will be included in the 2002/2003 PCA true p balance without any reduction, as will the
STAFF COMMENTS MAY 8, 2003
$275 663 adjustment for uncollected Astaris take-or-pay obligations. Staff has reviewed the
payments Idaho Power made to Astaris and verified that the amounts were paid and passed
through the PCA in accordance with the Commission Orders as set out in the stipulation.
Natural Gas and Transportation Purchases
In March 2001 Idaho Power entered into a long-term agreement with Northwest Pipeline
to receive firm gas transportation from the Sumas gas delivery region to its Danskin facility in
Mountain Home, Idaho.9 In addition to that contract, the Company signed a short-term
agreement with IGI Resources (IGI) to purchase gas and resell any of its unused transportation.
As the ending date ofthe IGI contract approached in October 2002, Idaho Power began to search
for a new service provider to manage the Company s transportation and nomination needs, plus
provide the natural gas necessary to run its facility. According to the Company, IGI was the only
company available that could meet all ofldaho Power s needs and credit requirements. The
Company entered into another short-term contract with IGI to manage its transportation and
provide various other services. The new IGI contract expires in March 2004. Staff recommends
that the Company undertake an RFP process before the expiration of the current IGI contract to
see if IGI or other marketers could provide the same or better services at a price that is more
advantageous for customers.
IDACORP Energy Proposed Settlement
In September 2002 Idaho Power announced that it had failed to properly disclose three of
its wholesale transactions with IE to the FERC. The three transactions included ancillary
services and power sales that IPC provided to IE. Idaho Power has since reported the
transactions and is working with the FERC enforcement division to develop an acceptable
settlement amount to be passed on to customers.
Idaho Power believes a settlement with the FERC is imminent and recommends that a
portion of the settlement proceeds flow through the PCA accounts to customers. The proposed
settlement is based on the net revenues IE received from the three contracts less the amounts IE
has already paid to Idaho Power for these services. According to the Company, the total value of
9 On March 22, 200l the Company entered into an agreement with Northwest Pipeline to transport gas from the
Sum as region to the Company s Danskin facility. The Contract provides firm transportation until February 28
2007.
STAFF COMMENTS MAY 8, 2003
the three agreements is $5 826 186. During this PCA period and the prior period, Idaho Power
has already received a total of$4 043 866 relating to the three contracts. The proposed
782 320 settlement is the difference between these two amounts.
Staff has reviewed the proposed settlement and agrees that it is appropriate for customers
to receive a benefit in the current PCA. The settlement involves three contracts. Idaho Power
claims one of the contracts, the Truckee-Donner contract, has no additional effect on the PCA
because Idaho Power has already received the full value of the contract, $5 730. Staffhas
identified the Truckee-Donner agreement as one that will be further explored in the IPC-01-
process. Idaho Power agrees that IPC- E-O 1-16 is the proper case for this review. The final
determination of issues and any settlement amounts will be presented for the Commission
decision in Case No. IPC-01-16.
The second contract relates to a load following agreement with Montana Power for
capacity and energy. Idaho Power proposes to credit customers $1 165 191.47 before any
jurisdictional or Company sharing for the previously unpaid benefits IE received from this
contract. Staff accepts this adjustment as reasonable for this PCA.
The final contract relates to spinning reserveslO the Company provided to IE for the Tri-
State contract. In its proposed settlement, Idaho Power and IE recommend that Idaho Power pay
$428 625 for transmission costs that IE allegedly incurred while servicing this contract. Staff
does not believe it is reasonable to charge customers this amount under the PCA mechanism
because it relates to transmission payments that are not normally included in the PCA
mechanism. Transmission costs and benefits have been identified as an issue to be further
considered in IPC-01-16. Ifldaho Power agrees to this settlement payment with the FERC
then Idaho Power should bear the cost of that transmission. Staff recommends removal of the
$428 625 relating to the transmission payments that Idaho Power would have to bear under the
proposed settlement until the proper treatment of transmission is resolved in IPC-01-16.
The Company proposes allocating the settlement between Idaho and its other customers
based on the current Idaho jurisdictional allocation factor of 85%. In addition, the Company
recommends sharing the remaining amount based on the 90/10 split normally used when
allocating surplus power sales. Staff agrees that customers should receive the benefits of the
10 Spinning reserve is back-up energy production capacity that can be made available to a transmission
system with only a few minutes notice.
STAFF COMMENTS MAY 8 , 2003
proposed settlement, but believes that customers should receive the entire Idaho jurisdictional
share. It is not appropriate for the Company to fail in its regulatory responsibilities and receive a
financial benefit. This recommendation is consistent with past Commission practice for
settlements and separately ordered items where 100% has flowed through the PCA.11 In short
Staff recommends that Idaho customers receive the entire settlement amount allocated to Idaho
without the transmission payments referenced above. Staff Attachment A shows Staff s
recommended PCA treatment of the proposed settlement without Company sharing.
removing the transmission payments and eliminating the Company s share of the settlement
benefit, Staffs recommendation reduces the power supply costs in Idaho by $515 828.42.
The other IE issue addressed by the Company is the $2 million guaranteed payment from
IE to Idaho Power to ensure that customers would receive at least some benefit from the IE-
Idaho Power Management Services Agreement (Agreement). This amount was guaranteed to
customers by the stipulation in Case No. IPC-OO-13 and Order No. 28596. Staff believes this
amount should continue to flow to customers as stated in the stipulation. Order No. 28596 refers
to the settlement drafted by Idaho Power and states "Stipulation Section No. 1.2 provides that
this $2 000 000 will flow back to Idaho customers annually coincidentally with Idaho Power
PCA. This annual reduction will continue until new Idaho Power tariff rates are implemented in
the next rate case.12 In the same Order the Commission stated
, "
We find the identified cost
savings and related benefits to customers to be an important factor in assessing the merits of the
underlying Agreement.,,13 Staff believes that the Company should continue to fulfill its
obligation to customers and flow the benefit amount back until the tariff rates are set again in the
next rate case. Staff recommends the Commission require the Company to book the $2 million
amount in monthly installments until the next rate case.
11 The Commission has always reserved the option of flowing costs through the PCA at lOO% instead of90%. See
Order No. 2513l which allowed CSPP costs to be flowed through to customers at lOO% and Order No. 29050 which
authorized settlement payments made to Astaris to be flowed through to customers at lOO%. In Order No. 28596
the Commission ordered the $2 million settlement to be passed directly to customers without sharing. The
Commission has also on occasion allowed Idaho Power to collect lOO% of its costs without sharing. For example
in Orders No. 29l47, 29085, and 28992 the Commission ordered intervenor funding to be passed on to customers at
lOO%. In Order No. 28753 the Commission authorized the Company to collect lOO% of the mobile home metering
costs through the PCA.
12 Order No. 28596 at 6.
13 Order No. 28596 at lO.
STAFF COMMENTS MAY 8, 2003
Other True Up Expenses and Credits
Staff has also reviewed two other items the Company proposes to flow through the PCA
to customers. These items are intervenor funding and mobile home metering costs. Staff has
reviewed the Commission Orders that required the costs to flow through the PCA and found that
they were recorded properly. Therefore Staff recommends that they be passed on to customers
as proposed by the Company.
Risk Management Committee Review
As part of the audit and the ongoing IPC-01-16 case, Staffhas reviewed documentation
provided by the Risk Management Committee (RMC). At this time Staff is generally pleased
with the work the RMC has done with the 3- Tier risk management system and the
documentation and analysis performed each month. The documentation is much better than that
previously provided and it appears the Company performs a thoughtful and careful analysis on a
regular basis. Idaho Power has made many improvements to the Operating Plan (OP Plan)
presented to the RMC on a monthly basis. One such improvement made for the January 14
2003 RMC meeting identified the hedges by month, with heavy load-hour and light-load hour
splits. The detail also presents the total hedge position and any orders to fill.
Staff is concerned that the RMC occasionally authorizes a transaction to be completed
but which is not undertaken by the next RMC meeting or identified in the RMC minutes or
supporting documentation. There are two reasons that such transactions may not have been
completed. First, the Company could find no counter party willing to accept the transaction at
the proposed price. This could be due to an illiquid market or that the price the Company is
offering is to too high or low. Second, before the transaction is carried out, Company personnel
may be presented with new information that makes the transaction unnecessary or imprudent.
Staff recommends that the Company document in the RMC meeting minutes the reasons why
authorized transactions are not carried out. Additional documentation of e-mail orders or
changes to orders also need to be included with the RMC minutes. This will allow faster
verification of power supply transactions in future PCA filings. Idaho Power has been open to
such suggestions in the past and its employees have actively sought to improve the OP Plan.
STAFF COMMENTS MAY 8, 2003
STAFF ENGINEERING ANALYSIS
True Up
Each PCA true up calculation includes the previous year s abnormal actual power supply
costs that are netted against revenue based on the previous year s forecasted rate. This net
amount is calculated monthly on the true up spreadsheet and deferred for recovery in the
following year s PCA. The calculated deferrals for April 2002 through March 2003 are shown
on Company Exhibit No.3. Staff has verified the method and calculation of those amounts. As
previously discussed in these comments, Staff recommends some changes to the true up
spreadsheet input amounts. Staffs proposed changes are labeled "Staff Adjustments" and are
shown on line 48 of Staff s true up spreadsheet. Staff s true up spreadsheet is Attachment B
pages 1 and 2, to these comments. Without these changes Staff s spreadsheet produces the same
result as Company Exhibit No.3. With these changes Staff calculates the amount of the true up
to be $38,103 009.
Projection (Forecast)
Each year s PCA also includes a projection of power supply costs for the coming year.
The projection uses forecasted inflows to Brownlee Reservoir for the April through July period
in a power supply cost regression formula. This year s forecast of 3.3 million acre-feet is only
53 % of normal. When this level of forecast runoff is used in the regression formula, an
expected PCA expense of $111 209 454 is calculated for the coming year. This is the same
amount calculated by the Company is its filing. The graphic representation of this calculation is
shown on Attachment C to these comments. Staff agrees with the Company that this amount is
approximately $38.1 million above normal annual Company Power Supply Costs.
Carry-Over Amounts
In last year s PCA Case, Case No. IPC-02-2 and -, the Commission ordered a portion
of the extraordinarily high power supply costs for three customer classes be carried over to this
year. Order Nos. 29026 and 29065. The three customer groups are: Schedule 7 - Small General
Service Customers, Schedule 19 - Large Power Service Customers and Schedule 24 - Irrigation
14 This forecast is prepared and published annually by the National Weather Service Northwest River Forecast
Center.
STAFF COMMENTS MAY 8, 2003
Customers. As a result of this action the three customer groups paid lower PCA rates than did
other customers last year. Consequently, these same three customer groups will pay higher PCA
rates than other customers this year. Interest has also accumulated on the carry-over balances at
6%. By Commission Order No. 28992, the irrigation amount also includes the recovery of some
intervenor funding. Attachment D shows the break down of these costs.
PCA Rates
Attachment E shows the calculation of 2003-2004 PCA rates. Lines 1 through 6 show
the calculation of the portion of the PCA rate associated with the forecast. The rate is 90% of the
expected above normal system power supply costs divided by system normalized energy. This
rate is 0.2460 ~/Kilowatt-hour (~/kWh) and is exactly the same as the rate calculated by the
Company in its filing.
Line 8 calculates that portion of the PCA rate that comes from the 2002-2003 true up.
When Company proposed true up dollars and normalized energy (Megawatt-hours, MWh) are
used in this calculation, Staff duplicates the true up rate proposed by the Company of 0.3583
kWh. However, Staff has adjusted the true up amount to $38 103 009 as previously discussed
and Staff proposes continued use of a more appropriate level of energy consumption 920 360
MWh, in determining the rate. Fewer dollars divided by more energy produce a lower rate of
3195 ~/kWh.
Line 10 shows this year s total Staff recommended PCA rate, excluding class specific
adjustments, to be 0.5655 ~/kWh. As previously discussed, three customer groups have
adjustments that make their PCA rates higher. Staff and Company agree on the dollar amounts
of these adjustments but, once again, Staff proposes that the carry-over amounts be divided by a
more appropriate level of energy consumption for the purpose of determining rates. The rate
components associated with the carry-over deferral, interest and intervenor funding are
calculated and shown on Attachment E, lines 13 through 16. Attachment F shows the PCA rates
by class and component that are proposed by Staff and the rates proposed by the Company.
With regard to the calculation of PCA rates, there are only two differences between the
Company and Staff recommendations. These comments have already discussed Staff s
adjustments to the Company-proposed true up amounts. The other difference is in the energy
(kWh) amounts used to determine the true up and class specific adder portions of the rates. The
STAFF COMMENTS MAY 8, 2003
Company used 1993 normalized energy and Staff used 2002 normalized energy. IS The 2002
numbers are, on average, 10.4 % higher.
Normalized Energy (kWh)
Some discussion of PC A history is required to understand the justification for using one
set of energy numbers as opposed to the other. For the first eight years of the PCA, 1993
through 2000, the computation of the true up rate was the true up dollar amount divided by
normalized energy consumption. Normalized energy was established from time to time when the
PCA base was updated. Generally, the base numbers were updated in a general rate case. The
Company s last general rate case established normalized energy, Case No. IPC-94-, based on
a 1993 test year. Staff recognized from the beginning of the PCA that the Company s energy
sales to customers normally grow annually and that rates established using out-dated base energy
consumption would be higher than rates established using current energy consumption. Staff
understood that establishing a rate using outdated energy consumption would over-recover true
up surcharges and over-refund true up rebates as the rate is applied to higher, current annual
energy consumption. In 1993 when PCA methodology was initially determined, use of
normalized energy consumption as established in the Company s last general rate case was a
simplification thought to be acceptable because true up surcharges and rebates were expected to
be balanced and, in case they were not exactly balanced, true up amounts were expected to be
relatively small resulting in small errors. Staff also expected that the base would be updated
more regularly.
In PCA years nine and ten, 2001 and 2002, true up amounts were many times greater than
the amounts previously experienced and the 1993 base energy consumption was very stale. In its
PCA filings the Company departed from approved methodology and used updated normalized
annual energy amounts to determine the true up rate. In both cases, Staff recognized the benefit
to customers in terms of reduced PCA rates that more accurately recovered the very large true up
amounts so Staff accepted use of the updated energy numbers. The Commission also accepted
the use of updated energy in the true up rate calculation. Staff further recognized that if updated
normalized energy had not been used to calculate the true up rate, the rate would have been
15 The normalized energy used by the Company and by Staff is based on normal expected rum sales to Idaho
customers during a specified time period.
STAFF COMMENTS MAY 8, 2003
higher and the true up amount would have been grossly over-collected by the Company. Staff
estimates the over-collection for those two years would have been approximately $70 million.
Since recovery of the true up is not tracked and trued up, the over-collection would have been the
Company s to keep. Staff anticipates this over-collection will also occur in this PCA period if
normalized annual energy is not updated.
In its filing this year the Company proposes to return to the use of 1993 normalized base
energy amounts to determine the true up rate. This may have been appropriate if the true up
amounts had returned to pre-2000 levels and the recovery assumptions and associated risks
remained acceptable. However, that has not happened. As shown on Attachment G, this year
true up amount is the third largest ever. It is more than twice as much as any of the true up
amounts prior to 2001. Also, its major components are the Astaris Voluntary Load Reduction
(VLR) Contract and settlement costs which account for more than $29 million dollars or 75 % of
this year s true up amount. Although spot market prices have returned to a range near normal
the Astaris VLR contract paid Astaris 15 ~/k Wh to not use a specified amount of energy through
March 2003. This is much higher than the 3 to 4 ~/kWh that one would expect to pay for energy
under the normal market conditions that persisted through the true up year. This year s true up
costs remain abnormally high. The majority of those high costs were contractually incurred
during the period of extremely high market prices that existed in early 2001 when the Astaris
VLR contract was signed. These are the same kind of very high costs recovered through the
PCA during the last two years when the Company appropriately used updated energy amounts.
In addition to extraordinary true up cost levels, Staff proposes that the Commission use
updated normalized energy for the purpose of calculating true up and carry-over rates for several
other reasons. First, use of the most current normalized energy loads available provides the best
estimate of actual customer use in the true up recovery period and thus the best chance of
accurately recovering the true up amount. If the Company sells the expected amount of energy
at a rate based on that same amount of energy, it will recover the revenue it is entitled to.
second reason for updating normalized customer energy loads is that some of the assumptions
that made the use of outdated base load energy numbers acceptable are no longer true. Over-
recovery of true up surcharges and rebates has not been symmetrical. There is no realistic
scenario where good water conditions create unusual amounts of energy for the Company to sell
at market when market prices are 10 or 20 times normal levels. When water conditions are really
good, market prices generally fall not rise. It is also clear that true up amounts are neither
STAFF COMMENTS MAY 8, 2003
offsetting nor small. In short, the true up amounts remain too large, offsetting rebates are not
expected, and rates based on 1993 normalized energy will give the Company an unwarranted
windfall at the expense of ratepayers.
If true up rates and carry-over rates are designed to recover the amounts proposed by
Staff using 1993 energy (kWh), and 2002 energy amounts are actually sold, the true up
component of the rate will recover approximately $42.1 million instead of the desired $38.
million and the carry-over rate component will recover $16.5 million instead of the desired $16.
million. Neither of these amounts are trued up so the Company will receive a $4.5 million
windfall. This would not recover any costs incurred by the Company, it is simply an over-
collection. If the Company files a rate case this year, the base will be updated and will more
accurately reflect actual consumption in subsequent PCAs.
Cost Recovery
Attachment H shows rate reductions from current rates under Staff s proposal. As would
be expected with a smaller true up amount and more energy to spread the above normal power
supply costs over, Staffs proposal decreases rates more than the Company s proposal. The
overall reduction proposed by Staff is 19.12%. This reduction amounts to $5.1 million more
than Company-proposed rates would produce if 2002 amounts of energy are sold. The additional
$5.1 million reduction is composed of a $0.6 million reduction in the underlying true up amount
and a $4.5 million reduction in true up and carry-over recovery associated with the use of
updated energy amounts.
Attachment I shows how much above base rates (current or normal rates with no PCA
adder) rates will be if the Commission accepts Staffs proposal. It also indicates that although a
significant reduction is proposed in this filing, another substantial reduction is required to return
rates to normal levels. Under Staffs proposal average rates will still be 17.41 % above normal.
CONSUMER ISSUES ANALYSIS
Idaho Power s PCA Application filed on April 15, 2003 contained both the customer
notice and press release. Customers were notified of the Application by bill stuffer and will have
until May 8 , 2003 to file comments with the Commission. Staff reviewed the customer notice
and press release and determined both complied with the notice requirements of IDAP
31.21.02.102.
STAFF COMMENTS MAY 8 , 2003
The customer notice is being mailed with cyclical billings, resulting in a small percentage
of customers not receiving the notice before the proposed decrease would become effective.
However, Staff did not want to delay implementation of the decrease and determined that the 21-
day period of time was sufficient for the Commission to receive customer comments.
As of May 7 2003, the Commission had received six comments from customers. All
the customers supported the proposed decrease in rates. However, one commented Idaho Power
should decrease rates more than 18.9% and another comment favored a larger decrease for small
commercial users.
Between May 16 2002, the effective date of the Company s previous PCA, and May 7
2003 , the Idaho Public Utilities Commission Consumer Assistance Staff received 492 complaints
and inquiries regarding credit and collection issues. Of that number, 449 were concerning
disconnection of service. This was an increase over the corresponding 2001-2002 time period
when Staff received 429 complaints and inquires regarding credit and collection issues, of which
401 concerned disconnections. There was a significant decrease during the same time period in
the number of complaints related specifically to Idaho Power s rates. Since the effective date of
the last PCA, there have been 2l complaints regarding prices and rates. During the same time
period the previous year there were 191 complaints, most of which were related to the tiered
residential rates then in effect.
Although rates will decrease as a result of the proposal, rates remain higher than normal
and there will always be customers who are unable to pay their bills in full each month. Based
on Staff s review of complaints and inquiries, it appears that customers continue to struggle
financially due to a lackluster economy and job layoffs. Therefore, Staff recommends that the
Company encourage customer service representatives to continue to work with customers to
establish payment arrangements when customers call the utility stating they are unable to pay
bills in full. Staff also recommends Idaho Power continue to provide customers with energy
conservation information.
RECOMMENDATIONS SUMMARY
Based on its analysis and review, Staff submits the following recommendations:
1. The purchased power transactions be approved with the changes noted by Staff.
2. The payments to and from Astaris be included in the PCA surcharge as booked.
STAFF COMMENTS MAY 8, 2003
3. That Idaho Power initiate an RFP process to manage its natural gas transportation
before the expiration of the current IGI contract.
4. That customers should not be responsible for the $428 625 in proposed transmission
expenses that Idaho Power would have to pay to IE.
5. The proposed IE settlement be flowed through to customers without any Company
sharing.
6. That Idaho Power be required to continue to book monthly the $2 million annual
benefit to customers the Company agreed to in the IPC-00-13 case stipulation.
7. That the mobile home metering costs and the intervenor funding be flowed through as
recommended by the Company.
8. That the RMC be required to provide more information and documentation regarding
the authorized transactions that are not carried out.
9. That true up rates and carry-over adder rates (including intervenor funding) be
calculated using 2002 normalized Idaho jurisdictional firm load (energy) at the
customer level.
Respectfully submitted this
;-th
~ ~y
of May 2003.
~~t~~
Deputy Attorney General
Technical Staff: Keith Hessing
Alden Holm
Marilyn Parker
LN:i :/umisc/commen ts/i pce03 .5lnkhah
STAFF COMMENTS MAY 8, 2003
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c::c..c..Case No. IPC-03-
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05/08/03 i:5
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2002 .2003 TRUE-UP CALCULATIONS
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-03-
Staff Case
1 Jurisdictional Allocation Factor 85.
2 Sharing Percentage 90.
2002 2002 2002 2002 2002 2002 2002
DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
4 PCA Revenue
5 Normalized Firm Load MWh 991 176 033 117 143 545 352 219 422 263 206 799 112 398
6 PCA Component Rate mIKWh 861 981 156 156 156 156 156
7 Revenue Allocated at 85.252 890.617 763.095 660.478 076.606,439.211 579.038,580.
8 Load Change Adjustment
9 Actual Firm Load MWh 070 745 312 833 523 116 753 615 540 338 270 806 176 173
10 Normalized Firm Load MWh 991 176 033 117 143 545 352 219 1,422 263 206 799 112,398
11 Load Change MWh 569 279 716 379 571 401 396 118 075 007 775
12 Expense Adjustment ((jj)16.84)339 941.96)710 417.44)391 975.64)759 508.64)988 383.00)077 877.88)(1,073,971.00)
13 Non-QF PCA
14 ACTUAL:
15 Purchased Water
16 Irrigation Load Reduction
17 Astaris VLR 940 861.593 397.300 935.799 027.771 124.899 256.549,877.
18 Mobile Generation
19 Master Metering Costs
20 Fuel Expense - Coal 725 116.825 869.212 816.644 471.42 073 558.029,564.007 563.
21 Fuel Expense - Gas 259 177.248 000.435 782.533 339.771 181.199 906.383 923.
22 Non-Firm Purchases 834 699.3,485 355.512 167.40 269 932.524 912.207 162.296 507.
23 Quantified Purchase from BPA
24 Surplus Sales (5,400 359.79)(1,657 392.27)(433 783.47)(744,348.59)942 255.40)351 220.63)784,231.55)
25 FMC Second Block Rev.
26 Expense Adjustment ((jj)16.84)(1,339 941.96)(4,710,417.44)(6,391,975.64)(6,759 508.64)(1,988 383.00)077877.88)073 971.00)
Sub-Total 019 552.784 812.635,942.742,913.49 16,210,137.906 790.379 668.
28 BASE:
29 Fuel Expense 341,000.293,000.843 000.076,000.6,445,000.587 000.026 000.
30 Non-Firm Purchases 339 000.356 000.872 000.2,473 000.252 000.615,000.162 000.
31 Surplus Sales 195 000.00)(597 000.00)(208 000.00)(142,000.00)(595 000.00)570 000.00)022 000.00)
32 FMC Second Block Rev.(826 062.77)(979,683.11)(693 150.51)(600,808.00)(745,141.45)(664,245.01)(742 239.84)
Sub-Total (341 062.77)072 316.813 849.49 806 192.356 858.967 754.423 760.
34 Change From Base 360 615.712 495.822 093.936 721.49 853 279.939 035.955 908.
35 Deferral (Shared and Allocated)865 870.370 059.43 158 901.22 366,591.537 758.543 362.321,270.
36 QF Deferral
37 Actual (incl. Meridian Amort.946,032.189 351.847 754.337,507.967,284.40 930 364.359 512.
38 Base 038,265.024 735.108 325.317,475.059,785.531 295.438,425.
39 Change From Base 907,767.164,616.739 429.020 032.907,499.40 399 069.921 087.
40 Quantified Benefit from BPA (47.00)
41 Total Non-shared Deferral 907 767.164 616.739 429.019 985.907,499.40 399 069.921,087.
42 Deferral (Allocated)771,602.989 924.628 515.866 987.771 374.189 209.47 782,924.
43 Astaris VLR Credit
44 Astaris Take-or-Pay Charge
45 Mobile Home Metering Costs
46 Intervenor Funding
47 Credit From IDACORP Ener
48 Staff Adjustments
49 Total Deferral 226 728.582,457.525 871.25 550,400.561 027.805 955.898 946.
50 Principal Balances
51 Beginning Balance 226 728.809 186.335 057.885,458.446,485.252 440.49
52 Amount Deferred 226 728.582,457.525 871.550,400.561,027.805 955.898 946.
53 Ending Balance 226,728.809,186.335 057.885,458.17 ,446 485.4 7 252,440.49 25,151 387.
54 Interest Balances
55 Accrual thru Prior Month (3,549.17)(27 290.50)(11,441.33)947.452.40 104,943.
56 Interest (jj)4% per Year 7,422.43 030.17,783.618.154.841.47
57 Prior Month's Interest Adj.549.17)(31 163.76)(181.45)605.(113.77)336.860.44)
58 Total Current Month Interest 549.17)(23 741.33)849.389.504.42 58,491.981.
59 Interest Accrued to Date (3,549.17)(27,290.50)(11,441.33)947.46,452.40 104 943.165 924.
60 Balance in All Accounts 223 179.781 895.323 616.11,892,406.17,492 937.357 384.317 312.
Note: Negative amounts indicate benefit to ratepayers Attachment B
Case No. IPC-03-
Staff Comments
U,\kho,,'o'poeO3OS\olaff C8S8\TRUE-UP 5I6l2OO3 KDH 05/08/03 Page 1 of 2
2002 - 2003 TRUE-UP CALCULATIONS
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-E~3-
Staff Case
1 Jurisdictional Allocation Factor 85.
2 Sharing Percentage 90.
2002 2002 2003 2003 2003
DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS
4 PCA Revenue
5 Normalized Firm Load MWh 030 835 162 545 229 083 162 223 106 080 952,288
6 PCA Component Rate mlKWh 156 156 156 156 156
7 Revenue Allocated at 85.889 108.22 130,479.252 417.129 889.027 002.729 895.
8 Load Change Adjustment
9 Actual Firm Load MWh 180 382 298 897 281 353 129 269 128 293 665 829
10 Normalized Firm Load MWh 030 835 162 545 229 083 162 223 106 080 952 293
11 Load Change MWh 149 547 136 352 270 (32 954)213 713 548
12 Expense Adjustment ((Q)16.84)518 371.48)296 167.68)(880 226.80)554 945.(374 066.92)(28 855 951.08)
13 Non-QF PCA
14 ACTUAL:
15 Purchased Water 15.
16 Irrigation Load Reduction 16.
17 Astaris VLR 3,407,962.501 610.090 697.826.893 589.
18 Mobile Generation 18.
19 Master Metering Costs 19.
20 Fuel Expense - Coal 920 506.030,414.165 414.299 812.324 197.259 327.
21 Fuel Expense - Gas 206 827.292 663.213 635.265 119.268 726.48 078 303.
22 Non-Firm Purchases 947,948.012 846.366 083.(363 892.04)905 178.998 923.
23 Quantified Purchase from BPA 23.
24 Surplus Sales 286 388.10)130 598.28)554 140.40)624 596.67)692,419.85)(39 601 711.00)
25 FMC Second Block Rev.25.
26 Expense Adjustment ((Q)16.84)518 371.48)296 167.68)(880 226.80)554,945.(374,066.92)(28,855 937.08)
Sub-Total 678,484.13,410 768.11,401,462.170 214.2,431,616.48 114,772,611.
28 BASE:
29 Fuel Expense 909 000.127 000.051,000.051 000.737 000.61,486,029.
30 Non-Firm Purchases 345 000.844,000.879 000.642 000.296 000.075 030.
31 Surplus Sales (3,883 000.00)809 000.00)978 000.00)781 000.00)742 000.00)(24 521 969.00)
32 FMC Second Block Rev.(625 639.68)(739 128.10)(799 266.67)(769 197.02)(889,475.62)(9,074 005.78)
Sub-Total 745 360.4,422 871.152 733.142 802.401 524.965,084.
34 Change From Base 933,123.987 896.248 729.027 411.030 092.807,437.42
35 Deferral (Shared and Allocated)068 839.875 741.310 277.785 969.788 020.46 992 689.
36 QF Deferral
37 Actual (incL Meridian Amort)280 715.597,534.194,734.055 349.784,779.44,490 959.
38 Base 539 895.713,885.567,845.1,459 785.314,445.114 198.
39 Change From Base 740 820.883,649.626 889.595 564.470 334.10,376 801.
40 Quantified Benefit from BPA (7.00)
41 Total Non-shared Deferral 740 820.883649.626 889.595 564.470 334.376,756.
42 Deferral (Allocated)629 697.43 751 102.43 532 855.506 230.399 784.820 249.
43 Astaris VLR Credit
44 Astaris Take-or-Pay Charge
45 Mobile Home Metering Costs
46 Intervenor Funding
47 Credit From IDACORP Ener
48 Staff Adjustments
49 Total Deferral 643 899.829 696.004 322.(1,009 629.58)246 029.64)373696.
50 Principal Balances
51 Beginning Balance 151 387.795 287.624 984.629 306.619 677.
52 Amount Deferred 643 899.829 696.004 322.(1,009 629.58)(1,246 029.64)373 699.
53 Ending Balance 795 287.624 984.629 306.619 677.373,647.
54 Interest Balances
55 Accrual thru Prior Month 165 924.250 352.349 659.468 536.600 634.
56 Interest (Q)4% per Year 837.317.118 749.132,097.128 732.772 642.
57 Prior Month's Interest Adj.589.(10.83)127.(5.24)(43 168.06)
58 Total Current Month Interest 427.306.118 877.132,097.128 727.729 474.
59 Interest Accrued to Date 250 352.349 659.468 536.600 634.729 361.
60 Balance in All Accounts 045 639.974,643.49 097 843.220 311.103 009.103 009.
Note: Negative amounts indicate benefit to ratepayers
Attachment B
Case No. IPC-03-
Staff Comments
U",,"..""'_3O51oI"" ....,\TRUE.UP 5/612003 KQH 05/08/03 Page 2 of 2
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CARRY-OVER AMOUNTS, INTEREST AND INTERVENOR FUNDING
Line Customer Rate Carry-Over Interest Intervenor Total
No.Group Schedule ~6%Funding
($)($)($)
Small General Service 577 033 622 611 655
Large Power Service 635,405 163 593 798 998
Irrigation Service 24 & 25 953 165 657 190 314 11 617 669
U:\khessin\ipce0305\Carry-Over Amounts 4/28/2003 KDH
Attachment D
Case No. IPC-03-
Staff Comments
05/08/03
2003-2004 PCA - Eleventh Annual
IPC-03-
Staff Case
Line Descri tion Units Base Forecast Difference
2003 - 2004 Forecast:
PCA Expense
($)
079 128 111 209,454 130 326
Normalized Energy - Total System (MWH)952 283 952 283
Energy Rate (~/kWh)52378 79707 27329
Sharing Percentage
(%)
90%
Energy Rate Difference (#kWh)24596185
Rate
2460
ill (MWh)/MWh (~/kWh)
2002-2003 True-u 103 009.926 360 19485653 3195
PCA Rates:
Proposed PCA Rate Adj. from Base (~/kWh)5655
PCA Rate Currently in Effect (i/kWh)9370
Total Rate Difference (~/kWh)(1.3715)
Carry-Over Adders and Intervenor Fundinq:
Schedule 7 - Small General Service 611 655 267 241 288776797 2289
Schedule 19 - Large Power Service 798 998 928 629 969792013 1970
Schedule 24 - Irrigation & Pump 617 669 640 999 079632096 7080
Rate Energy Revenue Total
Expected PCA Revenues:/MWh (MWh)ill Rate
Forecast Revenue 2.460 926 360 338 846 2460
True Up Revenue 195 926,360 104 720 3195
Schedule 7 - Small General Service 289 267 241 611 715 7944
Schedule 19 - Large Power Service 970 928 629 799 399 7625
Schedule 24 - Irrigation & Pump 080 640 999 618 273 2735
83,472 952
Note: Negative rates and amounts indicate benefits to ratepayers.
Attachment E
Case No. IPC-03-
Staff Comments
05/08/03
STAFF PROPOSED PCA RATES
IPC-O3-
Line Tariff Description Schedule Forecast True Up Carry-Over Total PCA
No.No.Rate Rate Rate Rate
(it/kWh)(it/kWh)(it/kWh)(it/kWh)
1 Uniform Tariff Rates:
2 Residential Service 2460 3195 0000 5655
3 Small General Service 2460 3195 2289 7944
4 Large General Service 2460 3195 0000 5655
5 Dusk to Dawn Lighting 2460 3195 0000 5655
6 Large Power Service 2460 3195 1970 7625
7 Irrigation Service 2460 3195 7080 1 .2735
8 Unmetered General Service 2460 3195 0000 5655
9 Municipal Street Lighting 2460 3195 0000 5655
10 Traffic Control Lighting 2460 3195 0000 5655
11 Special Contracts:
12 Micron 2460 3195 0000 5655
13 FMC 2460 3195 0000 5655
14 J R Simplot 2460 3195 0000 5655
15 DOE 2460 3195 0000 5655
COMPANY PROPOSED PCA RATES
Line Tariff Description Schedule Forecast True Up Carry-Over Total PCA
No.No.Rate Rate Rate Rate
(it/kWh)(it/kWh)(it/kWh)(it/kWh)
16 Uniform Tariff Rates:
17 Residential Service 2460 3583 0000 6043
18 Small General Service 2460 3583 2438 8481
19 Large General Service 2460 3583 0000 6043
20 Dusk to Dawn Lighting 2460 3583 0000 6043
21 Large Power Service 2460 3583 2178 8221
22 Irrigation Service 2460 3583 7120 1 .3163
23 Unmetered General Service 2460 3583 0000 6043
24 Municipal Street Lighting 2460 3583 0000 6043
25 Traffic Control Lighting 2460 3583 0000 6043
26 Special Contracts:
27 Micron 2460 3583 0000 6043
28 FMC 2460 3583 0000 6043
29 J R Simplot 2460 3583 0000 6043
30 DOE 2460 3583 0000 6043
U:\khessin\ipce0305\staff case\PCA Rate Comparison 5/2/2003 KDH
Attachment F
Case No. IPC-03-
Staff Comments
05/08/03
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KD
H
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 8TH DAY OF MAY 2003 SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF IN CASE
NO. IPC-03-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
MONICA MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
GREGORY W SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
~ ~
SE RET
CERTIFICATE OF SERVICE