HomeMy WebLinkAbout28852.pdfOffice of the Secretary
Service Date
September 28 2001
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR A CASE NO. IPC-Ol- 7
REFUNDABLE EMERGENCY ENERGY
CHARGE FOR THE RECOVERY OF
EXTRAORDINARY POWER SUPPLY
EXPENSES.
IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR AUTHORITY CASE NO. IPC-Ol-
TO IMPLEMENT A POWER COST
ADJUSTMENT (PCA) RATE FOR ELECTRIC
SERVICE FROM MAY 1, 2001 THROUGH MAY ORDER NO. 28852
15, 2002.
BACKGROUND
A. Procedural History
In Order No. 28722 issued May 1 , 2001 , the Commission partially granted Idaho
Power s Power Cost Adjustment (PCA) Applications and allowed the Company to immediately
recover approximately $168.3 million through the PCA mechanism. The Commission deferred
recovery of $59 211 603 pending further investigation of the trading practices used to purchase
power for the regulated Company, including hedging against market volatility, transmission and
wheeling charges, Mid-C pricing, and the use of weighted average pricing. Order No. 28722
also identified "the November trading event" for further investigation to determine whether the
purchasing entity failed to execute a timely purchase of power when requested to do so.
August 28-2001 , the Commission conducted an evidentiary hearing on these issues.
After reviewing the record in this matter, the Commission has determined that the
Company should be allowed to recover $48 856 748 ($47 665 120 plus interest of $1 191 628)
by imposing a uniform 0.3826~ per kilowatt hour charge for all non-residential customers over a
one-year period. The first two blocks of the residential rate will increase by 0.430~ per kilowatt
hour over a one-year period. The Commission s findings are set out in greater detail below.
B. Parties
In these consolidated cases, the Commission granted intervention to: Astaris LLC
Irrigation Pumpers Association, Inc., U.S. Department of Energy, Land and Water Fund of the
ORDER NO. 28852
Rockies, Mary McGown, Idaho Rivers United, Idaho Rural Council and the Industrial Customers
of Idaho Power. The Land and Water Fund, Mary McGown, Idaho Rivers United and the Idaho
Rural Counsel later withdrew their submitted comments and participation in this phase of the
consolidated cases.
Prefiled testimony was submitted by the Commission Staff, Idaho Power, and the
Irrigation Pumpers Association. Although the Irrigation Pumpers Association submitted prefiled
testimony, it subsequently withdrew from the proceeding. Consequently, our record in this case
does not include the Association s prefiled testimony. Although the Industrial Customers of
Idaho Power (ICIP) did not pre file testimony, it was the only intervenor to enter an appearance at
the evidentiary hearing and participated by cross-examining witnesses.
ISSUES IN DISPUTE
In Order No. 28722, the Commission specifically identified the November Trading
Event and Idaho Power s trading practices, which include hedging, use of weighted average
pricing for real-time transactions, use of Mid-C pricing for day-ahead transaction pricing, and its
transmission and wheeling charges for further investigation. These issues are discussed at length
below.
A. November Trading Event
During the PCA audit, Staff identified a 75 MW term transaction (the "November
Trading Event") for the regulated system for January 2001 that was ordered by the Risk
Management Committee (RMC) in its November 21, 2000 meeting minutes, but was never
completed by the trading entity. When a purchase was subsequently made to meet this need, the
market price of power had substantially increased.
Staff witness Carlock argued that the Company should not be allowed to recover the
additional $8 million for higher-priced replacement power because the need for the power had
been identified but the Company failed to follow through on the purchase. Tr. at 344. Idaho
Power witness Gale maintained that the apparent oversight in the RMC minutes is "a record
keeping issue and not one of execution." Tr. at 599. Idaho Power argued the transaction was not
completed because the RMC changed its decision later during the same meeting. However, this
change was not recorded in the meeting minutes because of a "clerical error.Tr. at 144.
Furthermore, Company witness Anderson testified that the system did not need to purchase
power for January 2001 because it had a net long position of 1 300 MW through the balance of
ORDER NO. 28852
the 2000-2001 PCA year despite net short positions of 80 MW in December 2000 and 63 MW in
January 2001. Tr. at 125.
Staff argues that the Company s record keeping error explanation is not persuasive
because the Company s operating plans showed that under nearly every scenario the system
would be short in January and thus a term transaction was supported. Tr. at 343. Absent
additional documentation of its rationale, Staff contends the Company s alleged subsequent
decision to rescind the term transaction was contrary to the prudent decision originally made. Tr.
at 419-20. Consequently, Staff advocated that these additional costs should be absorbed by the
non-system operations rather than recovered from customers. Tr. at 344.
Commission Findings:After reviewing the testimony of Staff witness Carlock and
Company witness Anderson, the Commission must evaluate the reasonableness of the situation
based on the information known at the time of the transaction. To assist us in that exercise, the
Company must keep detailed and accurate records so that the Commission can correctly assess
issues in dispute. Idaho Power s minutes and supporting documents were the primary source of
information regarding its contemplation of long-term transactions. Company witness Darrel
Anderson testified that Idaho Power was short 63 MW for the month of January 2001 and the
RMC decided unanimously to make a term purchase to cover this shortfall. Tr. at 125 , 142.
According to his testimony, the RMC reversed its original decision later during the same
November 21 , 2000 meeting. Tr. at 126. However, the Company s record keeping does not
support the testimony of the Company s witness. Mr. Anderson also testified that Idaho Power
has since changed its handling of RMC minutes to prevent such mistakes from occurring in the
future, but that is neither helpful nor applicable to our review of November 2000. Tr. at 127.
Given the operating plans, water forecasts and scenario analyses considered by the
RMC on November 21 , 2000, the documented decision to purchase the 75 MW hedge was a
reasonable and prudent determination that guaranteed adequate power during a peak winter
month. Any decision to the contrary was not recorded in the minutes and is unsupported by any
other documentation. Moreover, Mr. Anderson testified that if the RMC failed to send a written
authorization to the trading entity, the decision to purchase the 75 MW would not have occurred.
Tr. at 156. Without evidence of the written authorization or other documents to support the
testimony of the Company s witnesses, the Commission finds that the Company has failed to
ORDER NO. 28852
adequately demonstrate that its failure to complete the RMC approved November transaction
was reasonable and prudent.
Ratepayers will not be held financially responsible for Idaho Power s poor record
keeping in this instance. If the RMC minutes were fully accurate (and the decision to buy was
not later rescinded but merely was not carried out by the RMC or traders), the Commission
cannot in good faith require ratepayers to pay for a similar transaction in late December that cost
significantly more than the approved but uncompleted November transaction. Idaho Power did
not properly document that its RMC changed its decision to carry out the approved transaction.
Because the Commission finds that Idaho Power has not demonstrated that it acted reasonably in
failing to execute the November transaction, the Company will not recover the $7 976 701 in
question.
B. Real-Time Transaction Pricing
During the 2000-2001 PCA year, the Company changed the way the real-time
transactions were priced.In prior PCA periods, the transactions flowed through the system at
their actual cost. Now, however, the transactions are priced based on the weighted average of all
real-time transactions that touch the Idaho Power system on an hourly basis. Tr. at 222-341.
According to Staffs analysis, this weighted average price resulted in significant
overcharges and underpayments. Tr. at 341. Consequently, the purchases and sales should be
kept separate to calculate the cost. Tr. at 341-42. To account for these disparities, Staff
recommended that the real time purchase transactions for the months of December 2000 through
February 2001 be repriced to the lower of the non-system s cost or market price. Id. Staff also
recommended repricing the real time sale transactions for the same months using the higher of
sales price or market. Id. In doing so, the system would receive the benefit of the best price
which Staff believed to be appropriate since the non-operating system had not yet become a
separate trading entity. Tr. at 342.
Idaho Power justified implementing this change in real-time pncmg because
Commission Order No. 28596 approving the IDACORP Energy Solutions (IES) 1 and Idaho
Power Service Agreement was "technically in effect" even if the Agreement was not yet
effective by its own terms. Tr. at 233. Moreover, the Company believed using the weighted
average of all real-time transactions that touch the Idaho Power system on an hourly basis was
1 IDACORP Energy Solution (IES) is now known as IDACORP Energy (IE).
ORDER NO. 28852
the best representation of the real-time market prices and the risks associated with the real-time
business. Id.
Commission Findings:In Order No. 28596 issued December 19, 2000, the
Commission approved the Agreement between IES and Idaho Power.2 Terms of the Agreement
provide that it does not become effective until the state regulatory commissions of Idaho
Oregon, and Nevada all approve the Agreement in addition to the Federal Energy Regulatory
Commission (FERC). Agreement at 'tI 6. The Agreement provides that it "shall not become
effective until the commissions have issued their respective final orders approving the
Agreement or any future amendments.Id. at'tl9.
Upon reviewing the Electric Supply and Management Services Agreement
(Agreement), we find that the negotiations and the documents contemplated that the Agreement
would go into effect when all four commissions approved the Agreement. Because the
Agreement was not effective under the express language of the Agreement until July 3, 2001
when the Oregon Commission provided the last requisite approval, the Company was not
authorized to implement real-time pricing before that date. The Agreement contemplated several
customer benefits and safeguards that were not yet in place when Idaho Power implemented the
real-time weighted average pricing for purchases and sales. It is also inappropriate for the
Company to implement some provisions of the Agreement but not others. Because the
Agreement was not effective, the Commission finds that the $3 569 782 in disputed real-time
transactions are disallowed. We also find it is appropriate to calculate the average cost for
purchases and sales separately.
Moreover, the Company s change in real-time pricing was a change to the PCA
mechanism. Company witness Gale testified that not changing the real-time pricing method in
light of Order No. 28596 seemed "a precarious position to take." Tr. at 277. When asked ifthe
Company discussed seeking Commission approval to implement the real-time pricing change
prior to the entire Agreement being approved by all the necessary regulators, Company witness
Gale responded in the negative because "it was clearly the right thing to do . . . at that time." Tr.
at 282. The Company should know that it must file an Application to formally change the PCA'
structures or implement Commission Orders outside of their effective dates. Utilities that
unilaterally change the implementation terms of major accounting mechanisms without seeking
2 This Agreement has been included in the record as Idaho Power Exhibit 13 and Staff Exhibit 117.
ORDER NO. 28852
prior Commission approval run the risk of disallowances. We now turn to day-ahead and intra-
month transaction pricing, which comprised the bulk of the monetary amount in dispute.
C. Day-Ahead Transaction Pricing
During its audit of the PCA period, Staff did not find the index market price to be
reflective of a reasonable price surrogate between the system and non-system purchases because
the non-operating system obtained substantially greater margins on similar transactions than did
the regulated system. Tr. at 339-40. According to Staff witness Carlock, the lower of cost or
market for purchases and the higher of cost or market for sales is the appropriate transfer pricing
mechanism between affiliates to assure that customers are not harmed by affiliate abuse until the
requisite safeguards are in place. Tr. at 363.
Company witnesses testified that the day-ahead transfer pricing procedures had been
in place without Staff objection since January 1999. Tr. at 572, 599, 609. Moreover, Idaho
Power believes that the Mid-C index continues to be representative of the day-ahead pricing in
the Idaho regional power markets. Tr. at 571. Company witness Hoyd further indicated that
Staffs methodology does not accurately price transactions between operating and non-operating
books because it excluded ancillary transaction charges and included irrelevant transactions. Tr.
at 568-69.
Commission Findinf!s:Based upon the evidence presented at the hearing, the
Commission finds that Idaho Power s day-ahead transfer pricing practices were neither
imprudent nor unreasonable for several reasons. First, Mid-C day-ahead pricing has been used in
prior PCA periods reviewed by Staff and accepted by the Commission. As Company witness
Hoyd testified, Idaho Power has applied the same procedures for pricing day-ahead transfers
between the operating and non-operating systems since January 1999. Tr. at 572. Second, Staff
agrees that Mid-C is the proper index to reflect market price transfer costs once proper
safeguards are in place. Tr. at 407. Staffs testimony identified potential areas of abuse or
inequity, and while the transfer mechanism produced significant increases in the PCA deferral
that were not actively monitored by Idaho Power, the mechanism itself was not shown to be
imprudent. Given our review of the record, we do not find that use of the Mid-C pricing
mechanism for day-ahead transactions was unreasonable. However, the market volatility present
during the 2000-2001 PCA should have alerted the Company to do further analysis of the impact
ORDER NO. 28852
on the PCA results.Nevertheless, the Commission authorizes Idaho Power to collect the
$47 665 120 associated with day-ahead transactions from the 2000-2001 PCA period.
The Commission believes that the Company should have re-examined its day-ahead
transaction pricing in light of the market volatility present during the 2000-2001 PCA period.
During the hearing, Company witness Hoyd testified the transfers between the non-operating and
operating systems were "quite mechanical." Tr. at 588. The Commission finds this hands-off
attitude to be troublesome and a weak justification to explain why the Company did not take
action to minimize ratepayer costs in the face of large day-ahead price fluctuations. Although
the Company points to the 90/1 0 power procurement cost sharing in Idaho as incentive to seek
low market prices, we question if it is adequate motivation to prompt appropriate Company
action. Tr. at 177-79. While the Commission does not presently find the Company s reliance on
and compliance with past practices to be imprudent, it is always appropriate to re-examine
existing policies and improve them if possible. Consequently, the Commission believes it is
appropriate for the parties to discuss a greater sharing of PCA purchased power cost components
or other incentive mechanisms within the context of the IPC-01-16 case currently in progress.
D. Hedging
Staff asserted that the Company substantially limited system long-term or hedging
contracts after November 2000, which created higher customer costs because the power
purchases were shifted to intra-month and priced at the market index. Tr. at 322-23. Staff
argued that while the non-system operation may execute additional and potentially more risky
deals, the direction and the existence of system transactions should be consistent but on a more
conservative scale. Tr. at 323. Because the non-system operation executed term transactions
the system (serving native load) should also have had some corresponding transactions within its
risk bands. Id.
Company witness Anderson testified that the power supply activities of the Company
were reasonable and prudent in light of unprecedented high regional energy prices and an
uncertain water situation. Tr. at 130. Moreover, the Company implemented both supply and
demand side measures to reduce the Company s power supply costs once it knew in February
2001 that the snow pack would be low and that prices for power were not going to decline. Tr. at
131.
ORDER NO. 28852
Commission Findings:As we have previously seen in California and noted in our
Orders, reducing the use of long-term contracts places over-reliance on the spot market and
exposes utilities to possible exercise of market power by wholesale power sellers during periods
of short supply. Order No. 28722 at 13 citing California PX v. FERC 245 F.2d 111 0 (9th Cir.
2001). Long-term power purchases have traditionally mitigated spot market price volatility but
can produce higher costs if prices later fall below the purchase price of the hedge.
During Commissioner Hansen s cross-examination of Company witness Darrel
Anderson, Mr. Anderson stated that the Company "actively managed the system and monitored
the surplus deficits all the way through November, December and January" but "did not take any
specific actions" such as tying up long-term contracts that benefited the customer. Tr. at 186.
Upon reviewing the evidence presented, the Commission finds that the Idaho Power
Company s actions in regard to hedging have not been shown to be imprudent given the
information it had at the time the decisions were being made. Company witness Anderson
testified that the Company did not have reliable indication of how poor water conditions would
be that winter and was faced with unprecedented price spikes on the spot market. Tr. at 129-
184-, 190. We will not examine the evidence using hindsight, but rather make our findings
based upon the circumstances at the time hedging decisions were made by the Company.
The decisions to make or not to make long-term transactions were calls that needed to
be made by risk managers trained in such areas. Although the Company s failure to secure long-
term transactions proved costly in retrospect, no evidence was presented that definitively proved
that the Company s inaction was unreasonable under the circumstances present at that time.
Consequently, the Commission will not penalize the Company for the hedging or lack of hedging
decisions it made during the 2000-2001 PCA period.
E. Transmission and Wheeling Charges
Staff witness Lord testified that a strong possibility exists that the non-system
speculative arm of Idaho Power utilized the Company s transmission facilities without proper
benefit or compensation to the regulated utility and its customers. Tr. at 451. Transmission
arbitrage occurs where a discrepancy between two pricing points exists such that the transaction
can be entered into to capture the difference as profit with little or no risk. Id. Transmission
services are transferred to the non-system speculative arm of Idaho Power at cost. Id. The entity
then transfers power purchased for Idaho Power at the Idaho border based on the Mid-C index
ORDER NO. 28852
price - not the border price. Id. Because the transportation price is known, the speculative arm
can determine whether Idaho border prices are less than the representative market price plus
transmission. Id. If there is a differential, the speculative arm collects that differential as a
profit. This profit is risk-free and is not shared with ratepayers. Id.
Commission Findinf!s:The Commission finds that although transmission and
wheeling activities are not accounts included in the PCA and their benefits may be difficult to
quantify, Idaho Power s non-operating system likely received significant benefits from use of
system assets during the 2000-2001 PCA year. On August 30, Company witness Gale testified
that it is renegotiating its Agreement with IE to account for "the use of system transmission and
system capacity services, as well as other potential intangible benefits" on a prospective basis.
Case No. IPC-01-, Tr. at 224.
Because neither Staff nor the Company quantified the transmission benefits
experienced by the non-operating system during the 2000-2001 PCA period, the Commission
makes no adjustment for the 2000-2001 PCA period even though some benefits were probably
derived by the non-operating system. Moreover, these items are not accounts that flow through
the PCA. Even so, we expect this issue should be addressed prospectively in Phase II ofthe IPC-
01-16 case.
RATE DESIGN
A. Carrying Charge
Although the Commission conducted its investigation of the above issues as
expeditiously as possible while still fully developing the record, five months have passed since
we issued Order No. 28722 deferring recovery of the disputed $59 million. This deferral was not
without cost; $1 191628 of interest is attributable to the $47 665 120 allowed for recovery during
this time at the 6% annual interest rate previously approved by this Commission. Order No.
28575.
Commission Findinf!s:Because this Order authorizes Idaho Power to recover
$47 665 120 of the disputed $59 million, the Commission finds it reasonable to award the
carrying charge associated with the amount of their authorized recovery. Consequently, Idaho
Power shall recover $1 191 628 in carrying charges.
ORDER NO. 28852
B. Surcharge Amount
Because the Commission has determined that Idaho Power should collect
$48 856 748, the issue remains of what recovery method should be used. Company witness Gale
testified that the Commission should authorize a rate to collect the additional amount over one
year with implementation occurring shortly after the issuance of the Order. Tr. at 269. In the
alternative, Mr. Gale testified that the Commission could defer the additional amount for
recovery until the next rate action in the form of next year s PCA filing or a securitization filing
submitted prior to the next PCA rate change. Tr. at 270.
Commission Findinf!s:The Commission considered amortizing the increase and/or
deferring it until the Company files its PCA request next spring. However, the Commission
declines to delay recovery of this PCA amount any further. As with any requested rate increase
the Commission must balance the needs of the Company to maintain its financial viability with
customer concerns of fair rates and rate stability. In this case, the Commission is confronted
with extraordinary conditions that resulted in large purchase power costs and a low forecast of
reservoir water levels. Given the amount of purchases the Company has already made, it is
reasonable and appropriate for the Company to recover these costs as near as possible to the time
period in which they were incurred.
This is not to say that amortization is never a viable option. We noted in the original
PCA Order that when the PCA results in large rate increases, it may be appropriate to defer a
percentage of that year s power supply costs. Order No. 24806 at 20. However, the Commission
will not mortgage the collective future of ratepayers without considerable justification. Given
that the costs of several large demand-side initiatives undertaken in the last year will likely
included in Idaho Power s next PCA recovery request, the Commission declines to delay
recovery of this amount any longer for fear of exacerbating potential power rate increases next
spnng. Such a delay would also incur additional carrying charges of approximately $2 million.
To recover the $48.9 million, the rate increase is a uniform 0.3826~ per kWh
surcharge imposed on all energy consumed by non-residential customer classes over a 12-month
period. The first two rate blocks of the residential class will increase by 0.430~ per kWh over a
12-month period. Recovery over a one-year period will ensure that all customers will bear their
proportionate share of the rate increase. Imposing a uniform cent per kWh surcharge for non-
residential customers is reasonable and consistent with past PCA surcharges. This rate design
ORDER NO. 28852
produces a PCA rate of 0.3826~ per kWh above existing rates. The Attachment shows Idaho
Power s affected schedules and the associated average rates and increases. The table below is
simplified version of the Attachment.
EXISTING APPROVED PERCENTAGE
CUSTOMER GROUP AVERAGE RATE AVERAGE RATE INCREASE
Residential
* 0 - 800 kWh 7 cents per kWh 2 cents per kWh 50%
* 801 - 2000 kWh 5 cents per kWh 0 cents per kWh 57%
* over 2000 kWh 8.4 cents per kWh 8.4 cents per kWh
Irrigation 1 cents per kWh 5.4 cents per kWh 5 %
Small Commercial 6 cents per kWh 0 cents per kWh
Lan!:e Commercial 9 cents per kWh 5.2 cents per kWh
Industrial 1 cents per kWh 4.4 cents per kWh 3 %
Although the surcharge will be applied to the first two residential rate tiers, the
Commission declines to extend it to the third tier with the highest energy consumption. In doing
, the Commission continues to encourage energy conservation but recognizes that a further
increase in the over 2000 kWh tier is not warranted at this time.
C. Effective Date
According to Company witness Gale s testimony at the evidentiary hearing, Idaho
Power prefers that a one-year rate change be implemented as soon as possible due to cash flow
and capitalization concerns. Tr. at 270.
Commission Findinf!s:We find that the appropriate effective date to implement the
PCA rates granted in this Order is October 1 , 2001. Because this rate increase will be effective
for one year, it will expire on September 30, 2002. The Commission understands that this will
cause rates to change more than the once a year we have traditionally experienced. However
this timing will ensure prompt recovery and fairly divide the recovery burden among customer
classes.
The Commission recognizes the additional hardship that this increase will place on
Idaho Power customers. We also note in the way of rate mitigation that recent approval of a
Bonneville Power Administration (BP A) credit will flow through to residential and small farm
customers for the next five years. Although the BP A credit will not fully offset the increase
approved by this Order, it will help to reduce its impact for those customer classes.
ORDER NO. 28852
D. Customer Assistance
Because it is necessary to authorize a second rate increase now, the Commission is
concerned for the health and safety of ratepayers who struggle to pay their electric bills during
the winter heating season. We recognize that some customers may not be able to conserve or
reduce their consumption in order to lower their bills. There are programs for eligible residential
customers to possibly convert to more efficient space heating appliances or receive assistance for
high heating bills. Interested parties should contact the Commission Consumer Assistance Staff
at 1-800-432-0369 for more information on programs in their vicinity.
We encourage ratepayers to contact Idaho Power, which offers special payment
arrangements to help customers manage their utility payments in extraordinary circumstances.
Special payment arrangements can be tailored to the unique needs of each customer and may
include spreading payments over several months. To make special payment arrangements
customers should contact Idaho Power s Customer Service Department at (208) 388-2323 or
(800) 488-6151.
A budget pay plan is available to Idaho Power customers who are not behind on their
bills but merely seek to minimize bill fluctuations. The amount paid is based on the customer
average dollar amount of the previous 12-month history. For those customers who do get
behind, a levelized payment arrangement can be made that spreads the past due amount over a
number of payments, plus the normal monthly bill.
Customers interested in LIHEAP energy assistance funds must qualify under federal
income guidelines. Customers can apply in December to receive a one-time payment made
directly to the utility. LIHEAP also provides funding for low-income weatherization programs.
Qualifying customers may also access Idaho Power s Low-Income Weatherization
Assistance. The Company provides grants to local non-profit agencies that supplement federal
funds supporting weatherization projects for its low-income customers.
Project Share primarily provides funds to qualifying customers for heating assistance
from October 1 through the end of April. Applicants may contact organizations like the
Salvation Army, American Red Cross, or a local Community Action Agency to apply for Project
Share funds. Additional emergency assistance funds may also be available through county
welfare offices.
ORDER NO. 28852
In an effort to help customers improve the energy efficiency of their homes and
reduce their electricity bills, Idaho Power has developed an "Energy Planner" or home energy
audit packet. The packet contains conservation ideas and ways to improve the energy efficiency
of homes, a printed history of the customer s power usage and energy cost calculator. Customers
who are interested in receiving an Energy Planner packet or a home energy audit should contact
Idaho Power s Customer Service Department at the number given above.
The Commission urges electric customers to conserve energy in an effort to keep
electric bills affordable.Customers interested in conserving energy may consult
www.eren.doe.gov/buildings/documents/high heating bills, the Department of Energy s website.
The Commission and Idaho Power also have conservation information available on their
respective websites.
Finally, the Commission s winter moratorium rule prohibits any electric or gas utility
from terminating or threatening to terminate during the months of December through February
the service of any residential customer who declares that he or she is unable to pay in full for
utility service and whose household includes children, the elderly, or infirm persons. IDAP
31.21.01.306.01. However, for families that use this protection, the full amount not paid during
the moratorium period becomes due on March 1.
ORDER
IT IS HEREBY ORDERED that the disputed amounts requested by Idaho Power
Company s PCA Applications are partially granted. The Company is authorized to implement
the surcharge identified in this Order that will generate $48 856 748 in PCA revenues.
IT IS FURTHER ORDERED that the Company shall file tariffs in conformance with
a uniform kWh rate increase of 0.3826~ per kWh for all non-residential customer classes and a
0.430~ per kWh increase in the first two rate blocks of the residential class.
IT IS FURTHER ORDERED that the PCA rates established in this Order are
effective October 1 , 2001 for a period of 12 months.
IT IS FURTHER ORDERED that the Commission invites the parties to consider
whether a change is warranted in the 90/10 cost sharing mechanism or components included in
the PCA. In particular, the Commission invites the parties to comment on the need, if any, to
provide additional incentive for Idaho Power to act in the ratepayers ' interests within the context
of the workshops scheduled in the IPC-01-16 case. IDAPA 31.01.01.273.
ORDER NO. 28852
THIS IS A FINAL ORDER. Any person interested in issues finally decided by this
Order or in interlocutory Orders previously issued in these Case Nos. IPC-01-7 and IPC-01-
11 may petition for reconsideration within twenty-one (21) days of the service date of this Order
with regard to any matter finally decided in this Order or in interlocutory Orders previously
issued in these Case Nos. IPC-01-7 and IPC-01-11. For purposes of filing a petition for
reconsideration, this order shall become effective as of the service date. Idaho Code 9 61-626.
Within seven (7) days after any person has petitioned for reconsideration, any other person may
cross-petition for reconsideration. See Idaho Code 9 61-626.
DONE by Order ofthe Idaho Public Utilities Commission at Boise, Idaho, this ':;"7 -hw
day of September 2001.
IJ
~~~
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~f)~
D. Jewell
Commission Secretary
O:IPCEOI7 11 In
ORDER NO. 28852
Co
m
m
i
s
s
i
o
n
D
e
c
i
s
i
o
n
IP
C
-
01
-
7
&
1
1
Su
m
m
a
r
y
o
f
R
e
v
e
n
u
e
I
m
p
a
c
t
St
a
t
e
o
f
I
d
a
h
o
No
r
m
a
l
i
z
e
d
1
2
-
Mo
n
t
h
s
E
n
d
i
n
g
D
e
c
e
m
b
e
r
3
1
19
9
9
5/
1
/
0
1
P
C
A
R
a
t
e
s
t
o
1
0
/
1
/
0
1
P
C
A
R
a
t
e
s
12
M
o
n
t
h
R
e
c
o
v
e
r
y
P
e
r
i
o
d
(1
)
(2
)
(3
)
(4
)
(5
)
Ra
t
e
19
9
9
A
v
g
,
19
9
9
S
a
l
e
s
Sc
h
,
Nu
m
b
e
r
o
f
No
r
m
a
l
i
z
e
d
5/
1
1
0
1
Re
v
e
n
u
e
No
,
Cu
s
t
o
m
e
r
s
(k
W
h
)
Re
v
e
n
u
e
Ad
j
u
s
t
m
e
n
t
s
(6
)
(7
)
(8
)
Au
t
h
o
r
i
z
e
d
To
t
a
l
Av
e
r
a
g
e
Pe
r
c
e
n
t
Re
v
e
n
u
e
It
l
k
W
h
Ch
a
I
N
e
Li
n
e
No
.
Ta
r
i
f
f
D
e
s
c
r
i
p
t
i
o
n
Un
i
f
o
r
m
T
a
r
i
f
f
R
a
t
e
s
:
Re
s
i
d
e
n
t
i
a
l
S
e
r
v
i
c
e
29
9
32
1
07
6
27
9
04
9
26
4
66
3
18
5
59
5
84
4
28
0
25
9
02
9
87
5
89
%
Sm
a
l
l
G
e
n
e
r
a
l
S
e
r
v
i
c
e
23
6
26
7
79
8
95
2
50
4
,
4
1
0
02
4
59
9
52
9
00
9
03
9
00
%
La
r
g
e
G
e
n
e
r
a
l
S
e
r
v
i
c
e
28
7
72
4
58
7
69
0
13
3
93
6
62
6
10
,
4
2
4
27
3
14
4
36
0
89
9
29
8
78
%
Du
s
k
t
o
D
a
w
n
L
i
g
h
t
i
n
g
95
0
84
1
60
0
13
2
76
8
62
2
90
0
27
,
27
2
1.
4
2
%
La
r
g
e
P
o
w
e
r
S
e
r
v
i
c
e
10
1
90
8
78
4
16
5
51
2
59
6
30
3
00
8
81
5
60
4
4.
4
9
6
30
%
Ir
r
i
g
a
t
i
o
n
S
e
r
v
i
c
e
34
3
67
8
,
54
7
07
1
62
2
69
8
6,
4
2
2
12
1
04
4
81
9
5.
4
8
4
50
%
Un
m
e
t
e
r
e
d
G
e
n
e
r
a
l
S
e
r
v
i
c
e
80
6
9,
4
4
1
29
1
63
9
,
77
4
12
2
67
5
89
6
15
9
65
%
Mu
n
i
c
i
p
a
l
S
t
r
e
e
t
L
i
g
h
t
i
n
g
81
6
54
5
02
4
,
4
2
3
51
4
08
4
93
7
13
,
18
2
99
%
Tr
a
f
f
i
c
Co
n
t
r
o
l
L
i
g
h
t
i
n
g
96
8
,
72
2
52
0
.
68
0
45
,
79
2
56
6
73
3
79
%
Su
b
-
To
t
a
l
35
7
23
4
69
9
17
4
32
6
58
8
02
4
52
4
93
5
04
1
62
8
95
9
56
5
87
9
96
%
ec
i
a
l
C
o
n
t
r
a
c
t
s
:
Mi
c
r
o
n
53
6
78
7
23
1
97
8
99
5
05
3
74
8
03
2
74
3
4.
4
7
7
34
%
12
F
M
C
05
1
20
0
00
0
84
2
36
7
02
1
89
1
86
4
25
8
98
3
10
,
63
%
13
J
R
Si
m
p
l
o
t
27
9
69
6
10
5
33
7
97
4
07
0
11
7
40
8
09
1
07
9
10
,
35
%
14
D
O
E
20
3
,
54
7
70
9
37
6
.
73
9
77
8
.
77
4
15
5
.
51
3
00
7
10
,
56
%
Su
b
-
To
t
a
l
07
1
23
1
04
5
53
6
07
5
92
4
53
0
85
,
4
6
0
60
5
12
6
10
,
22
%
16
To
t
a
l
A
n
n
u
a
l
I
d
a
h
o
R
e
t
a
i
l
S
a
l
e
s
35
7
23
8
77
0
40
5
37
1
66
5
56
0
59
9
85
9
57
1
71
4
,
4
2
0
17
0
59
4
34
%
kW
h
rt
/
k
W
h
Ad
d
i
t
i
o
n
a
l
P
C
A
T
r
u
e
-
u
p
C
a
l
c
u
l
a
t
i
o
n
85
6
74
8
77
0
40
5
37
1
38
2
6
In
t
e
r
e
s
t
T
h
r
o
u
g
h
10
/
1
/
0
1
U:I
K
h
e
s
s
i
n
l
l
P
C
E
0
1
1
1
l
C
o
m
m
i
s
s
i
o
n
s
S
e
c
o
n
d
D
e
e
l
s
l
o
n
l
R
e
v
e
n
u
e
A
l
l
o
c
a
t
i
o
n
9
/
2
6
/
0
1
K
D
H
..
.
-
..
.
-
Nt
'
-
-
1.
O
~
WN
W
I
0
()
Z
0.
.
.
c:
:
(
a
:
I-
W
C/
)
I-
0
0
c:
:
(
a
:
C/
)
c::
(