20020513Order No 29026.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AN ENERGY
COST FINANCING ORDER AND AUTHORITY
TO INSTITUTE AN ENERGY COST BOND
CHARGE.
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, 2002 THROUGHMAY 15, 2003.
CASE NOS. IPC-02-
IPC- E-02-
ORDER NO. 29026
On March 11 , 2002, Idaho Power Company filed an Application (Bond Application)
for an "energy cost financing order" authorizing the issuance and sale of up to $172 million in
Energy Cost Recovery Bonds (Bonds). The Bond Application requested that the Commission
allow Idaho Power to impose a usage-based Energy Cost Bond Charge (Bond Charge) ranging
between 0.50 and 0.65 cents per kilowatt hour (kWh). Bond Application at 18. Consistent with
its annual Power Cost Adjustment (PCA) filing and as an alternative in part to issuing Bonds
Idaho Power also filed an Application (PCA Application) on April 15, 2002.The PCA
Application, which included final forecast and true-up computations for this year s PCA
reiterated the Company s request that it be allowed to issue Bonds to recover up to $172 million
from customers over three years and recover the remaining true-up and forecast costs over a one-
year period using the traditional PCA rate. Idaho Power provides electric service to
approximately 370 000 customers in southern Idaho.
In this Order, the Commission denies Idaho Power s Application for authority to
issue Bonds. Instead, the Commission authorizes the recovery of $244.4 million over a one-year
period and defers $11.5 million to be recovered from the Irrigation and Small General Service
classes in the 2003-2004 PCA. We also discontinue the three-tiered rate structure for residential
customers. The Commission finds it appropriate to recover this year s PCA surcharge from
customer classes using a flat cents per kWh rate. Finally, the Commission authorizes Idaho
Power to implement a tariff rider to collect one-half of one percent (0.5%) of each customer
class s base revenues to fund Demand-Side Management (DSM) programs for its customers.
ORDER NO. 29026
I. BACKGROUND
A. Statutory Authority for Bonds
In 2001 , the Idaho Legislature passed Senate Bill 1255 (codified at Idaho Code
61-1501 et seq.
),
which allows energy utilities to recover increases in their short-term costs
through the issuance of moderate-term (1 to 5 years) bonds. At the time this legislation was
enacted, Idaho and the western United States were experiencing extraordinarily high wholesale
energy market prices and the second-worst water conditions ever recorded in Idaho. By enacting
this legislation, the Legislature provided an alternative to large rate increases caused by Power
Cost Adjustments (PCA) and other cost recovery mechanisms by permitting the issuance of
multi-year Bonds. Idaho Code ~ 61-1501. Thus, the legislation provides electric and gas public
utilities with a mechanism to recover extraordinary fuel or power costs immediately while
leveling" the rate impact on customers.
Idaho Code ~ 61-1503(2) states that the Commission shall not issue an energy cost
financing order unless the sum of: (1) any PCA then in effect; (2) plus any Bond Charge then in
effect; and (3) the amount identified in the utility's PCA Application would exceed a minimum
threshold amount previously approved by the Commission. In June 2001 , the Commission
established this minimum threshold amount as one cent per kWh (or approximately $128 million
in annual revenues) in Case No. IPC-01-19. Order No. 28761. Because the Company alleged
the amount recoverable in the present PCA Application will exceed this threshold, Idaho Power
requested authorization to spread recovery of the $172 million over three years by issuing Bonds
rather than recovering it through the standard one-year surcharge.
In reviewing Idaho Power s Bond Application, the Commission must determine if the
public interest would be better served by recovering the PCA amounts over the term of the
proposed Bonds (i., three years) or by a one-year recovery period without Bonds. Idaho Code
~ 61-1503(1). If it finds the Bond issuance to be in the public interest, the Commission shall
issue an energy cost financing order to allow Idaho Power to recover the approved PCA amount.
Id.
B. History of PCA
Because Idaho Power Company is an electric utility that relies predominantly upon
hydroelectric generation, the Company s actual costs of providing electricity (i., its "power
supply costs ) can vary from year to year depending upon changes in streamflow and market
ORDER NO. 29026
pnces. When streamflows or snowpacks are low, Idaho Power must rely increasingly upon its
other generating resources and/or off-system market purchases that are more costly than its
hydro generation. Conversely, in years of abundant streamflows with correspondingly plentiful
inexpensive hydro generation, the Company s power supply costs are lower. To ameliorate the
adverse consequences of fluctuating power supply costs both to customers and the Company, the
Commission instituted a "power cost adjustment" (PCA) mechanism in 1993.
The PCA is comprised of two major components. First, the Company is allowed to
recover its above normal power supply costs ! for the preceding 12 months2 including off-system
purchases used to serve Idaho system load.3 Second, rates are adjusted on an annual basis to
compensate for the forecasted succeeding 12 months' power supply costs based on expected
Snake River streamflows and storage. Order No. 24806 at 2-3. For example, for projected
periods of low water, the Company is allowed to recover its costs to generate or purchase the
necessary replacement power. For periods of high water, customers experience credits from the
sale of surplus power. Thus, under the PCA mechanism ratepayers receive a credit when power
costs are low and are assessed a surcharge when power costs are high.4 During the nine years
that the PCA has been in effect, there have been three annual credits that benefited ratepayers by
approximately $57.5 million. Until last year s extraordinary power costs, the PCA surcharge has
not exceeded $17.3 million a year.
Idaho Power rates are adjusted each May after the Company files its PCA
Application. The PCA rate usually extends from May 16 to May 15 of the following year.
Procedurally, PCA cases are normally processed on an expedited basis through the submission of
written comments. IDAPA 31.01.01.122.02.
1 The term "power supply costs" means additional purchases and fuel costs plus decreased surplus sales revenue.
2 Although the PCA mechanism historically recovers amounts accrued over 12 months, this PCA Application seeks
to recover 13 months of costs because last year s PCA only recovered costs for 11 months. See Order No. 28722 at
3 The term "Idaho system load" means that amount of electricity necessary to serve Idaho ratepayers.
4 The Company may recover 90% of the difference between the projected power cost and the Commission
approved base power cost. Order No. 25880.
5 Last year the Commission authorized Idaho Power to recover $217 million in PCA costs.
ORDER NO. 29026
C. The Bond Application
The Company proposes to finance approximately $172 million of accrued PCA costs
by issuing Energy Cost Bonds. Idaho Power s retail customers would pay the Bonds back over a
planned three-year period itemized on their monthly bills. By statute, the charge would be based
on energy consumed - a charge per kilowatt-hour. The $172 million represents three primary
components: (1) $147 million of Idaho Power s PCA costs associated with voluntary load
reductions for irrigation customers and for Astaris LLC; (2) $18 million of the remaining
uncollected expenses associated with the October 1 , 2001 PCA rate increase; and (3) up to $7
million in estimated overhead costs for issuing the Bonds. The Company anticipates the Bonds
will carry a 4.5% interest rate, which it described as the best bond rate attainable. Tr. at 291.
If the Commission approved the sale of the three-year Bonds, a special purpose
financing entity (SPE) would be created. The SPE would then issue Bonds and Idaho Power
would convey reimbursement rights to the SPE. Finally, customers would be assessed a monthly
Bond Charge to repay the SPE.
D. The PCA Application
This year s PCA includes forecasted costs and a true-up of last year s forecasted costs
to actual costs. The forecast rate of .2156~ per kWh is expected to recover approximately $28.
million. PCA Application at 3. The true-up amount that the Company would include in this
year s PCA is approximately $223.3 million. Id. at 4. The Company proposes to recover $147
million of the true up amount over three years by bonding, which would require the Company
customers to repay the cost of the bonds. The remaining true up amount, $76.3 million, would
be recovered with a one-year PCA rate of .5785~ per kWh. Tr. at 294. The Company estimates
first year bond cost to customers to be .5600~ per kWh. Tr. at 295. The PCA costs would be an
additional .7941~ per kWh which includes the additional true-up and the forecast costS.6 This
year s total PCA rate including bonding would be 1.3541~ per kWh which would provide an
average rate reduction of 6.64 percent, 5.38 percent to the residential class. Tr. at 295.
If the Commission denies the Company s request to issue Bonds, the Company
requests authority to implement a Power Cost Adjustment (PCA) of 2.2885~ per kWh applicable
to all customers for the period May 16, 2002 through September 30, 2002, and a PCA of 1.9059~
6 .7941~ = .5785~ + .2156~
ORDER NO. 29026
per kWh for the period October 1 , 2002 through May 15, 2003. Tr. at 271. In other words, the
Company seeks to recover $223.3 million in additional power supply costs incurred from March
2001 through March 31 , 2002 and $28.5 million for next year s projected power supply costs
in a single year. Approximately $18 million remains on the current PCA for recovery during the
October 1 , 2001 through September 30, 2002 time period, thus making the total amount
requested $269.7 million.
If approved, this single year recovery alternative would result in an average rate
increase of 10.1 % to all customer classes effective May 16 2002. Tr. at 271-72. On October 1
2002, customer rates would decrease by an average of 6.2%. Tr. at 272.
E. Proceedings
Although the Company filed separate Applications for authority to issue Bonds and to
recover the PCA costs, the Commission consolidated the Applications into a single proceeding.
Order No. 28988. The Commission further established deadlines for intervention and public
comment, scheduled public workshops and hearings, and set a technical hearing for April 26
2002.
To gather public input on the Bond and PCA Applications, the Commission held
three workshops and public hearings in Twin Falls, Pocatello, and Boise. Approximately 84
people attended the workshops and 77 people attended the three hearings. Of those who
attended, 30 people testified at the hearings. In Order No. 28988 , the Commission also solicited
written public comments regarding the Applications to be filed on or before April 26, 2002. The
Commission received 274 timely written comments from the public.
F. Parties
The following persons were made parties to the Bond and PCA proceedings.
Parties Counsel
Idaho Power Company Larry D. Ripley
Commission Staff Lisa Nordstrom
Deputy Attorney General
Land & Water Fund of the Rockies
Idaho Rivers United
Idaho Rural Council
Mary McGown
William M. Eddie
ORDER NO. 29026
R. Simplot Company R. Scott Pasley
Industrial Customers of Idaho Power Peter J. Richardson
Richardson & O'Leary
Idaho Power Company, Commission Staff, and the Industrial Customers of Idaho
Power (ICIP) each filed written testimony. With the permission of the Commission and other
parties, the Land & Water Fund of the Rockies, Idaho Rivers United, Idaho Rural Council and
Mary McGown (collectively referred to as the Conservation Groups) provided written comments
directed solely at policy issues involving residential tiered rates and funding of Demand-Side
Management (DSM) conservation programs. J.R. Simp lot Company did not file written
testimony and did not participate at the technical hearing. Staff and the Company participated in
all of the public hearings. With this background, we turn to the issues.
II. COMPONENTS OF THE POWER COST ADJUSTMENT
A. The Water Forecast
As explained above, the forecasted water conditions for the next 12 months are the
second component of the PCA. In their respective testimonies, Idaho Power witness Greg Said
and Staff witness Keith Hessing agreed that expected power supply costs for the period April 1
2002 through March 31 2003 totaled $106 509 695, based on forecasted April through July 2002
stream inflows into Brownlee reservoir.Tr. at 267; 490-91. Above normal forecast costs
totaled $33.4 million, of which the Idaho jurisdictional share is $28.5 million. Staff and the
Company agreed that a rate of .2156~ per kWh was necessary to recover anticipated power
supply costs. Tr. at 268; 490. Staff witness Hessing testified that this rate is based on projected
Brownlee April through July inflows of 3.63 million acre-feet, which are only 58% of normal
due to last year s drought. Tr. at 490. The other parties did not dispute these calculations.
Commission Findinf!s Based upon our review of the record, the agreement of Staff
and Idaho Power, and the lack of any disagreement by the other parties, the Commission finds
that the appropriate PCA rate attributable to predicted streamflows is .2156~ per kWh. The PCA
was designed to allow consistent recovery of anticipated power supply costs, particularly when
less water is available for hydro generation. Thus, the Commission finds it reasonable and in the
public interest to allow recovery of the forecasted power supply costs in the current 2002-2003
PCA.
ORDER NO. 29026
B. Excess Purchased Power Supply Costs
Of the total $269.7 million PCA revenue requested by the Company, approximately
$223.3 million is attributable to last year s unrecovered power supply costs. This amount
includes $185.9 million resulting from the irrigation and Astaris load-reduction programs. Case
Nos. IPC-01-3 and IPC-01-9. The $223.3 million requested by Idaho Power also includes
approximately $18 million authorized for recovery by Order No. 28852 last October that has not
yet been recovered.
Staff recommended that the Commission only allow recovery of $207.3 million of the
$223.3 million in power supply costs. Staff indicated that these costs were reasonably and
prudently incurred to serve the Company s Idaho customers. The Company and Staff agreed on
one adjustment regarding real-time pricing.
Idaho Power s PCA Application decreased the true-up component by approximately
$4.3 million to reflect the repricing of "real-time" power purchases from July 2001 through
March 2002. These purchase transactions were originally priced under the Federal Energy
Regulatory Commission s (FERC) method, in which Idaho Power received IE's highest purchase
price in any hour for energy transfers to IE and paid IE's lowest sales price in any hour for
energy transfers from IE. Tr. at 282. However, Idaho Power asserted ratepayers were
disadvantaged under the FERC method because at times these transactions were: unrelated to the
Northwest markets; there was no weighting by volume; and there were more trading hours
without real-time transactions in them than when both purchases and sales were used. Tr. at 283.
Although not approved by FERC, Idaho Power proposes to use a weighted average of
all relevant IE purchases and sales transactions to set the real-time prices for transactions with
Idaho Power. This weighted average method would provide a market proxy for what Idaho
Power would have paid or received from a non-affiliate and was initially approved by this
Commission in Case No. IPC-OO-13. Tr. at 283. Idaho Power witness Gale further testified
that the Company continues to work with FERC to resolve this issue. Tr. at 285-86. Staff
reviewed the Company s real-time adjustment and agreed that it was needed to reflect a more
equitable transfer pricing methodology for both the Company and its customers. Tr. at 421. The
other parties did not take a position on this issue.
Commission Findinf!s The Commission finds that the real-time pricing adjustment
which was agreed to by the Company and the Staff, is reasonable and should be adopted. Thus
ORDER NO. 29026
the PCA's true-up component should be decreased by $4 306 635.82 to reflect the repricing of
real-time transactions from July 2001 through March 2002. This adjustment benefits ratepayers
and allows real-time pricing to be based on regional markets that reflect the cost of power bought
and sold in the Northwest, rather than the United States as a whole. Moreover, it is consistent
with the methodology approved by this Commission in Case No. IPC-OO-13.
Staff also recommended that $16 million in unrecovered power supply costs be
More specifically, the Staff recommended four adjustments for: 1) irrigation lostdenied.
revenues; 2) mobile generation expenses; 3) Mountain Home gas transportation costs; and 4)
Williams capital facility charge be denied recovery in the PCA. Tr. at 423-28. Parties other than
Idaho Power neither supported nor disputed the Staffs four adjustments. We address the Staffs
four adjustments below.
1. Irrigation Lost Revenue Adiustment.Last year, the Commission approved a
program to pay irrigators to reduce their consumption of energy and authorized Idaho Power to
recover its direct costs associated with the program in this year s PCA. Order No. 28992. Staff
verified $73 941 839.42 in direct program costs and that they were properly included in the PCA
account. Tr. at 424. In addition to these direct costs, Idaho Power calculated that it "lost"
$15 146 639.32 in revenue when irrigators participated in the Irrigation Load Reduction
Program.Staff recommended disallowance of the "lost" revenues per Order No. 28992, in
which the Commission denied recovery of the Company s reduced revenues. Id.
Commission Findinf!s This issue has been thoroughly addressed during the
proceedings in Case No. IPC-01-34. In that case we stated
, "
in the context of the market
situation that existed at the time this Program was approved, it was the prudent if not required
action for the Company to take and that further incentives, such as the recovery of lost revenues
to develop and utilize a program of this type were not needed.Order No. 28992 at 7-
Consistent with our final Order in Case No. IPC-01-, we disallow recovery of the
$15 146 639.32 included by Idaho Power.
2. Mobile Generation Adiustment.Because forward market prices for the summer
and fall of 2001 were projected to be more than $200 per megawatt-hour, Idaho Power leased 25
7 "Lost" revenue refers to revenue that the utility would have earned if it had sold power to the participating
irrigators instead of paying the irrigators to reduce their electric consumption.
8 On May 2 2002, Idaho Power filed a Petition for Reconsideration in Case No. IPC-01-34.
ORDER NO. 29026
diesel-powered generation units during the months of May through October 2001. After
installing and operating 17 of the 25 units for a few days, Idaho Power shut them down because
of complaints from nearby homeowners and attempted to relocate them. The remaining 8 units
had not yet begun the siting permit process when the Company applied for new siting permits for
the 17 units that were to be relocated. After FERC-mandated price caps were implemented for
western energy trading in June 2001 , the market price of purchased power dropped below the
operating cost of the units. As a result, the units were not operated after that time.
In September 2001 , the Commission authorized the Company to use the PCA
mechanism when it sought to recover its mobile generation expenses. However, the Commission
stated that recovery of such expenses would occur after first determining whether the expenses
were reasonably incurred. Order No. 28837 at 7. In comments filed in Case No. IPC-01-
that were included with Staff witness Alden Holm s testimony in these cases, Staff expressed
concern that the Company s voluntary shut down of the 17 units was unreasonable and costly to
the general body of ratepayers. Staff Exhibit No. 101 at 3. By never applying for siting permits
for eight of the generators, Staff argued that ratepayers were subjected to paying for the units
without any offsetting benefits. Id.Thus, Staff recommended in this proceeding that the
Company s associated power costs be reduced by $3 832 663 to reflect diesel generation costs
and purchased power benefits that would have occurred if the 25 generating units had been
continuously dispatched against market prices beginning May 1 , 2001. Tr. at 425. Idaho Power
did not address Staff s recommended adjustment in its testimony.
Commission Findings. As a preliminary matter, the Commission first addresses a
procedural" argument made by Idaho Power during the April 26, 2002 technical hearing. While
questioning Staff witness Alden Holm on his proposed disallowance of mobile generator
expenses, counsel for Idaho Power argued:
Staff has not presented any new evidence to allow or to contend for any
disallowance. They simply relied upon what they previously submitted to the
Commission, what the Commission had. . . before when it issued the orders
authorizing the inclusion of certain costs in the PCA.
Tr. at 448.However, Idaho Power s argument is misplaced. The question is not whether the
Staff s evidence is "new" or "old" but if it is relevant to the question of whether mobile
generator expenses were reasonably incurred. In Order No. 28837 issued in September 2001 , we
stated:
ORDER NO. 29026
We make no decision in this case regarding the dollar amount to be included
in the PCA nor do we foreclose the Staff or other parties from challenging the
reasonableness of said amounts when the Company requests recovery.
Order No. 28837 at 7. With these words the Commission made clear that while the Order
allowed mobile generator expenses to be recovered through the PCA, we did not approve a
specific dollar amount for recovery until the expenses could be formally reviewed in the
Company s PCA filing. Thus, the Commission did not authorize a recovery amount for Idaho
Power s mobile generators at that time and purposely left the issue open. Although Idaho
Power s counsel argues that the Commission "simply got a regurgitation of a prior argument
made already to the Commission " we find Staffs IPC-01-14 comments as incorporated into
its filed testimony in these cases to be adequate evidence regarding this issue. Tr. at 448. Staff
was not required to provide additional evidence. In fact, Staff simply resubmitted its prior
consistent comments which does not make this evidence defective. As the record stands, Staff s
recommendation to disallow $3 832 663 of the mobile generator expenses has not been rebutted
by Idaho Power. We now turn to the substantive issue of whether or not the Commission should
authorize recovery of the Company s mobile generator expenses.
In September 2001 , the Commission directed Idaho Power "to plan for (deficient)
power supply in advance and take prudent steps to have adequate, reliable supply available.
Order No. 28837 at 6. We also recognized in that Order that if months later it appears "that other
options turned out to be lower cost, (that fact) does not invalidate the prudent decision made
based on information known at the time.Id.In other words, we would evaluate the
reasonableness of Company actions in the context of the known information and events at that
time.With this standard in mind, the Commission generally finds that the acquisition of
generation units at that time was prudent and reasonable.
Although leasing the units was reasonable, it is apparent that the Company s decision
about where to operate the units is less so. We share the Staffs concerns regarding Idaho
Power s unilateral decision to idle and relocate 17 of the 25 generators without the permits
necessary to resume operation in another location. Had those 17 generators been operational
Idaho Power could have purchased less power on the costly wholesale market. However, we
also recognize the concerns expressed by nearby residents regarding whether the units were
placed at appropriate locations even though the sites were properly permitted. The other eight
ORDER NO. 29026
units were not operated. We find it reasonable to allow recovery of the costs associated with the
17 generating units and power purchase costs incurred as a result of shutdown. However, we
disallow the costs associated with the failure to site and operate the remaining 8 units.
Ratepayers never had an opportunity to receive benefits that would have occurred had these 8
units been properly sited and operated. These units were never used and useful in generation of
power. Therefore, the Commission disallows recovery of $1 226 452 of purchase power costs
because the 8 units never operated during May and June 2001.
3. Mountain Home Gas Transportation Adjustment.In Order No. 28773, the
Commission allowed Idaho Power to account for and recover expenses associated with fuel and
transportation for its natural gas fired plant in Mountain Home through the PCA mechanism.
Although Idaho Power is not required to pay for unneeded fuel, the Company must pay for firm
fuel transportation if it intends to use the plant when market prices are higher than the cost of
running the plant.
Staff argued that $682 272.40 of the Company s $3.3 million in fuel expenses should
be disallowed because the plant was not operational during part of the time period for which
Idaho Power had contracted for firm fuel transportation. Tr. at 427. The Company contracted
for firm transportation on April 11 , 2001 , projecting that the plant would be finished in July
2001. However, due to various delays, the plant did not operate until September 25 2001. Staff
maintained that because customers never had the opportunity to benefit from the transportation
expense incurred by the Company during the months of July, August and most of September, it
was not "used or useful" during that time period. Id. The Company did not address this issue in
its testimony.
Commission Findinf!s We find that payment for firm transportation prior to the
facility becoming operational was not a reasonable expense. Once the plant is operational, it is
important to have firm transportation available so that the plant can be operated when market
prices are higher than the cost of running the plant. However, the Mountain Home facility did
not require a firm transportation commitment when non-firm options would have satisfied the
Company s testing, maintenance and training requirements before the plant became operational.
The Company was not able to mitigate these expenses by reselling the unnecessary firm
9 $1 226 452 = (8/25) x (3 832 663)
ORDER NO. 29026
transportation because there was little demand for firm transportation in the summer months.
Because ratepayers never had an opportunity to benefit from the plant and it was not used and
useful until September 25, the Commission disallows recovery of the $682 272.40 associated
with this period.
4. Williams Facility Charge Adjustment.Williams Gas Pipeline West (Williams)
charged Idaho Power the first annual billing for payment of $419 054 to install a meter station
control equipment, and a 4 200 foot pipeline from the mainline to Idaho Power s Mountain
Home natural gas facility. A fluctuating annual facility charge will pay for these items over the
next 30 years. Staff argued that this charge is more like a capital cost than an annual gas delivery
expense. Thus, it would be more appropriate to seek recovery of this amount as a capital asset
cost in ratebase than to be recovered through the PCA. Tr. at 427-28. The Company indicated
that because it is booked to a PCA-appropriate account, is fuel-related, and varies year to year
the facilities charge is appropriate for inclusion in the PCA. Tr. at 561.
Commission Findinf!s The Commission finds that although the facilities charge is
not a capital expense per se, it has many of the characteristics of a capital expense normally
recovered as an asset in rate base. The charge pays for plant investment over time and includes
expenses related to depreciation, interest, a return and maintenance on the plant investment.
Although this charge enables Idaho Power to buy fuel from Williams, the repayment structure
over 30 years is typical of a capital investment. Thus, the facilities charge should be considered
for recovery in Idaho Power s next rate case - not in this PCA case. The $419 054 shall not be
recovered through the PCA.
In summary, the Commission finds that $209 414,437.79 in excess power supply
costs should be recovered through the PCA mechanism as true-up expenses that were reasonably
and prudently incurred.
III. RECOVERY OF DEFERRED PCA AMOUNTS
Having determined that the Company is authorized to recover $255.9 million
through the PCA, we next must decide how this amount is recovered from ratepayers. The
Commission was presented with a variety of methods to recover the deferred PCA costs. These
options included securitizing a portion of the amount through the issuance of Bonds, instituting a
to $255 894 232 = 28 479 794 (forecast) + 209 414 438 (true-up) + 18 000 000 (unrecovered October 1 2001 PCA).
ORDER NO. 29026
multiple-year recovery without issuing Bonds, and implementing a traditional single-year
recovery. We address these alternatives below.
A. Energy Bonds
1. Idaho Power. Idaho Power s preferred method of recovering a portion of the
deferred PCA amount is to securitize the amount by issuing Bonds. According to Idaho Power
witness Ric Gale, spreading the recovery of a portion of these costs over a number of years offers
an opportunity to reduce rates immediately and finance these costs at favorable interest rates. Tr.
at 288. The Company proposes to issue $172 million in Bonds. When both the fees and interest
are considered, the average percentage rate of the financing will range from 5.9% to 7.
depending on the final administrative costs. Tr. at 294.
Mr. Gale testified that authorizing bonds would immediately increase the Company
cash flow and improve its financial ratios because rating agencies exclude bond financings in
their ratio analysis. Tr. at 298. The Company proposed that the remaining true-up costs , $76
million, and the water forecast amount of $28.5 million be recovered in one year through a
separate PCA rate. Moreover, Idaho Power witness Greg Said calculated that issuing three-year
energy bonds would result in an immediate rate decrease of 6.6%. Tr. at 272.
2. ICIP . The Industrial Customers of Idaho Power (ICIP) supported the concept of
bonding but urged the Commission to spread the proposed rate increase over a period of five
years (the maximum amount of time allowed under the energy Bond statute). The ICIP believes
last year s rate increases put Idaho s industry at a serious competitive disadvantage that may be
aggravated if a rate reduction is not immediately forthcoming. Tr. at 373-74. According to ICIP
witness Stuart Trippel, bonding appeared to be " a fair and equitable way to accomplish this goal
with minimal financial impact on Idaho Power and its ratepayers.Tr. at 273. The ICIP
advocated spreading recovery over five years because "the benefits of extending the pay back
and further lowering our rates far outweigh the perceived harm from pancaked rates." Tr. at 374.
3. Commission Staff.Although it acknowledged the benefits Idaho Power would
receive if Bonds were issued, Staff did not support the issuance of Bonds because "the costs and
risks to customers for securitization outweigh the benefits to customers." Tr. at 433. According
to Staff, issuing Bonds would alter the existing PCA mechanism s allocation of responsibility for
carrying charges on the deferred amounts during recovery from the Company to customers. Tr.
at 431. Staff was also concerned about additional expenses to be paid by customers, that would
ORDER NO. 29026
include up to $7 million in initial borrowing fees, $1.5 million in ongoing servicing fees and
trustee expenses, and approximately $12 million in interest expenses over the three years. Tr.
432. Staff also feared a "pancaking effect" would result if customers are paying off the Bonds at
the same time large future PCA expenses must be recovered. Id.
Commission Findinf!s.Based on our review of the record in this case, the
Commission denies the Company s Bond Application. The Commission has carefully reviewed
Idaho Code ~ 61-1503(1), which states in pertinent part:
. .
.if the commission finds that the public interest would be better served if the
energy cost amounts were recovered through the issuance of energy cost
recovery bonds over the term of such bonds than if the ECA amounts were
recovered over a period of one (1) year, assuming a conventional financing of
such amounts, the Commission shall issue an energy cost financing order to
allow the public utility to recover energy cost amounts.
The Commission finds that the public interest is better served in this instance by recovering the
vast majority of the $255.9 million authorized in this Order over a single year as originally
contemplated by the PCA mechanism rather than spreading large amounts of recovery over
multiple years. We reach this conclusion largely out of our concern for uncertainties the future
may hold.
One of our primary concerns is the water supply necessary to generate the electricity
that Idaho Power relies on to supply 60% of its system load. Snowpacks the last two years have
been significantly lower than average, particularly in the upper Snake River Basin. Idaho
reservoirs have not yet refilled and the opportunity to generate hydroelectricity is thus
diminished in the near term.If another drought year were to occur while Bonds were
outstanding, electricity rates could easily climb again.
In addition to the unpredictability of the weather, the Commission is concerned about
potential volatility in the western wholesale power markets once FERC's price mitigation orders
terminate on September 30, 2002.11 Although structural changes have been made to the regional
wholesale market since FERC's orders were issued in 2001 , prices may escalate again once the
price restrictions are removed. The Commission is loath to knowingly enter a period of market
uncertainty with large amounts of deferred PCA costs slated for recovery through 2004.
11 San Diego Gas & Electric Company, 95 FERC ~ 61 418 (June 19 2001).
ORDER NO. 29026
The Commission is also concerned that the longer power supply cost recovery is
delayed, the greater the risk that the customers taking service when the deferred costs were
incurred will not be the same customers that will later pay for them. A significant number of
public commentors, in writing and at the public hearings, indicated that it was preferable to pay
off the PCA amount in a single year rather than pay the carrying costs associated with deferral.
We largely agree with this sentiment. The Commission also questions the fairness of requiring
Idaho Power ratepayers to pay the approximately $21 million in interest and fees associated with
energy bonds when IdaCorp s unregulated subsidiaries will benefit as a result. Tr. at 332-
567-68. Based on the facts of this case, we find it unreasonable and contrary to the public
interest to mortgage the future of ratepayers simply to achieve a small rate decrease this year.
The Commission is sympathetic to the concerns of the Industrial Customers that a
rate increase will place them at a competitive disadvantage. However, spreading recovery over
multiple years in exchange for a small decrease this year will prolong high power rates and delay
the substantial rate decrease that all customers seek. Adding nearly $21 million in bond fees and
interest to the $269.7 million requested by Idaho Power is an expensive price to pay for the
option of multi-year PCA recovery. Thus, the Commission declines to authorize issuance of
energy bonds for recovery over three years, or over five years as the Industrial Customers
requested.
According to the testimony of Idaho Power witness Gale, only one year of
extraordinary high costs remain to be recovered through rates. Tr. at 288. We certainly hope
that this is the last year Idaho Power ratepayers will be faced with such extraordinarily high
deferred PCA costs. However, as we have learned over the past two years, there are no
guarantees about future streamflows or market prices. In short, the Commission does not want to
spread large amounts for recovery out over multiple years, and it is not cost-effective to
securitize smaller amounts. Tr. at 433. Because mortgaging our future through the issuance of
Bonds is not in the public interest at this time, we turn our discussion to other recovery options.
B. Other Recovery Alternatives
1. Idaho Power. Under normal operations, the PCA surcharge or credit is effective
over a 12-month period. If the Company s energy bond proposal were rejected, Idaho Power has
indicated that its secondary proposal is the one-year recovery associated with traditional PCA
ORDER NO. 29026
treatment. Tr. at 272. That proposal would increase existing rates now and reduce them on
October 1 , 2002 as the second part of last year s PCA increase expires.
2. Commission Staff.Staff presented four recovery options in its testimony. The
first option consisted of the Company s securitization proposal with Staffs adjusted true-up.
Option No.2 recovered all of the PCA costs in the first PCA year, which required an increase
above existing rates. The third option continued the existing rates in the first PCA year and
carried the unrecovered costs over to the 2003 PCA year with interest. Staff Option No.
reduced rates in the first year by an average amount of9.6% and carried the unrecovered amount
into the 2003 PCA year for recovery.Staff recommended the fourth option because it
immediately decreased rates, recovers the PCA costs in two years, and avoided bonding costs
and some of the interest associated with securitization. Tr. at 496.
3. ICIP. The ICIP requested that if a multiple-year recovery option were adopted by
the Commission, the Industrial Customers would like a one-year option to be offered. Tr. at 359.
Under such an arrangement, individual customers within a certain schedule or who use a
threshold amount of kilowatt hours could choose by a date certain to pay the entire amount based
on the customer s historical consumption within one year, rather than extend payment of the
PCA amount over multiple years. Tr. at 360-, 363 , 366. At the end of the year, the estimated
one-year payment amount would be trued-up to reflect actual usage. Tr. at 366.
Commission Findinf!s While the Commission understands the reasons why cost
recovery or some portion thereof might be amortized over time, the Commission largely declines
to adopt this recommendation. As with any requested rate increase, the Commission must
balance the needs of the Company to maintain its financial viability and recover its reasonable
expenses with customer concerns of fair rates and rate stability. During the last two years
extraordinary conditions have resulted in large purchase power costs and a low water forecast.
Given the amount of purchases the Company has already made, it is reasonable and appropriate
for the Company to recover the majority of the $255.9 million approved for recovery within the
normal one-year timeframe.
The Commission does not make this decision lightly. We understand the hardships
that continuation of last year s large rate increase will impose on customers. However, as we
stated in our Energy Bonds findings, the Commission is very concerned about the unknown
water and market conditions that lie ahead. Weare also reluctant to create a situation where
ORDER NO. 29026
customers are required to continue paying costs from this year on top of whatever increases may
be required in future years. Passing through the majority of the PCA costs in one year will be
unpleasant and create a hardship for some customers, but it will clear the way for significant rate
decreases in the future barring any unforeseen circumstances. The PCA was designed for a
single-year recovery of PC A costs and we continue to honor its original design.
We noted in the original PCA Order that if the PCA were to result in large rate
increases, it may be appropriate to defer a percentage of that year s power supply costs. Order
No. 24806 at 20. In Order No. 28722 issued in last year s PCA case, we declined to spread
recovery out over a period longer than one year despite the large rate increases that resulted.
When forced to increase rates yet again this year, we find it is appropriate to make some rate
allowances for the Irrigation (Schedule 24) and Small General Service (Schedule 7) customer
classes.
At the public hearings, several irrigators testified that they were not aware that a 7%
increase in irrigation rates was approved by the Commission last October. Tr. at 102-, 121-22.
This can largely be attributed to the fact that most irrigators typically end their seasonal usage in
October. Thus, the irrigation class as a whole had very little opportunity to adjust to the October
rate increase. Moreover, it is likely that the typical irrigator did not include that increase in
his/her budget when calculating expenses for 2002. Tr. at 122. Rather than increase irrigation
rates by 11.5% to recover the $35.6 million allocated to the irrigation class in a single year, the
Commission finds it appropriate to defer $11.0 million for recovery in the 2003-2004 PCA and
recover the remaining $24.6 million in irrigation rates this PCA year. Although the majority of
the irrigation class s PCA costs will be recovered in the traditional PCA period, deferring the
$11.0 million willlirnit their rate increase to the 5.051~ per kWh rate ordered last May in Order
No. 28722. The $35.6 million in total PCA costs allocated to the irrigation classjncludes the
$20 134.29 attributed to the irrigation class in Order Nos. 28699 and 28770 for intervenor
funding.
The Commission also finds it reasonable to defer $600 000 of the total $5.2 million in
PCA expenses attributable to the Small General Service customer class (Tariff Schedule 7) until
the 2003-2004 PCA year. The Small General Service class typically includes small businesses
12 If confronted again with extraordinary power costs, another alternative would be to implement an immediate
interim surcharge rather than defer such costs for recovery in the next 12-month PCA.
ORDER NO. 29026
and outbuildings that use less than 3 000 kWh per month. With the exception of the Lighting
classes, the Small General Service class was the only class to have rates set in excess of 8~ per
kWh after last October s rate increase. Order No. 28852. Rather than raise their rates above the
already high 8.021~ average rate Schedule 7 customers currently pay, the Commission finds it
appropriate to minimize hardship to this class by continuing their current rate for this PCA year
and to allow recovery of the remaining portion next year.
IV. THE CARRYING CHARGE
By previous agreement between the Company and Staff, a single Commission-
approved carrying charge or interest rate (i., the interest rate paid on customer deposits
effective at the beginning of the PCA year) has previously been used to calculate interest on
balances for all months in the PCA deferral year.13 IDAPA 31.21.01.106. The carrying charge
used during the 2001-2002 PCA deferral period is 6%. The carrying charge for calendar year
2002 is 4%. Prior to this Order, the Commission had not determined the appropriate carrying
charge if balances were ordered to be carried for periods longer than one year. The parties
recommended several interest rates.
1. Idaho Power.Because deferral balances are greater than ever anticipated and the
energy crisis has disrupted the "symmetry of outcomes" originally envisioned for the PCA, Idaho
Power recommended changing the interest rate applied to the deferral balances to be the same as
the Company s overall rate of return (9.2%) on a prospective basis beginning June 1 , 2002. Tr.
at 295-96. The Company asserted that the overall rate of return more appropriately reflects the
Company s significant costs of financing large balances.
2. Commission Staff.Staff did not agree with using the Company s overall rate of
return for calculating the carrying charge, largely because steps have been taken to limit the
amounts in the deferral account going forward. Tr. at 434. Instead, Staff advocated leaving the
PCA mechanism unchanged with carrying charges continuing to accrue at the customer deposit
rate (4%). However, Staff also recommended that the Company should be able to accrue interest
equal to the larger of its short-term debt rate or customer deposit rate for amounts held in the
deferred account longer than the traditional one-year recovery period. Tr. at 435-36.
13 This practice was instituted to simplify the true-up calculation and adopts the interest rate established by the
Commission at the beginning of each calendar year.
ORDER NO. 29026
3. ICIP.The ICIP stated that it is reasonable and fair for the Company to receive
interest on deferrals, but it did not specify an interest rate to be applied. Tr. at 377.
Commission Findinf!s To remain consistent with prior PCA case~, the Commission
declines to change the rate applied to PCA balances in the deferral period and continues to find it
appropriate to apply the 4% customer deposit interest rate to the deferred balances. The current
customer deposit rate of 4% will be applied to balances being deferred during the traditional 12-
month PCA deferral period of April 1 , 2002 through March 31 , 2003.
However, the Commission also recognizes the additional costs associated with large
deferral balances - particularly those extending beyond the traditional one-year PCA recovery
period. Thus, the Commission finds in this instance that it is appropriate for the Company to
receive a higher interest rate than the current customer deposit rate of 4% on the $11.5 million
that will be deferred for recovery beyond one-year.The Commission finds that 6% is
reasonable rate. This carrying charge is higher than the deposit rate and short-term debt rate but
lower than the rate of return. This rate is also reasonable given that it was the customer deposit
rate applicable in the 2001 PCA year when the deferral amounts were incurred.
V. FUNDING OF DEMAND-SIDE MANAGEMENT PROGRAMS
1. Idaho Power. In response to Order No. 28922 , Idaho Power Company proposed a
tariff rider as a means of funding conservation or Demand-Side Management (DSM) programs in
Case No. IPC-OI-13. The rider, as proposed, would be 0.5% (one-half of one percent) of the
Company s base revenue requirement on all electric bills for all customer classes. It has been
estimated that the rider would provide approximately $2.6 million annually for DSM measures.
Tr. at 500.An Energy Efficiency Advisory Group - comprised of customer representatives
Company and Commission Staff personnel, and conservation program experts - has been formed
to review DSM programs for all customer sectors and make recommendations to Idaho Power
accordingly. Idaho Power supported funding conservation progi-ams through an Energy
Efficiency Rider because it does not add to the already significant DSM deferred balance
approximating $27 million for past DSM programs. Tr. at 310.
2. Commission Staff.Staff also supported approval of a 0.5% tariff rider to fund
additional conservation efforts. Tr. at 500. Staff further recommended that the approximate $2.
million generated by this tariff rider be included in rates this year. This would cause additional
ORDER NO. 29026
true-up amounts to be deferred with interest to allow customers to receive the full decrease
proposed by Staff for this PCA year. Tr. at 501.
3. ICIP. The ICIP testified that DSM costs should be recovered by Idaho Power on
an ongoing basis and that the industrial class should be permitted to self-direct all funds collected
from it for DSM purposes rather than funnel it through other agencies. Tr. at 377.
4. Conservation Groups. In their written comments, the Conservation Groups stated
that the 0.5% of Company revenues recommended by Idaho Power and Staff is too low to fund
all cost-effective DSM opportunities. Instead, they recommended that the tariff rider be set at a
level of 1.5% of revenues. The Conservation Groups also indicated that the Commission should
direct Idaho Power to initiate a comprehensive study to evaluate cost-effective DSM
opportunities in its service territory, which identifies: (1) cost-effective DSM opportunities in
each customer class; (2) estimated costs to fully fund those opportunities; and (3) opportunities
for reductions in peak loads as well as reductions in total energy consumption. According to the
Conservation Groups, the Commission should approve the tariff rider subject to later review and
require Idaho Power to report regularly on DSM program implementation, costs, customer
response, and new DSM opportunities.
Commission Findinf!s In granting the rate increase authorized by this Order, the
Commission recognizes that consumers need avenues to reduce their consumption. As we
recognized in Order No. 28722, conservation and DSM programs are powerful tools Idahoans
can use to mitigate the impact of this rate increase as well as ones that may occur in the future.
The Commission believes that funding a comprehensive conservation program is critical given
last year s market volatility and the opportunity to benefit from long-term demand-side
measures.
The Commission finds it reasonable to authorize a tariff rider in the amount of 0.
of each customer class s base revenues to support analysis and implementation of new DSM
programs. This amount may be increased in the future if necessary to take advantage of other
cost-effective DSM measures as circumstances warrant. This tariff rider shall appear as a line
item expense on customers' monthly bills so that customers are advised what portion oftheir bill
goes toward energy conservation. This tariff rider shall be imposed as a flat $0.30 per-month
charge to residential customers and as a cent per-kilowatt hour charge for all other customer
classes. The maximum amount charged to any irrigation meter under this tariff shall not exceed
ORDER NO. 29026
$15.00 per month. The irrigation rate will be .0301~ per kWh applied to a maximum of 50 000
kWh per meter. These charges are set out in Appendix 1 in greater detail. We recognize that
this amount of funding may not be adequate to support some programs that could be very
beneficial. However, we find it is a reasonable starting point and will reassess the level of this
change annually.
We believe the Energy Efficiency Advisory Group will be a valuable resource in
recommending and evaluating potential conservation programs for Idaho Power.The
Commission expects that the Advisory Group will meet frequently to recommend the initial
DSM programs and at least quarterly thereafter. The Company shall file an annual written report
to the Coinmission detailing: the Advisory Group s recommendations, the Company s response
to those recommendations, the associated program costs, the DSM accounting numbers
customer response data, and information on new DSM opportunities. Idaho Power shall file this
annual report no later than January 30 of each year, so that the Commission may review the
DSM programs and adjust the rider if necessary when the new PCA rate is implemented in May.
Furthermore, Idaho Power shall consult the Energy Efficiency Advisory Group
regarding the need to initiate a comprehensive DSM study of the IPC service territory relative to
the priority for DSM funds to identify: (1) cost-effective DSM opportunities in each customer
class; (2) estimated costs to fully fund those opportunities; and (3) opportunities for reductions in
peak loads as well as reductions in total energy consumption.
The Commission is particularly concerned about DSM programs for the Residential
Class. As discussed in further detail below, the return to a uniform residential rate will eliminate
the less costly rate designed to provide a reasonable rate for basic electrical service necessary for
customer health and safety. It is our hope that the programs created by the DSM rider will
empower customers to exercise control over their energy consumption and reduce their bills.
see the merit of the three efforts (Energy Code Support, Public School Energy Efficiency and
Residential New Construction Pilot) cited by Idaho Power in its May 2, 2002 DSM report as
beneficial programs that could be quickly developed and deployed. However, we believe
residential DSM dollars are better spent on CFL coupon programs and pilot programs that can be
expanded to the entire customer base rather than education alone. We also direct the Advisory
Group and Idaho Power to investigate the implementation of a cost-effective, compact
fluorescent light bulb (CFL) program that utilizes coupons toward their purchase or direct
ORDER NO. 29026
distribution by the Company. Although the Commission previously ordered the Advisory Group
to consider a Time-of-Use metering pilot program, we did not see it mentioned in the May 2
2002 report filed by Idaho Power. Order No. 28894 at 7. Consequently, we also direct the
Advisory Group and the Company to evaluate and report to the Commission on the viability of a
Time-of-Use residential metering program by September 12, 2002 (date certain).
Although we appreciate the initiative shown by the ICIP's request to allow the
industrial class to self-direct its DSM funds, the Commission finds it more appropriate to retain
oversight of the expenditure of funds collected by this tariff rider. We encourage representatives
of the industrial class to participate in the Energy Efficiency Advisory Group to ensure that DSM
dollars collected by this tariff rider will also benefit their class.
VI. RATE DESIGN
Rates are normally adjusted each May once the Commission determines the
appropriate revenue increase or decrease under the Company s PCA. As previously mentioned
absent a Bond issuance, the Company s PCA filing sought to recover approximately $223.
million through the imposition of a 2.2885~ per kilowatt-hour (kWh) PCA rate applicable to all
customer classes for the period May 16, 2002 through September 30, 2002, and a PCA rate of
1.9059~ per kWh for the period October 1 2002 through May 15 2003. The Company requests
that the new PCA rates become effective on May 16, 2002.
A. Non-Residential Rates
Last year in May and again in October, the Commission ordered a uniform cents per
kWh charge on all non-residential customers. The May increase was effective over a 12 and
one-half month period. 14 The additional increase in October was effective over a twelve-month
period. Both Staff and the Company advocated that same rate design be implemented in this
proceeding.
Commission Findinf!s.We agree with the Company and Staff that the rate increases
for non-residential customers should be implemented as a cents per kWh charge on all customers
over a twelve month period. This rate design produces three PCA rates for the coming year.
Irrigators shall pay 1.3415~ per kWh, the May 1 , 2001 PCA rate, for the coming year and carry
14 Although the PCA is generally recovered over 12 months, last year the Commission ordered an additional half-
month of recovery to accommodate a May 1 (rather than a May 16) effective date. Order No. 28722 at 27.
ORDER NO. 29026
approximately $11.0 million15 over for recovery in the 2003 PCA year. Small General Service
customers shall pay 1.7241~ per kWh, the October 1 , 2001 PCA rate, and carry over
approximately $600 00016 for recovery in the 2003 PCA year. All other non-residential
customer classes will pay a PCA rate of 1.9370~ per kWh for the coming year with no carry-over
into the 2003 PCA year. Appendix 2 shows all of Idaho Power s affected schedules and the
associated average rates and increases. The table below is a simplified version of Appendix 2.
CUSTOMER EXISTING APPROVED PERCENT AGE
GROUP SCHEDULE SURCHARGE SURCHARGE INCREASE
Irrigation 5.1~ per kWh 1~ per kWh
Small General Service 0~ per kWh 0~ per kWh
Large General Service 3~ per kWh 5~ per kWh
Large Power Service 5~ per kWh 7~ per kWh
Imposing a cents per kWh surcharge is reasonable and consistent with past PCA surcharges. We
next turn to the rates for residential customers.
B. Residential Rates
Except for the residential customers in 2001-2002, PCA costs have historically been
recovered on a uniform cents per kWh basis. Last year the Commission ordered residential PCA
recovery to take place through a three-tiered inverted block rate structure. Order No. 28722 at
24.
1. Idaho Power. The utility recommended that the current residential three-tiered
rate structure be eliminated in favor of a flat rate for all kilowatt-hours of energy consumption.
Tr. at 301. The Company makes purchases to meet the system s load requirements rather than
meet the load requirements of specific customer groups. Id. Consequently, Idaho Power argued
that it is impossible to identify costs as being caused by certain customers. Id. In order for the
PCA component of customers ' rates to be reflective ofthe cost ofthe energy commodity, and the
nature in which the commodity is purchased, Idaho Power asserted the PCA should be uniform
for all customers and all customer classes. Tr. at 302. To the extent that the energy charge is
designed to recover only energy related costs, the Company argued that no cost basis exists for
establishing variable energy prices based solely on quantity of consumption within customer
classes. Tr. at 303.
15 $10 953 165.16 $577 033.
ORDER NO. 29026
Idaho Power also recommended a flat PCA charge for residential customers for
several other reasons. First, the Company argued that the current three-tiered rate structure
unfairly penalizes customers who utilize electric energy for space heating and air condition and
provides an incorrect price signal for customers who use less than 800 kilowatt-hours per billing
cycle. Tr. at 304. Second, the three-tiered rate structure exacerbates the existing residential
intra-class subsidy for recovery of fixed costs. Id. Third, the three-tiered rate structure results in
the customer perception that meter reading intervals greater than 30 days are unfair. Tr. at 304-
05.
2. Commission Staff.Although the Company proposed that all rates (including
residential) be uniformly increased, the Commission Staff recommended that the Commission
continue an inverted three-block rate design for residential customers. However, Staff proposed
that the tiered rates be modified to recognize abatement of the energy crisis and improved water
conditions yet still preserve the conservation price signal. Tr. at 532. To reduce the cost burden
on high energy users, Staff advocated reducing the rate difference between the first and third
block from 2.2 cents per kWh to approximately 1 cent per kWh. Tr. at 534.
3. Conservation Groups. The Conservation Groups also supported continuation of a
block rate design for residential customers. According to their written comments, tiered rates
send an appropriate price signal and encourage customers to conserve and improve efficiency.
Moreover, they supported the Commission s efforts in recent DSM-related orders to target those
customers utilizing electric space heat for increased DSM program attention.
4. Public Comments. The Commission also received a tremendous public response
on the issue of residential tiered rates. Of the 274 written comments received by the
Commission, 132 opposed tiered rates while only 9 supported their continued use. More than
100 commentors specifically mentioned that they lived in all-electric homes. Of the 30
witnesses who testified at the public hearings about high-energy bills, 2 favored the tiered-rate
structure while 16 opposed it. The two individuals who supported tiered rates generally did so
because the rates brought attention to the need to conserve and prompted people to reduce their
energy consumption. Those commentors who submitted written comments or testified at the
public hearings generally opposed tiered rates because the rates "discriminated" against high
energy users
, "
penalized" residents of the all-electric Gold Medallion homes once promoted by
ORDER NO. 29026
Idaho Power, and left customers unable to reduce the consumption enough to see a significant
difference in their bills.
Commission Findinf!s Based upon the record, we find it is appropriate and
reasonable to return to a uniform rate design for residential customers. We base this decision on
several reasons, despite losing the conservation price signal sent by tiered rates. As discussed in
the "Recovery of Deferred PCA Amounts" section above, the Commission finds a multiple-year
deferral of large PCA amounts is not in the public interest given the uncertainty currently present
in our water and wholesale market conditions.
Tiered rates created unanticipated problems when Idaho Power s meter reading cycle
extended beyond 30 days. To the extent that the kWh consumed between day 30 and day 33
pushed customers into a higher rate block, customers paid a higher rate than they otherwise
would have if the meter had been read on day 30. The Commission directs Idaho Power to
continue its efforts to establish meter reading schedules that maximize efficiency and minimize
ratepayer costs while reading meters as close to every 30 days as possible. If problems persist
after the flat rate is implemented, the Commission intends to address this issue in a separate
proceeding.
The Commission is also concerned about the public s perception of tiered rates.
Many customers attributed their high energy bills to the tiered rate structure rather than to the
implementation of a 31 % residential increase over the previous winter s rate. Consumers using
2008 kWh of electricity experienced no difference in their bills under tiered rates than they
would have under a flat rate surcharge. Those using less than that amount experienced increases
less than a flat surcharge under the tiered rates because their bills were primarily comprised of
the 0-800 kWh rate designed to allocate a portion of less expensive electricity to each customer
for the purpose of maintaining essential service for customer health and safety.
Although many high energy users assumed they paid the highest rate on all of their
consumption, they actually benefited from the lowest rate for the first 800 kWh they consumed
as well. Only 4% of Idaho Power s ratepayers used more than 3000 kWh per month. Many
testified that energy used for barns, stock water heaters and other non-residential users were part
of their residential bills. These non-residential users should not be metered through a residential
meter. Outbuildings, farm uses and other non-residential energy consumption belong on a
general service schedule separately metered. A customer using 3000 kWh per month would
ORDER NO. 29026
receive a $219.36 bill - which is only $11.25 more than what they would have paid with a flat
rate surcharge. From the public comments we received, it was apparent many ratepayers did not
understand the purpose or actual dollar effect of tiered rates.
For these reasons, the Commission finds it reasonable to implement a uniform
1.9370~ per kWh charge on all residential customers over a 12-month period. The table below
shows average increases and decreases associated with the residential rate changes.
TIERED RATE EXISTING APPROVED PERCENTAGE
GROUPS AVERA GE RATE AVERA GE RATE INCREASE
800 kWh 6.2~ per kWh 1~ per kWh 15%
801-2000 kWh 0~ per kWh 1~ per kWh
over 2000 kWh 8.4~ per kWh 7.1~ per kWh 15%
Although it is appropriate to use flat residential rates this year, this Order should not
be interpreted as precluding the use of tiered rates in the future. We believe that last year s tiered
rates were effective in sending a price signal to customers to conserve. However, many of these
customers experiencing an increase of 31 % or more had limited ability to significantly alter their
energy consumption once they received the price signal. It is our belief that with additional
customer education and increased availability of residential DSM programs like Time-of-Use
metering, tiered residential rates may be an appropriate rate design option in the future as
circumstances dictate.
Although our return to a flat residential rate will alleviate the hardship posed to the
small percentage of extremely high energy users, it will increase the burden on low energy users
by eliminating the less costly block available with the tiered rate to promote customer health and
safety. Low-income customers may also be eligible to receive financial assistance from energy
programs like LIHEAP, Project Share, and Project Warmth. The Commission Staff or the
community action agencies can provide additional information on these programs. While we
recognize that some customers may not be able to conserve or reduce their consumption, there
are programs for eligible residential customers to possibly convert to more efficient space
heating appliances or receive assistance for high heating bills. For example, customers may also
enroll in levelized pay programs that are intended to reduce or "levelize bills for high
consumption months with bills for low consumption months. Regardless of whether a CFL
ORDER NO. 29026
coupon program is initiated, customers who replace several incandescent light bulbs with CFLs
may partially offset this increase and in some cases lower their bills.
Customers interested in conserving energy may also view the US. Department of
Energy s web site located at www.eren.doe.govibuildings/documents/high heating bills.The
Idaho Office of Energy also dispenses low interest energy conservation loans. Interested persons
can access applications and additional
www.idwr.state.id.us/SaveEnergy/Residential.htm
information their web site at:
Finally,the Commission winter
moratorium rule prohibits any electric or gas utility from terminating or threatening to terminate
service during the months of December through February 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 infirmed persons. IDAP A 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.
In summary, the Commission is authorizing Idaho Power to recover approximately
$255.9 million in PCA rates and $2.6 million in DSM rates. The Commission is ordering
implementation of the PCA and DSM rate changes effective on May 16, 2002. We believe that
allowing the Company to recover the majority of the customers' share of its above normal power
costs in a timely fashion ensures the Company of continued financial viability and ensures that
ratepayers will not mortgage their future opportunity for lower electric rates.
ORDER
IT IS HEREBY ORDERED that Idaho Power Company s Bond Application in Case
No. IPC-02-2 is denied.
IT IS FURTHER ORDERED that Idaho Power Company s PCA Application in Case
No. IPC-02-3 is partially granted. The Company is authorized to implement the rates
identified in this Order, which will generate approximately $244.4 million in 2002 PCA
revenues.
IT IS FURTHER ORDERED that recovery of approximately $11.5 million will be
deferred for recovery in the 2003-2004 PCA year. Of this amount, approximately $11.0 million
is attributable to the Irrigation Class and approximately $600 000 is attributable to the Small
General Service Class. The carrying charge for amounts deferred beyond the traditional PCA
ORDER NO. 29026
recovery period shall be 6% per year simple interest. Amounts are carried over in the Small
General Service and Irrigation classes.
IT IS FURTHER ORDERED that a separate tariff rider in the amount of .5% of each
customer class s base revenues be collected as described above for the purposes of funding
Demand-Side Management programs throughout the Idaho Power service territory. This tariff
rider shall appear as a line item on customers' bills and labeled so as to indicate that the amount
will fund conservation programs.
IT IS FURTHER ORDERED that Idaho Power shall file an annual written report to
the Commission no later than January 30 of each year detailing: the Advisory Group
recommendations, the Company s response to those recommendations, the associated program
costs, the DSM accounting numbers, customer response data, and information on new DSM
opportunities.
IT IS FURTHER ORDERED that Idaho Power consult the Energy Efficiency
Advisory Group regarding the need to initiate a comprehensive DSM study of the IPC service
territory relative to the priority for DSM funds to identify: (1) cost-effective DSM opportunities
in each customer class; (2) estimated costs to fully fund those opportunities; and (3)
opportunities for reductions in peak loads as well as reductions in total energy consumption.
IT IS FURTHER ORDERED that the Company file tariffs in conformance with the
rates described above in this Order.
IT IS FURTHER ORDERED that the PCA and DSM rider rates established in this
Order are effective May 16 2002.
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-02-2 and IPC-02-
3 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-02-2 and IPC-02-3. For purposes of filing a petition for
reconsideration, this order shall become effective as of the service date. Idaho Code ~ 61-626.
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. 29026
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this 131*'
day of May 2002.
64 1f
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~l
Commission Secretary
O:IPCE0202 03 1n2 final
- - -
ORDER NO. 29026
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