28722.pdf

Office of the Secretary
Service Date
May 1 2001
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THEMA TTER OF THE IDAHO POWER
COMPANY APPLICATION FORA CASE NO. IPC-01-
REFUNDABLE EMERGENCY ENERGY
CHARGE FOR THE RECOVERY OF
EXTRAORDINARY POWER SUPPLY
EXPENSES.
IN THE MATTER OF THE IDAHO POWER
COMP ANY APPLICATION FOR AUTHORITY CASE NO. IPC-Ol-
TO IMPLEMENT A POWER COST
ADJUSTMENT (PCA) RATE FOR ELECTRIC NOTICE OF PREHEARING
SERVICE FROM MAY 1, 2001 THROUGH MAY CONFERENCE
15, 2002.
ORDER NO. 28722
SUMMARY OF COMMISSION ORDER
In February and March 2001 , Idaho Power Company filed two Applications seeking
to increase its rates under the annual Power Cost Adjustment (PCA) mechanism first approved
by the Commission in 1993.Idaho Power supplies electricity to approximately 360 000
customers across southern Idaho. In its February Application, the Company sought to recover
$161 million that represented the amount of off-system power purchases over the preceding 10
months. In March 2001 , the Company filed its second Application requesting authority to
recover approximately $66.4 million in revenues. Thus, the Company requested recovery of a
total of $227.4 million by imposing a uniform 1.8889~ per kilowatt hour charge for all its
customers over a one year period. The proposed rate change reflected an average 45.6% increase
above current rates.
In this Order, the Commission finds that Idaho Power should be allowed to
immediately recover approximately $168.million through the PCA mechanism. This
represents 74% of the Company s request and is $159.6 million above current rates. The
Commission has deferred recovery of approximately $59 million pending further investigation of
several issues. Furthermore, the Commission determined that it is appropriate to initiate an
investigation regarding several of the trading practices used to purchase power for the regulated
company; whether the purchasing entity failed to execute a timely purchase of power when
ORDER NO. 28722
requested to do so; whether the Company appropriately hedged against market volatility;
whether the pricing mechanism used to purchase power should be amended on a prospective
basis; and whether the Company s resource plans are adequate to prospectively address current
drought and market conditions. The Commission intends to proceed expeditiously in its review
of the deferred issues.
After reviewing the record in this matter, the Commission has determined that the
rates for the non-residential customer classes should be uniformly increased by 1.3415~ per kWh
over base rates. The percentage increase for each customer class over current rates is: irrigation
- 31.3%; small commercial - 18.8%; large commercial - 32.9%; and industrial - 42.1 %. The
Commission has determined that the approved rates for residential customers should be spread
over three blocks that increase as a customer s electric consumption increases. The overall
average rate increase for residential customers is 23%. This translates into residential increases
of 14.4% for the first block (monthly usage of up to 800 kWs), 28.8% for the second block
(monthly usage between 801 and 2000 kWs), and 62% for the third block (monthly usage over
2001 kWs). The average residential customer using 1200 kWh per month would experience a
monthly increase from $62.72 to $74.29, or an increase of 18.4%. This rate design is specifically
intended to provide rate incentives for customers to conserve electricity.
Finally, in response to comments filed by the parties and members of the public, the
Commission has directed Idaho Power to submit additional energy conservation proposals
designed to provide customers with the opportunity to reduce electric consumption.
ORDER NO. 28722
TABLE OF CONTENTS
SUMMARY OF COMMISSION ORDER
I. BACKGROUND
A. History of PCAB. The Two ApplicationsC. ProceedingsD. Parties
II. THE WATER FORECAST COMPONENT
III. THE POWER SUPPLY COSTS COMPONENT
1. Adjustments
2. Consumption
A. Trading Practices
1. Background
a. The IES Agreement
b. The IPC-OO-13 Case
2. Lack of Authority
3. Hedging
4. Transaction Pricing
a. Mid-C Price Index
b. Weighted Average
5. Transmission Pricing
B. The Disputed November Transaction
C. Resource Planning
IV. NOTICE OF PREHEARING CONFERENCE
V. CONSERVATION
VI. RATE DESIGN
A. Non-Residential Rates
B. Residential Rates
C. Amortization of Rates
D. Effective Date
ORDER
ORDER NO. 28722 1l1
Office of the Secretary
Service Date
May 1 2001
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE IDAHO POWER
COMPANY APPLICATION FOR CASE NO. IPC-01-
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 NOTICE OF PREHEARING
SERVICE FROM MAY 1 , 2001 THROUGH MAY CONFERENCE
15, 2002.
ORDER NO. 28722
I. BACKGROUND
A. 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 dramatically from year to year depending upon changes in streamflow and
market prices. When streamflows or snowpacks are low, Idaho Power must rely increasingly
upon off system purchases and its other generating resources and/or market purchases that are
more costly than 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 costsl for the preceding 12 months including off-system
purchases used to serve Idaho system load? Second, rates are adjusted on an annual basis to
1 The term "power supply costs" means additional purchases and fuel costs plus decreased surplus sales revenue.
2 The term "Idaho system load" means that amount of electricity necessary to serve Idaho ratepayers. For the
purpose of this Order, it is synonymous with "system operations" as discussed in the section on trading practices.
ORDER NO. 28722
compensate for the 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 receives revenues 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 receive a
surcharge when power costs are high.3 During the seven years that the PCA has been in effect
there have been three annual credits and four annual surcharges. This PCA case is the largest
amount ever requested - nearly 6 times larger than the next largest increase.
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 ofthe following year. Procedurally, PCA
cases are normally processed on an expedited basis through the submission of written comments.
IDAP A 31.01.01.122.02.
B. The Two Applications
On February 23 2001 , Idaho Power Company filed an Application in Case No. IPC-
01-7 for authority to implement a flat "emergency energy charge" of 1.2737~ per kilowatt-
hour (kWh) applicable to all customer classes for a 12-month period. The Company sought to
recover an unprecedented $161 million in additional power supply costs incurred over the prior
10 months.
On March 20, 2001 , Idaho Power Company filed an additional Application in Case
No. IPC-01-11 for authority to increase the PCA rate schedule from the existing 0.1371~ per
kWh rate to 0.6152~ per kWh. The proposed rate increase in this second case is primarily based
upon forecasted below-average water flows in Idaho s hydroelectric system for the coming year.
If approved, this Application alone would result in an overall revenue increase of approximately
$66.4 million.
If approved, these two Applications (hereinafter referred to as the "combined PCA
filing ) would recover approximately $227.4 million through a flat 1.8889~ per kWh charge
3 The Company may recover 90% of the difference between the projected power cost and the Commission
approved base power cost. Order No. 25880.
4 The next largest increase was $38 million.
5 Typically this forecast is based upon an April 1 projection of April through July runoff at Brownlee Reservoir.
Because the Commission requested that Idaho Power file its PCA case early, the Company substituted a March I
projection of the April through July Brownlee runoff.
ORDER NO. 28722
imposed on the Company s customers for one year. Because not all customers pay the same per-
kilowatt-hour charge, the proposed 1.8889~ per kWh charge represents a different percentage
increase for each customer class. Idaho Power s proposed approximate rate increases for major
customer groups are set out below:
TODA Y'PROPOSED PERCENTAGE
CUSTOMER GROUP AVERAGE RATE AVERAGE RATE INCREASE
Residential 5.2 cents per kWh 1 cents per kWh 34.4%
Irrigation 9 cents per kWh 8 cents per kWh 46.
Small Commercial 6.4 cents per kWh 3 cents per kWh 27.
Large Commercial 7 cents per kWh 5 cents per kWh 49.
Industrial 9 cents per kWh 7 cents per kWh 62.
Source: Order No. 28685 at 3.
The combined proposed rate change reflects an average 45.6% increase to current
Idaho Power rates. More specifically, the Company s bill stuffer notifies customers that a typical
monthly residential bill for 1200 kWh will increase from $62.72 to $84.34 if the proposed
8889~ rate increase were approved.
C. Proceedings
Although the Company requested in its IPC- E-O 1- 7 filing that the emergency energy
charge become effective on March 26, 2001 , the Commission suspended the effective date until
May 1 2001. Order No. 28665. The suspension allowed the Commission time to examine the
prudency of the Company s power purchases, review the Company s promotion of its
conservation policies, and conduct public workshops and hearings. When it later filed its PCA
Application in IPC- E-07 -, the Company requested an effective date of May 1 , 2001 to enable
both Applications to be decided in this joint Order. Because the Commission normally considers
both PCA elements together, the Commission issued Order No. 28665 to combine the proposed
emergency energy charge (IPC- E-O 1- 7) and the PCA (IPC- E-O 1-11) into a single proceeding.
This has facilitated comprehensive consideration of all components of the PCA.
To gather public input on the combined PCA filing, the Commission held workshops
and public hearings in American Falls, Pocatello, Twin Falls, Caldwell and Boise.
Approximately 105 people attended the five workshops and 118 people observed the four
hearings.6 Of those who attended, 41 people testified at the hearings.
6 Although no public hearing was held in American Falls, those who attended the American Falls workshop could
testify the following evening at the Pocatello hearing.
ORDER NO. 28722
In Order Nos. 28665 and 28685, the Commission solicited written comments to be
filed on or before April 16, 2001. As of that date the Commission received 314 individual
written comments from the public and 23 petitions containing a total of 406 signatures. All but
10 of the public comments received objected to the proposed PCA increase.
D. Parties
The following persons were made parties to the combined PCA filing.
Idaho Power Company Larry D. Ripley
Commission Staff Lisa Nordstrom
Deputy Attorney General
Astaris LLC Conley Ward
Givens Pursley LLP
Ken Tandy
Astaris LLC
Irrigation Pumpers Association, Inc.Randall C. Budge
Racine Olson Nye Budge & Bailey, Chartered
Anthony Yankel
u.S. Department of Energy Lawrence A. Gollomp
Assistant General Counsel
Land & Water Fund of the Rockies
Mary McGown
William M. Eddie
Idaho Rivers United Sara C. Denniston
Idaho Rural Council Kristy Webb
Industrial Customers of Idaho Power Peter J. Richardson
Molly O'leary
Richardson & 0' leary
Stuart Trippel
Trippel Mast Consulting
Each party filed written comments except Astaris, which provided oral testimony at
the Pocatello hearing. Staff and the Company participated in all of the public hearings. Idaho
ORDER NO. 28722
Power Company filed its response to these comments on April 21 , 2001. With this background
we turn to the issues.
II. THE WATER FORECAST COMPONENT
As explained above, the forecasted water conditions for the next 12 months are the
second component of the PCA. In their comments, the Company and the Staff agreed that
expected power supply costs totaled $132 938 867, based on forecasted April through July 2001
Brownlee inflows. After computing the above-normal power supply costs, the Company
determined that the PCA rate should recover $41.7 million when adjusted for Idaho
jurisdictional share of the increase and the 90/10 sharing between ratepayers and shareholders.
The Staff calculated the power supply costs attributable to low streamflow as $45.8 million but
its calculation was based upon a different amount of assumed kWh expected to be sold by Idaho
Power.However, the Staff and the Company agreed that a rate of .3861~ per kWh was
necessary to recover anticipated power supply costs.
Although the Company sought to impose the .3861~ per kWh as part ofthe PCA rate
Staff recommended this forecasted amount be deferred until next year s PCA. Staff asserts the
forecast amount severely underestimates expected power supply costs in light of low reservoir
water and high market prices. In its response, the Company does not believe deferring this
amount until next year s PCA is in the public interest. Response at 5. The Company maintained
that deferring the water forecast amount from this year s PCA
will only exacerbate the Company s true-up for next year and will provide
no cash to pay for the increased power supply costs we all know are
coming. Additionally, those who set the Company s credit ratings and
those who provide it with much needed capital in these difficult times are
also watching this decision very closely. Failure to include the (water)
forecast in the PCA adjustment will likely be viewed as failure of the
mechanism to assure recovery of costs resulting in credit downgrades and
restricted access to capital in the marketplace when it is needed most.
Id.
Commission Findinf!s Based upon our review of the record, the Commission finds
that the PCA rate attributable to predicted streamflows is .3861~ per kWh. See Appendix 1 to
this Order.
ORDER NO. 28722
Although the Commission understands that Staff s purpose in recommending
deferred recovery of this PCA component is to mitigate the anticipated large rate increase this
year, deferring this amount would only increase next year s PCA rate. Staffs reasoning that the
low water projection will underestimate actual power supply costs is in itself justification for
allowing recovery in this PCA case. The Commission is hopeful that regional power market
prices will decline and that Idaho will soon experience an above-average water year. Even if
these favorable conditions come to pass, the Commission is concerned that next year s PCA
request may be sizable to recover excess power purchase costs incurred during the coming year
and to fund conservation or demand-side management programs like the Irrigation Buy-Back
Program.
The Commission finds it reasonable and in the public interest to allow recovery of the
forecasted power supply costs in the current 2000-2001 PCA. The PCA was designed to allow
consistent recovery of anticipated power supply costs. The Commission chooses not to deviate
from the established formula in this case. Given the volatility and high wholesale prices in
regional power markets, the Commission finds immediate recovery of the forecast amount is
reasonable. This recovery also assures the financial community that the Company will be
allowed to recover its reasonably incurred power supply costs. Moreover, immediate recovery of
this forecasted amount will minimize the interest costs that would otherwise be included in next
year s PCA.
III. THE POWER SUPPLY COSTS COMPONENT
Of the total $227.4 million PCA revenue requested by the Company, approximately
$186 million is attributable to last year s umecovered power supply costs. Idaho Power applied
for $161 million in its emergency energy charge filing in IPC- E-O 1- 7 for 90% of above
forecasted power supply costs from April 2000 through January 2001.7 In its PCA filing in IPC-
O 1-, the Company requested an additional $25 million to recover the customer s share of
forecasted power supply costs for February 2001. To facilitate the early PCA filing requested
by the Commission, recovery of the customers' portion ofthe March 2001 above forecast power
supply costs will be deferred to the 2001-2002 PCA case.
7 See infra note 3.
ORDER NO. 28722
Staff recommended recovery of$126.212 million of the $186 million in power supply
costs. Staff indicated that these costs were reasonably and prudently incurred to serve the
Company s Idaho customers. Staff also recommended that $8 million be recorded below-the-
line, thus denied recoverr, and that recovery of the remaining $51 million be deferred pending
further investigation. See Trading Practices and Disputed November Transaction Sections
below. Other parties also recommended that portions of the PCA be denied for various reasons.
The Rural Council suggested that one-third of the total PCA request be denied. Rural Council
Comments at 3. The Industrial Customers of Idaho Power (ICIP) and others argue that some of
the power purchases may have been imprudent and any rate increase should be subject to refund.
ICIP Comments at 20. Parties also urged the Commission to initiate a general rate case or
initiate an investigation into issues in this case. Id. at 5-, 18-19; Irrigation Pumpers Comments
at 2; Land and Water Fund and Idaho Rivers United Comments at 3; DOE Comments at 3.
Commission Findinf!s The Commission finds that $126.212 million excess power
supply costs should be recovered immediately in this PCA. Although some parties offered
general objections or concerns about the purchase power component, the Commission is
persuaded by the Staff comments. As discussed below in greater detail, the Commission shall
defer recovery of some power supply costs and open an investigation to examine some of the
issues raised by the parties. However, it is evident that the Company did purchase power to meet
its obligation to serve Idaho ratepayers.
1. Adjustments.Staff concurred with two adjustments made by the Company in its
true-up" calculation. First, the Company adjusted the load change expense for February 2001 to
account for differences in "actual firm load" reported in previous months. Second, the Company
adjusted the interest calculation on the deferred balance of August, October and February to
reflect differences in market purchases, sales, and load change expenses reported in previous
months.
The Company used a 5% interest rate for April through December 2000 and a 6%
interest rate for January and February 2001 in its calculation. To be consistent with past PCA
calculations, Staff recommended that the 5% interest rate be used for the entire PCA period.
Staff Comments at 5. By previous agreement between the Company and Staff, a single
Commission-approved interest rate (i., the rate paid on customer deposits effective at the
ORDER NO. 28722
beginning of the PCA year) has previously been used for all months in the PCA year.8 IDAPA
31.21.01.106.
Commission Findinf!s The Commission finds that the adjustments agreed to by the
Company and the Staff are reasonable and should be adopted. To maintain consistency with
prior PCA cases, the Commission further finds it appropriate to apply the 5% interest rate on
deposits to the deferred balances for the entire PCA period of April 2000 through March 2001.
2. Consumption Data. Staff pointed out in its comments that the Company used
different annual energy consumption totals to calculate the PCA rates proposed in its two
separate filings. In the emergency surcharge case (IPC-01-7), the Company used normalized
1999 Idaho jurisdictional firm load of 12 632 017 MWh.9 In its second filing (IPC-01-11), the
Company used 10 802 636 MWh - the normalized Idaho jurisdictional firm load that was used in
the Company s last general rate case. Staff recommended that the Commission use the 1999
Idaho jurisdictional load of 12 770 405 MWh.lO Staff Comments at 39.
Commission Findinf!s The Commission finds it appropriate to adopt the Staff and
Company proposal to use normalized 1999 kWh for 12 and one-half months (13 253 976 M\Vh)
to calculate this year s true-up PCA rate. If the Company sells this amount of electricity, as it
expects to, the Company will recover all of its true-up costs. See Appendix 2.
A. Trading Practices
Background The Commission received many comments regarding the
relationship and the transactions that have occurred between the regulated entity (Idaho Power
Company) and another subsidiary called IDACORP Energy Solutions (IES). Idaho Power and
IES are both wholly-owned subsidiaries of IDACORP, Inc. IDACORP desired that IES engage
in the marketing of electricity and natural gas on the wholesale level. In other words, IES will
trade" (actually purchasing and selling) natural gas and electricity as commodities.
8 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.
9 The Company has subsequently indicated that the correct normalized 1999 Idaho jurisdictional fIrm load is
770 405 MWh.
10 The Company s response proposed to add 483 571 MWh to the 12 770 405 MWh load amount, for a total of
253 976. This additional amount is the one-half of May s kWh that must be recovered to effectuate a May 1
2001 effective date.
ORDER NO. 28722
a. The IES Agreement. On September 1 , 2000, Idaho Power filed an Application
requesting that the Commission approve a proposed Electric Supply and Management Services
Agreement (Agreement) between Idaho Power and IES. This Agreement was reached after
approximately two years of negotiation, after which Staff recommended approval of the
Agreement. Under the Agreement, Idaho Power sought authority to transfer its operating
transactions (e., purchasing and selling power for itself to meet the utility's Idaho system load)
to IES. Agreement ~ 1 , Atch. 1 ~ 3.1. Such transactions or trades for Idaho Power are referred to
as "operating or system transactions." IES would also engage in transactions in the wholesale
power market that do not involve sales from Idaho Power resources and are not related to the
Idaho Power system. For example, IES would purchase gas and electricity from third parties and
resell these commodities to parties other than Idaho Power.
referred to as "non-operating or non-system transactions.
Such electric transactions are
The Attachment to the Agreement noted that the "sales price for delivered energy and
capacity acquired by Idaho Power from IES to supply Native Load will be equal to the Market
Price determined in accordance with Section 5." Agreement, Atch. 1 , ~ 3., the market price for
purchasing power to meet Idaho Power s obligation to serve its Idaho system load was based on
the Dow Jones Mid-Columbia Electricity Price Index (Mid-C). Id. at ~ 5.
In addition to the pricing mechanism, Idaho Power would compensate IES for its
services in the amount of $300 696.30 per month. Id.~ 6.1. In addition to purchasing and
trading for Idaho Power, IES proposed to provide other management services such as executing
hedges" intended to "minimize the risk of financial loss from an adverse price change in a
commodity market." Atch. 1 , ~ 2.1.3.Other services include real-time power marketing,
intramonth power marketing (trades that supply power from one day to one month), and risk
management activities intended to reduce risk of losses "that would cause Idaho Power to incur
higher costs for supplying Native Load.Id.~ 2.1 through 2.
b. The IPC-00-13 Case.In Order No. 28596 issued December 19, 2000, the
Commission approved the Agreement between IES and Idaho Power. 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 ~ 6. The Agreement provides that it "shall not become
effective until the commissions have issued their respective final orders approving the
ORDER NO. 28722
Agreement or any future amendments.Id. at ~ 9. With this background, we now turn to the
particular concerns raised by the Staff comments in this case.
The Staff expressed several concerns regarding the trading practices and transactions.
In addition, other parties questioned the prudency or practices of the Company s power
purchases. These are discussed in further detail below.
2. Lack of Authority.As a threshold matter, the Staff asserted that the IES
Agreement (including the Mid-C Pricing Index contained in the Agreement) is not in force
because the Agreement had not been approved by the FERC or the Oregon Public Utility
Commission. Consequently, Staff argued the market functions continue to be under Idaho Power
and the Mid-C pricing structures should not be solely utilized. Staff Comments at 22-23. In
Staffs view, Idaho Power should still be performing these trading transactions on its own behalf.
If Idaho Power is still responsible for power purchases, it appears inappropriate and umeasonable
to charge ratepayers $51 million more than the cost ofthe purchased power.
3. Hedging. Staff also expressed concern with the Company s apparent failure to
properly use hedging instruments. Staff maintained that the Company has substantially limited
long-term purchase contracts in favor of more expensive day-ahead market purchases. The Staff
argued that the ability "to purchase power at a fixed price is a valuable tool for rate stability.
According to Staff, the Company should have been aware of generating shortfalls and that its
system would need to rely more heavily on expensive day-ahead markets. Staff Comments at
22.
After reviewing the Company s recent power purchases, the Staff determined that the
Company only executed one power purchase contract in the month of February 2001 that was
over a month in duration.Staff argued this apparent failure to properly hedge subjected
ratepayers to greater market volatility and risk. Id. By comparison, Staff found during the
months of June 2000 through August 2000 30.5% of the Company s non-system purchases were
term purchases of one month or more and an additional 60.2% were from the day-ahead market.
In January and February 2001 , 15.2% of the Company s non-system purchases were long-term
and 70.3% were day-ahead transactions. This increased reliance on more expensive day-ahead
markets is one factor that Staff believes has contributed to the overall increase in costs to
ratepayers. Id.
ORDER NO. 28722
4. Transaction Pricing
a. Mid-C Price Index. Staff recommended that a portion of the purchased power
component of the PCA be deferred until the Commission re-examines the use of the Mid-
Pricing Index.ll Staff Comments at 20-, 29. Staff analyzed all transactions for the three
months from December 2000 through February 2001 , comparing purchases for the Company
operating system and non-operating system. The analysis showed that in 155 out of 161
transactions (more than 96%), the regulated entity paid more for power than was paid by the
non-regulated entity. Id. at 23; Atch. Nos. 7-10. The Staff argued that the Mid-C pricing
mechanism adopted in the Idaho Power-IES Agreement no longer represents a reasonable
surrogate price for system power transactions. "(T)he Mid-C pricing does not produce rates that
are fair, just and reasonable.Id. at 23.
To correct this pricing inaccuracy, Staff recommended that purchases by IES for
Idaho Power be priced at the "lower of cost or market." Under a typical "lower of cost or
market" approach for prudent and reasonable expenses, system units owned by the Company
would normally be operated and dispatched if the cost of running these units was below
alternatives available from the market. If market alternatives were less expensive, purchases
would be made to take advantage of these lower costs for customers. Staff Atch. 19 at 4. The
Staff argued that for purposes of determining the "market price " the Commission could use the
Mid-C price or another acceptable pricing mechanism. Staff recommended that the cost be
based on the daily weighted average of the price actually paid for the power by the non-operating
book to third parties. Id. at 28.
In its reply comments, Idaho Power argued that the Mid-C Index continues to
represent a relevant market price to use for affiliate transactions because it is the closest trading
hub and is a liquid, objective pricing point. The Company maintained that it should be entitled
to rely upon the Commission s previous orders and should be authorized to collect the
$51 234 902 amount the Staff would "re-price" under a yet undefined methodology. Response at
8. The Company asserted that Order No. 28596 explicitly approved the Mid-C pricing
mechanism contained in the Agreement. Id. at 9. Consequently, the Company claimed that it
has followed both the letter and the spirit of (the Order) in all of its actions.Id.
11 The Staff recommended both an adjustment be made below the line and that the Commission investigate this issue
in a "second phase or a separate case." Staff Comments at 29.
ORDER NO. 28722
The Company stated there are additional advantages to the use of the Mid-C Index.
Utilizing the Mid-C Index eliminates the ability of Company personnel to manipulate the price
and they have no ability to pick and choose which transactions to classify as operating or non-
operating. Id. at 11. The Company insisted that changing "the affiliate pricing procedures
without prior Commission review is equally inappropriate and would result in retroactive
ratemaking.Id. The Company also noted that the FERC believes an established relevant
market index adequately mitigates affiliate abuse concerns. "Moreover, this is exactly what
Idaho Power proposed and this Commission approved in Order No. 28596.Id. at 12.
b. Weighted Average.Staff also maintained that in the past real-time power
purchases always flowed through the system at their actual costs. After conducting its review
Staff insisted that the Company is now pricing these transactions on the weighted average price
for all real-time transactions that touch the Idaho Power system on an hourly basis. Staff
Comments at 24. According to Staffs analysis, this results in overcharges and underpayments in
several cases. Adjusting the inter-book real-time sales and purchases for the months of
December 2000 through February 2001 , Staff calculated that an adjustment of $4.6 million is
necessary.12
Id. The Staffs calculations are shown in Staff Attachment Nos. 7-10 and
summarized on Staff Attachment No. 13.
The Company in its reply comments objected to the Staffs proposed adjustment. It
argued setting transfer prices at the weighted average of all real-time affiliate transactions would
expose the regulated utility to "risks, volatilities and costs of other markets outside the physical
markets available for actual supply or sale of energy from the Idaho Power system." Reply
14. The Company maintained that using the Staffs suggested methodology, the $24.4 million
ratepayer benefit would in all actuality result in a $21 million detriment. Id. at 15. Furthermore
the Company maintains that any change in this pricing methodology could only be applied
prospectively.
5. Transmission Pricing.Finally, Staff expressed concern that IES is utilizing the
Company s transmission facilities without proper benefit or compensation to the regulated utility
and its customers. Staff Comments at 25. For example, the Staff suspected that IES may be
using "flip" transmission transactions. A "flip" occurs where power is received at one point in
12 The actual amount would be lower when adjusted for jurisdictional and sharing allocations.
ORDER NO. 28722
the Company s transmission system and is delivered at another point. Id. For its part, the
Company maintained that during the current PCA year alone
, "
the non-operating business paid
$55 839 701 in transmission expenses and booked a credit reserve of$21 682 000." Reply at 14.
Commission Findinf!s Based on the above-mentioned comments, the reasonableness
and prudency of several of Idaho Power s trading practices is directly disputed by the Staff, as
well as indirectly by Intervenors. Moreover, we find that there is a legitimate dispute whether
the Idaho Power/IES Agreement was actually in effect during the 2000-2001 PCA year. The
Company s reply comments did not address the approval status of the Idaho Power/IES
Agreement before either the Oregon or Federal Energy Regulatory Commissions.
The Commission also finds that Staff has made a sufficient case for us to examine in
greater detail the hedging practices of the Company. Reducing the use oflong-term contracts, as
we have seen in California, 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.
California Power Exchange Corp. v. FERC - F.3d _2001 WL 366364 (April 1 2001).
Consequently, we find it appropriate and in the public interest to examine the hedging issue more
closely.
The Commission further finds that an investigation of the Mid-C Price Index is
appropriate so that we may determine whether the charges proposed and the Company are
reasonable. The Staff and other parties question the Company s power purchase practices.
Although we recognize that use of the Mid-C Index was contemplated by our Order No. 28596
in Case No. IPC-OO-, Staff has raised the issue of whether the Agreement is in effect without
all the other regulatory approvals. In addition, we find it necessary to review whether the Mid-
Index is an appropriate safeguard to determine the reasonableness of transactions between IES
and Idaho Power.The Commission further finds that it is appropriate to examine Staff s
allegations that IES/ldaho Power changed the manner that it purchased term power and
billed/priced real-time power purchases. The Staff proposed an adjustment, to which the
Company objects. Another disputed issue appears to be whether IES is appropriately'
13 After the record was closed in this case, the Federal Energy Regulatory Commission (FERC) issued an Order on
April 27, 2001 concerning the Idaho Power/IES Service Agreement in Docket No. EROl-1329-000. In its Order
FERC approved the use of the Mid-C Index and the Palo Verde Index for day-ahead transactions. The FERC
requested further filings for real-time transactions.
ORDER NO. 28722
compensating Idaho Power for use of the transmission system.Given these disputes, the
Commission exercises its discretion to also set these matters for hearing.
In summary, the Commission finds that these issues taken collectively raise sufficient
concerns that an evidentiary hearing is required to fully develop the record in this case.
Until the hearing is complete and an order is issued, the Commission finds it
necessary to defer recovery of the $51 234 902 in disputed pricing of power purchases. This
hearing will also satisfy the concerns of the Industrial Customers of Idaho Power and others, who
specifically objected to Modified Procedure and requested that a hearing be scheduled. A
Prehearing Conference to set further proceedings will occur on MAY 10,2001 AT 10 A.M. See
Notice of Prehearing Conference Section below. To complete a review of these issues, the
Commission finds it is appropriate to further suspend portions of the Company s Applications
(IPC-01-7 and IPC-01-11) until such time as the Commission has completed its review of
these issues.
B. The Disputed November Transaction
In its comments, Staff identified one transaction which also deserves further
investigation by the Commission. For purposes of identification, we shall refer to it as the
November Transaction.An explanation and examination of this issue requires some
Idaho Power s parent corporation IDACORP has created a Riskbackground information.
Management Committee which maintains general oversight of energy commodity trading and
assessments of financial risk. Staff Comments at 25. The Committee meets regularly to review
the profit and loss reports, exposure reports, strategies and program objectives. Decisions of the
Committee are made by a simple majority and recorded in the minutes.Id. As described by the
Staff, the Committee normally meets to evaluate whether Idaho Power needs to purchase off-
system generation or whether it has system generation to sell. Once the Committee makes a
decision regarding the purchases or trades, the purchase order is sent to the energy trader at IES
via e-mail and the traders carry out the orders ofthe (Committee) immediately.Id. at 26.
In reviewing the Committee minutes, the Staff focused on a particular Committee
event in November 2000. The Staff alleged that the Committee instructed the energy trader to
buy power that would be necessary to meet Idaho Power s future system needs in January 2001.
Staff claimed that the November buy order of the Committee was not carried out. When a
ORDER NO. 28722
purchase was subsequently made to meet this need, the Staff alleged that the market price of
power had substantially increased.
When the Staff inquired about this issue, the Company replied that the Committee
minutes do not accurately reflect what happened. According to the Staff, the Company stated
that after the Committee discussed making a purchase, it was decided by the Committee that no
purchase would be necessary. However, the minutes do not reflect this subsequent discussion or
action. Consequently, the Staff recommended that the Company s power purchase expense be
reduced by $10 286 154 to reflect the difference between the market price of a timely executed
purchase in November 2000 and the subsequent purchase at a higher price. Id. at 39.
In its response, the Company calculates the Staffs adjustment to be $7 976 701
million.The difference between the Company s calculation and Staff s calculation was
premised upon the Company using Idaho jurisdictional data that would pass through the PCA
whereas the Staff was using multi-state system data. Response at 3-4. Idaho Power responded
that this issue "is more of a dispute over appropriate recordkeeping than an error in trading
activities.Id. at 4. Given the dispute concerning this issue, the Company requested that this
matter be immediately set for hearing to determine the appropriateness of Staffs recommended
denial.
Commission Findinf!s The Commission finds that there are considerable concerns
regarding the November transaction and that they do not necessarily lend themselves to
resolution by the submission of written comments. As is customary of most PCA cases, the Staff
and intervenors generally examine the books and records of the Company to determine the
validity or reliability of entries. In this instance the Staff has challenged the appropriateness of
this action and recommended an adjustment to the PCA request. The Commission believes that
it is necessary to conduct an evidentiary hearing in this matter. There is sufficient cause to
examine this transaction in greater detail. An evidentiary hearing will afford all parties an
opportunity to adequately develop the record so that the Commission can make an informed
judgement. Consequently, the Commission will defer recovery of $7 976 701 million and will
schedule an evidentiary hearing on this issue. See Notice of Prehearing Conference Section
below. To complete our review of this issue, the Commission finds it is appropriate to further
suspend portions of the Company s Applications (IPC-O 1- 7 and IPC- E-O 1-11) until such time
as the Commission has completed its review of this matter.
ORDER NO. 28722
C. Resource Planning
In its comments, Staff concluded that the Company made market purchases this
winter in exact accordance with its long-term integrated resource plans (IRPs). Although Staff
did not call Idaho Power s resource planning imprudent, it noted that these purchases were made
despite increasingly severe warnings found in Western Systems Coordinating Council (WSCC),
North American Energy Reliability Council (NERC) and Northwest Power Planning Council
(NWPPC) reports. Staff Comments at 19-20.
The Industrial Customers of Idaho Power (ICIP) argued that Idaho Power has not
made a showing sufficient to allow the Commission to find that its power purchases over the past
PCA year have been prudent or that the extraordinary expenses it incurred were not necessitated
by lack of planning. ICIP Comments at 2. The ICIP further stated that the Company has been
imprudent in its failure to actively promote energy conservation measures and independent
power production in its service territory. Id. Therefore, it urged the Commission to review the
Company s load and resource plan and determine to what extent the extraordinary power supply
costs resulted from Idaho Power s load and resource planning decisions. Id. at 8.
Likewise, the Idaho Rural Council wrote that a substantial portion of the power costs
Idaho Power seeks to recover resulted from its failure to take reasonable measures to anticipate
and satisfy its customer s electricity needs. Rural Council Comments at 6. It argued that the
Company knew 1) it had a growing customer base, 2) that it lacked new power generation, and
3) of the Northwest Power Planning Council's concerns. Id.
The u.S. Department of Energy (DOE) also recommended that the Commission
examine the details ofIdaho Power s power supply procurement procedures. DOE Comments at
5. In a similar vein, the Idaho Irrigation Pumpers Association indicated its desire to investigate
in an evidentiary hearing what steps the Company took to secure short-term firm purchases
during months when it knew it would be short of generation due to low water and review the
time period when the Company began "to shift from its reliance upon non-firm to short-term
purchases." Irrigation Pumpers Comments at 2.
Commission Findinf!s Several parties and a considerable number of public
comments allege that Idaho Power s long-term planning and/or failure to deviate from or adjust
long-term plans contained in its IRPs were imprudent in light of known water and market
conditions.
ORDER NO. 28722
Last December the Commission acknowledged ,and accepted Idaho Power s 2000 IRP
for filing" in Order No. 28583 (Case No. IPC-00-10). As noted in the Integrated Resource
Planning Statement of Policy adopted in Order No. 25260:
... the filing of the plan does not constitute approval or disapproval of the
plan having the force and effect of law, and the deviation from the plan
would not constitute violation of the Commission s orders or rules. The
prudence of a utility s plan and the utility s prudence in following or not
following a plan are matters that may be considered in a general rate
proceeding or other proceeding in which those issues have been noticed.
Order No. 25260 at 4 (Case No. GNR-93-3). While the Commission does not intend to review
the IRPs, the Commission will accept further evidence whether the Company s resource
planning is flexible enough to adjust for current water and market conditions. The scheduling of
discovery and other hearing issues will be determined at the Prehearing Conference set for May
2001. See Notice of Pre hearing Conference in Section IV below.
To facilitate this limited review, the Commission directs Idaho Power to file with the
Commission a report outlining short-term plans for the summer and winter of 2001. The report
should show projected loads, anticipated traditional resources, resources acquired to reduce
market exposure, energy provided by each resource, costs paid for each resource, surplus/deficit
energy for summer loads, market resource plans and anticipated cost.
IV. NOTICE OF PREHEARING CONFERENCE
YOU ARE HEREBY NOTIFIED that a Prehearing Conference has been scheduled to
commence at 10:00 A.M. ON THURSDAY. MAY 10. 2001. AT THE COMMISSION
HEARING ROOM. 472 WEST WASHINGTON STREET. BOISE. IDAHO. (208) 334-
0300 The purpose of the Prehearing Conference is to establish a hearing schedule to consider
those issues described above that the Commission has determined warrant further investigation.
More specifically, the Commission intends to conduct an evidentiary hearing to examine the
following issues: trading practices (to include hedging, transmission and wheeling charges, Mid-
C pricing, and the use of weighted average pricing), the November trading event, and the
Company s resource planning.
YOU ARE FURTHER NOTIFIED that the Commission s examination of the trading
practices, pricing mechanisms, and the Company s Services Agreement with IES, may result in
ORDER NO. 28722
amendments to Order No. 28596 issued December 19, 2000 in Case No. IPC-OO-13. See
Idaho Code ~ 61-624.
YOU ARE FURTHER NOTIFIED that the Commission s final determination of the
issues subject to further investigation may ultimately result in the Company s recovery of PCA
revenue in excess of that amount authorized to be collected in this Order. Consequently, the
rates and charges for all Idaho customers, both recurring and non-recurring, including special
contract customers, are at issue and every component of every existing and proposed rate and
charge is at issue. The Commission may ultimately approve, reject or modify the rates and
charges proposed. It may also find that rates and charges different from those proposed by any
party are just, fair and reasonable.
YOU ARE FURTHER NOTIFIED that the remaining PCA issues to be examined in
the subsequent evidentiary proceeding, consistent with the Company s Applications in the
combined PCA filing, represent approximately $59 million in PCA revenue. Recovery of this
amount through a flat charge per kWh would result in an additional rate increase of .4468~ per
kWh imposed on all customers for 12 and one-half months. The rates decided in this Order and
the potential rate impact of the issues yet to be decided is set out below for each customer class:
POTENTIAL
INCREASE
OVER
APPROVED 14 POTENTIAL CURRENT
CUSTOMER GROUP AVERAGE RATE AVERAGE RATE RATES
Residential Gp. Avg. 32.
First Block 7 cents per kWh 0 cents per kWh 20%
Second Block 5 cents per kWh 0 cents per kWh 40%
Third Block 1 cents per kWh 3 cents per kWh 86%
Irrigation 5.1 cents per kWh 5 cents per kWh 41.0%
Small Commercial 6 cents per kWh 8.1 cents per kWh 26.
Large Commercial 9 cents per kWh 3 cents per kWh 43.2%
Industrial 1 cents per kWh 5 cents per kWh 55.2%
YOU ARE FURTHER NOTIFIED that because the rates authorized in this Order and
the revenue associated with those issues subject to further investigation clearly exceed 7% of the
Company s normalized base revenues for the Idaho jurisdiction, the Commission may employ
14 The PCA rates approved in this Order are discussed in more detail in Section VI on Rate Design.
ORDER NO. 28722
other rate stability mechanisms including but not limited to deferring recovery until next year
PCA case. See Order No. 28406 at 19-20.
YOU ARE FURTHER NOTIFIED that all further hearings and prehearing
conferences in this matter will be held in facilities meeting the accessibility requirements of the
Americans with Disabilities Act. In order to participate, understand testimony and argument at a
public hearing, persons needing the help of a sign language interpreter or other assistance may
ask the Commission to provide a sign language interpreter or other assistance as required under
the Americans with Disabilities Act. The request for assistance must be received at least five (5)
working days before the hearing by contacting the Commission Secretary at:
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, ID 83720-0074
[phone] (TELEPHONE)
[phone] (FAX)
YOU ARE FURTHER NOTIFIED that the parties participating in the prehearing
conference may offer to settle some or all of the issues to be discussed at the prehearing
conference.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission s jurisdiction under Title 61 of the Idaho Code and that the
Commission may enter any final Order consistent with its authority under Title 61. The
Commission has jurisdiction over this matter under Idaho Code ~~ 61-622 61-623, and 61-624.
YOU ARE FURTHER NOTIFIED that all further proceedings in this matter will be
conducted pursuant to the Commission s Rules of Procedure, IDAP A 31.01.01.000 et seq.
V. CONSERVATION
Many of those who submitted written comments and testified at the public hearings
called for additional conservation measures and the reinstatement of Demand-Side Management
(DSM) programs. Until the late 1990s Idaho Power had several DSM programs in place
including the Commercial Lighting Program/s the Design Excellence Award Program 16 the
15 The Commercial Lighting Program was discontinued in February 1998 in Order No. 27375 (Case No. IPC-98-
1).16 The Design Excellence Award Program for commercial customers was discontinued in 1997 in Order No. 26931
(Case No. IPC-97-2).
ORDER NO. 28722
Partners in Industrial Efficiency Program I7 and the Agricultural Choices Program.18 These
programs were discontinued for a variety of reasons, including lack of customer interest
concerns regarding their additions to deferred accounts, completion of the program s original
goal, and fear that grants to install energy-efficient equipment could potentially become stranded
assets if deregulation were to occur. Idaho Power was not alone in the termination of DSM
programs, other regulated electric companies in the region similarly terminated their DSM
programs. In place of company-specific programs, Idaho Power participates in the Northwest
Energy Efficiency Alliance (NEEA), a regional approach to conservation whose goal is long-
term market transformation.
In addition to their comments, the Land and Water Fund of the Rockies, Idaho Rivers
United, Idaho Rural Council, and Mary McGown filed a Motion to Reinstate Idaho Power
DSM programs. They further proposed that 10% of the funds sought by the Company in these
cases be dedicated to the establishment of conservation and efficiency programs. Land and
Water Fund Comments at 2. These intervenors also requested hearings to evaluate permanent
programs, including industry and agriculture process-efficiency improvement programs, time-of-
use metering for all classes, net-metered small generation systems, and encourage strong
efficiency standards for local building codes. Id. at 12.
Although they did not file a motion to that effect, the Industrial Customers of Idaho
Power also support the revival of Idaho Power s previous DSM programs. They offer to
implement industrial specific conservation measures that would utilize the funds currently paid
to Idaho Power by the industrial class for the NEEA. ICIP Comments at 9-10.
Recognizing the value of DSM Buy-Back programs like those recently instituted for
irrigators and Astaris, Staff suggested the Company provide a loan program that would allow
customers to borrow money at a low interest rate, with low initiation fees, and amortize the loan
over the life of the installed conservation measure.Staff Comments at 33.Any viable
conservation measure for any customer class would be eligible. Staff argues that customers
would then be empowered to reduce their energy use, saving on their bills and reducing the
utility s dependence on the market.
17 The Partners in Industrial Efficiency Program was discontinued in February 1997 in Order Nos. 26753 and 26957
(Case No. IPC-96-22).
18 The Agricultural Choices Program was discontinued in July 1998 in Order No. 27637 (Case No. IPC-98-4).
ORDER NO. 28722
Commission Findinf!s The Northwest River Forecast Center estimated that as
April 1 , 2001 , Snake River Basin streamflows are only 33% of normal. This is critical because
in a normal water year, Idaho Power generates approximately 60% of its total system
requirements from its hydropower facilities. I9 With less water available to generate
hydroelectricity, the Company is forced to generate more costly thermal power and to purchase
additional off-system power to meet its retail customer requirements. The western wholesale
energy market has been extremely volatile since last summer, in large part due to chronic supply
shortages in California and poor hydro generation conditions throughout the West. According to
the Wall Street Journal average wholesale power prices have increased more than ten times
from prices one year ago ?O Consequently, Idaho Power s energy purchases under these market
conditions have created the extraordinary short-term expense that it seeks currently to recover.
Although the Commission hopes otherwise, it is entirely possible that Idaho will continue to
have poor water conditions and the regional power market will remain astronomically expensive.
In granting the rate increase authorized by this Order, the Commission recognizes that
consumers need avenues to reduce their consumption. 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. Furthermore, the Commission agrees with the Land and Water Fund of
the Rockies, Mary McGown, Idaho Rivers United and the Idaho Rural Council that "basic
fairness demands that all rate classes be afforded the opportunity to enjoy the benefits of guided
conservation and efficiency improvements" comparable to the recently authorized irrigation and
Astaris Buy-Back programs. Land and Water Fund Comments at 2.
The Commission believes that reinstating a comprehensive conservation program is
now appropriate given the current volatility of market prices and the opportunity to incorporate
long-term conservation. Consequently, the Commission now opens a DSM docket in Case No.
IPC-01-13. Idaho Power is directed to file a comprehensive DSM program by August 1 2001
that details program structure, potential conservation measures to pursue and funding options
that include a tariff rider. In particular, the Company should consider addressing conservation
proposals for residential customers in the highest block rate that typically use electric space
19 IPUC Comments in FERC Docket No. RM95-000 and Docket No. RM94- 7-001 at 3 (August 4, 1995).
20 Gavin, Robert Some Utilities Rake in Revenue Amid California Energy Crisis Wall St. 1., Feb. 23, 2001.
ORDER NO. 28722
heating. The Company s subsequent filing will be subject to review by all interested parties
prior to final decision by the Commission.
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
the Company s combined PCA filing sought to recover approximately $227.4 million through
the imposition of a flat 1.8889~ per kWh charge imposed on all its customers over a 12-month
period. Because not all customers pay the same kWh charge, the proposed 1.8889~ per kWh
represents a different percentage increase for each customer class. The percentage impact of the
Company s proposed rate increase for most customer classes is set out below:
TODA Y'PROPOSED PERCENTAGE
CUSTOMER GROUP AVERAGE RATE AVERAGE RATE INCREASE
Residential 5.2 cents per kWh 1 cents per kWh 34.4%
Irrigation 9 cents per kWh 8 cents per kWh 46.
Small Commercial 6.4 cents per kWh 3 cents per kWh 27.
Large Commercial 7 cents per kWh 5 cents per kWh 49.
Industrial 9 cents per kWh 7 cents per kWh 62.
Source: Order No. 28685 at 3.
The Company requests that the new PCA rate become effective on May 1 , 2001.
A. Non-Residential Rates
In its comments, the Staff recommended that all customer rate groups, except the
residential schedule 21 be increased on a uniform cents per kWh basis. Staff Comments at 32.
Although Staff did consider implementing inverted block rates for other customer classes, it
concluded that using inverted block rates for non-residential classes is not warranted at this time.
Id. at 33. The Staff concluded that the uniform rate increase for non-residential customers will
provide a "clear message to conserve wherever it is cost effective.Id. In addition to residential
inverted block rates, the Land and Water Fund recommended that block rates be implemented for
commercial, industrial and agricultural customers. Land and Water Fund Comments at 3.
Commission Findinf!s We agree with the Company and Staff that the rate increases
for irrigation, commercial and industrial customers should be implemented on a uniform 1.2044
21 Rates for residential customers are discussed separately below.
ORDER NO. 28722
cents per kWh charge imposed on all customers over a 12 and one-half month period. This rate
design produces a PCA rate of 1.3415~ per kWh above base rates. 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.
EXISTING APPROVED PERCENT AGE
CUSTOMER GROUP AVERAGE RATE AVERAGE RATE INCREASE
Irrigation 9 cents per kWh 5.1 cents per kWh 31.3%
Small Commercial 6.4 cents per kWh 6 cents per kWh 18.
Large Commercial 7 cents per kWh 9 cents per kWh 32.
Industrial 9 cents per kWh 1 cents per kWh 42.
Imposing a uniform cents per kWh surcharge is reasonable and consistent with past PCA
surcharges. We next turn to the rates for residential customers.
B. Residential Rates
Although the Company proposed that residential rates also be uniformly increased
the Commission Staff recommended that the Commission adopt an inverted three-block rate
design for residential customers. Under the Staffs proposal, residential rates would increase in
each block as a customer s usage increased. For example, the rates for usage between 0 and 800
kWh would increase 12% over existing base rates. For usage in the second block (between 801
and 2000 kWh), rates would increase by 24.1 %. Rates for the third block would increase by
51.7% for all usage over 2000 kWh. Staff Comments at 31; Atch. No. 16.
Staff maintained that adoption of the three-tiered inverted block rates would give a
stronger conservation signal and would be easier to implement and administer than other block
rate designs. The Staff claimed that this rate design for residential customers places a greater
portion of the rate increase on customers using electric space heating. Electric space heating is
the primary cause of the winter peak demand for residential customers. Id. at 32. Staff noted
that the cost of space heating has increased dramatically for all fuels except electricity in the last
two years. While the electric space heating customer s energy costs have actually decreased
over the last two years, the energy cost of natural gas space heating customers have increased by
32%. Id. at 31. Consequently, inverted block rates would mitigate those differences and place a
greater portion of the rate increase on users of large amounts of electricity.
ORDER NO. 28722
The Staffs analysis of annual residential usage showed that 44% of customers would
be billed entirely in the first block, 43% of residential customers would be billed in the first and
second blocks, and 12% of customers would be billed in for usage in all three blocks. Id.
similar trend is evident when considering residential usage. Staffs Attachment No. 15 showed
that the vast majority of residential kWh were billed in the first block, 31 % in the second block
and only 11 % in the last block. The majority of the kWh in the last block occurred during the
winter heating months. Id.
Other parties also supported imposition of a block rate design for residential
customers.The Irrigation Pumpers recommended that an inverted block rate design be
implemented with the ceiling for the first block set at 400 kWh. Irrigation Pumpers Comments
at 3. The Land and Water Fund also recommended block rates for residential customers. It
suggested that the first 500 kWh of energy should be billed at current rates "and any
consumption above that amount subject to an increased rate." Land and Water Fund Comments
at 3. The Fund insisted that block rates would protect low- and fixed-income customers from
rapid swings in electricity rate and encourage conservation.
Commission Findinf!s Based upon our review of the record, we find it is appropriate
and reasonable to implement a three-tiered block rate design for residential customers. There are
several reasons supporting our adoption of this rate design. First, as the Staff and Land and
Water Fund observed, tiered-rates provide residential customers with appropriate price signals to
conserve electricity. In other words, the more electricity used by a customer, the greater the rate.
This structure provides an effective and efficient means of providing customers with incentives
to conserve electricity.
As the Staff pointed out in its comments, 87% of all bills rendered during the year
would occur in the first two blocks and approximately 90% of all residential usage occurs in the
first two blocks. Under a uniform rate increase, residential rates would have increased 23.1 %.
Under our tiered rate design, the PCA surcharge will be: first block 0-800 kWh
, .
8049~ per kWh
(14.4% over current rates); second block, 801-2000 kWh, 1.6098~ per kWh (a 28.8% increase);
and third block for kWh in excess of 2000, 3.4586~ per kWh (a 62% increase). Under the rates
adopted in this Order, only 12% of customers' usage is expected to reach the top block rate.
Thus, the vast majority of residential customers will receive a rate increase below what would
have occurred with a uniform rate increase.
ORDER NO. 28722
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 emoll in levelized pay programs that are intended to reduce or "levelize" bills for
high consumption months with bills for low consumption months. 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 agency may be able
to provide additional information on these programs. Customers interested in conserving energy
may also VIew the u.S. Department of Energy web site located
www.eren.doe.gov/buildings/documents/high heating bills. The Idaho Office of Energy also
dispenses low interest energy conservation loans. Interested persons can access applications and
additional information on their website at: www.idwr.state.id.us/SaveEnergy/Residential.htm
Finally, the Commission s 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
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.
The Commission also notes that the possibility of imposing a tiered-rate design for
residential customers was discussed at every public meeting. Customers asked about the
imposition of inverted rate block generally said that this mechanism could potentially be very
effective in promoting residential conservation. Irrigators and business owners noted that they
had little ability to alter their consumption and thus, block rates would not be as effective for
them.
C. Amortization of Rates
Under normal operations, the PCA surcharge or credit is effective over a 12-month
period. Staff recommended that if the Commission approved an overall rate increase greater
than 20%, that the Commission should consider amortizing (or spreading) the increase over two
years. Staff Comments at
The ICIP also requested that the recovery of this year s PCA occur over five years.
The ICIP maintained that five years is the minimum length of time needed to ameliorate the rate
ORDER NO. 28722
shock effect of the large rate increase. ICIP Comments at 13. The Idaho Rural Council also
requested that any rate increase granted to Idaho Power be spread over five years to reduce its
impact on low-income and fixed-income families, farmers and farming communities. Rural
Council Comments at 3. The U.S. Department of Energy also asked the Commission to consider
deferring a portion of the proposed rate increase. However, the Department did not specify a
specific time period. DOE Comments at 5. Idaho Power s response did not specifically address
amortization but expressed its belief that recovery deferral is "bad policy." Response at
Commission Findinf!s While the Commission is sympathetic to the request that the
authorized rate increase or some portion thereof be amortized over time, the Commission
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 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 water. Given the
amount of purchases the Company has already made, it is reasonable and appropriate for the
Company to recover these costs within the normal one-year timeframe.
This is not to say that amortization is not 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. The Commission intends
to explore this and other rate stability mechanisms when we examine those issues that are
deferred for further investigation. Because several matters have yet to be decided, we do not
address the merits of the deferral issue but place the Company on notice that the Commission
will determine the appropriate manner of any recovery for these deferred issues at a later time.
D. Effective Date
The Company requested that the PCA rates become effective on May 1 , 2001
whereas the Staff recommended that the PCA rates become effective on May 16, 2001. The
Staff explained that the reason for the May 16 date was that last year s PCA rate runs through
May 15 2001. To avoid the apparent overlap, the Staff recommended that the PCA rates in this
case become effective on May 16. Staff Comments at 6.
In its reply comments, the Company indicated that implementing rates on May
would not cause a problem because the Company envisioned terminating the existing PCA rates
on April 30. The Company noted that the Commission s suspension of the February Application
ORDER NO. 28722
was until May 1. The Company also stated that financial institutions, rating agencies, and
customers anticipate the implementation of new PCA rates on May 1.
If the Commission determines that the appropriate effective date is May 1 , the
Company proposes that the new rate reflect the uncollected revenue from last year s PCA from
May 1 to May 15 and offset by the umefunded amount from last year s revenue sharing
adjustment. Response at 20. The Company also proposed that a final adjustment to collect the
true-up revenues over 12 Y2 months would be an appropriate adjustment. Id.Response
Attachment A, p. 1.
Commission Findinf!s We find that the appropriate date to implement the PCA rates
granted in this Order is May 1 , 2001. As the Company noted, customers and financial
institutions anticipate that the Commission will implement new PCA rates on May 1. We also
find that it is reasonable to adopt the Company s proposed adjustment to reconcile the
overlapping PCA and revenue sharing rates. See Appendices 1 and 2 to this Order.
In summary, the Commission is authorizing Idaho Power to recover approximately
$168.3 million, or approximately 74% of its requested PCA revenues. This amount is $159.
million above current rates. The balance of the Company s request is deferred pending our
further investigation into several issues. The Commission is ordering implementation of the
PCA rate changes effective on May 1 , 2001. We believe that allowing the Company to recover
the customers' share of its above normal power costs in a timely fashion ensures the Company of
continued financial viability and, at the same time, protects ratepayers from what may be
imprudent or umeasonable transactions. It is our intent to move expeditiously to resolve the
remaining issues in this case.
ORDER
IT IS HEREBY ORDERED that Idaho Power Company s PCA Applications in these
cases are partially granted. The Company is authorized to implement the rates identified in this
Order, which will generate approximately $168.3 million in PCA revenues.
IT IS FURTHER ORDERED that recovery of the disputed amount of $51 234 902
involving the Company s trading practices and the $7 976 701 associated with the disputed
November transaction will be deferred until such time as those matters are resolved.
ORDER NO. 28722
IT IS FURTHER ORDERED that those issues in Idaho Power Company
Application in Case No. IPC-01-7 that are deferred for further investigation, are further
suspended until August 23 , 2001 , or until such time as the Commission may issue a final Order
accepting, rejecting, or modifying the requested rate increase as it relates to the deferred issues.
IT IS FURTHER ORDERED that those issues in Idaho Power Company
Application in Case No. IPC-01-11 which are deferred for further investigation, are further
suspended until August 23 , 2001 , or until such time as the Commission may issue a final Order
accepting, rejecting, or modifying the requested rate increase as it relates to the deferred issues.
IT IS FURTHER ORDERED that the Company shall file tariffs in conformance with
a uniform kWh rate increase of 1.2044~ per kWh for all non-residential classes. The new PCA
tariffrate shall be 1.3415~ per kWh.
IT IS FURTHER ORDERED that the Company file tariffs in conformance with the
inverted block rate for residential customers previously described in this Order.
IT IS FURTHER ORDERED that the PCA rates established in this Order are
effective May 1 , 2001.
IT IS FURTHER ORDERED that the rate adjustments for PCA undercollection and
umefunded revenue sharing associated with a May 1 , 2001 effective date be included in this
year s PCA rate. The adjustments have been included in the ordered rates shown in Appendix 2.
IT IS FURTHER ORDERED that the March 2001 above forecast power supply costs
are deferred until next year s PCA case.
IT IS FURTHER ORDERED that a Prehearing Conference to establish a hearing
schedule for the issues to be investigated shall take place on May 10, 2001 at 10 a.m. in the
Hearing Room of the Idaho Public Utilities Commission.
IT IS FURTHER ORDERED that the Motion to Reinstate Demand-Side Management
Programs filed by the Land and Water Fund of the Rockies, Mary McGown, Idaho Rivers United
and the Idaho Rural Council is partially granted in that the Commission il).itiates an Idaho Power
Demand-Side Management docket in Case No. IPC-01-13. Idaho Power is directed to file a
comprehensive demand-side management program by August 1 , 2001 that details its program
structure and funding options.
THIS IS A FINAL ORDER AS TO SOME ISSUES. Any person interested in issues
finally decided by this Order or in interlocutory Orders previously issued in these Case Nos. IPC-
ORDER NO. 28722
O 1- 7 and IPC- E-O 1-11 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.
ORDER NO. 28722
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this 30 fi-.
day of April 2001.
~(4PAUL KJELI: NDER, PRESIDENT
See Separate Concurring Opinion
MARSHA H. SMITH, COMMISSIONER
ATTEST:
Je 1). Je~e1
Commission Secretary
bls/lnlO:ipceOl7 _ipceOIII ln2
ORDER NO. 28722
SEPARATE CONCURRING OPINION
COMMISSIONER MARSHA H. SMITH
CASE NOS. IPC-01-7 AND IPC-Ol-
ORDER NO. 28722
Because I support nearly all the findings in this Order, I characterize this as a separate
opinion, not a dissent. I have two concerns about the deferral of $51 234 902 until further
evidentiary hearings are held. First, Commission Orders and directives remain in effect until
changed. It seems that we are stretching this important regulatory principle based on a
technicality. Second, pushing recovery of costs into the future will cost more and extend the
ratepayer burden for the power costs ofthis past year.
In Order No. 28596, issued December 19, 2000, the Commission approved a
methodology to price sales and purchases between Idaho Power and IES. This followed about
two years of work between the Company and the Staff. The Staff supported the agreement and
recommended approval. Two public workshops were held and written comments were filed by a
number of interested persons. The Commission concluded:
Regarding the IPCo/IES Agreement, we find that the Agreement
establishes a reasonable and transparent structure for prioritizing,
protecting and serving native load requirements. We are convinced that
the Agreement gives the Company s native load customers priority and the
economic use and dispatch of Company generation resources
transmission and distribution facilities. In distinguishing between
operating and non-operating transactions, it also provides a reasonable
means of assuring that the Company s native load customers are not
saddled with those risks umelated to providing regulated utility service.
Order No. 28596 at 10.
We also charged the Staff with continuing audit and review of the dealings between
the Company and its affiliate. The Commission should review the methodology regularly to be
sure that it yields fair and reasonable results over time. Further review of the amount in dispute
in this case is necessary and should be done with intense scrutiny.However, changes in
Commission approved methodologies should be implemented prospectively. This has been a
firm regulatory principle to ensure certainty and fairness. Here, the majority finds that because
SEP ARA TE CONCURRING OPINION
COMMISSIONER MARSHA H. SMITH
approvals of the Federal Energy Regulatory Commission and Oregon Public Utility Commission
have not yet been obtained as required by the stipulation, the methodology adopted by our Order
may not yet be in effect. Only in a technical legal sense could those approvals be seen as
conditions precedent to the effectiveness ofthe Commission s Order. I note that FERC issued its
Order on this matter last week.
My second concern is for the timing of the recovery of the power costs for the 2000-
2001 PCA year. It will take some time to conduct the proceeding outlined in the Order.
have scheduled a prehearing conference almost immediately to avoid delay. However, I predict
that by the time the proceeding is concluded, any amount deemed to be justified will be pushed
forward for recovery in the next PCA. It will add to what we already know will be significant
costs that will need to be considered next year. It seems likely that the 2001-2002 PCA costs
may be securitized under the new authority granted by the legislature. If this is the case
ratepayers may still be paying off costs from 2000-2001 in 2007. While I reluctantly supported
the enactment of the securitization bill, I have grave concerns with its use and had hoped it could
be avoided. This deferral makes it more likely that the Commission will authorize the use of
energy cost bonds, thus mortgaging the ratepayers' future.
I recognize that deferral of the $51 million mitigates this rate increase to a degree. I
hope that the cost of deferral does not turn out to be an even greater burden over a longer period
oftime for Idaho Power s customers.
t1~
iJ&~
COMMISSIONER MARSHA H. SMITH
SEP ARA TE CONCURRING OPINION
COMMISSIONER MARSHA H. SMITH
2001-2002 PCA - Ninth Annual
IPC-01-7 & 11
Commission Decision
esc .!J..o.iN Forecast Difference
2001 - 2002 Forecast:
PCA Expense
($)
079 128 132 938 867
Normalized Energy - Total System (MWH)952 283 952 283
Energy Rate (Mills/kWh)23779 52811 29032
Sharing Percentage
(%)
90%
Energy Rate Difference (Mills/kWh)861286723 861
Other Adjustments:
2000-2001 PCA Undercollection
2000-2001 Unrefunded Rev. Sharing
DSM Adjustment
(MWb.)
($/
MWh (Mills/kWh)
126 212,496.40 253 976 522613924 523
662 976
(239 851)
056)
417 068 253 976 03146741 031
13.415
371
12.044
2000-2001 True-up
PCA Rates:
Proposed PCA Rate Adj. from Base (Mills/kWh)
PCA Rate Currently in Effect (Mills/kWh)
Total Rate Difference (Mills/kWh)
Rate Energy Revenue
pec A R ues ($/MWh)(MWh)
Revenue Incr. - Expiring PCA to Proposed PCA 12.044 253 976 $159 630 887
Note: Negative rates and amounts indicate benefits to ratepayers.
APPENDIX
Case Nos. IPC-O1-7 and IPC-O1-
ORDER NO. 28722
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