20051227Objection, requests exhibit B.pdf

. ,
Office of the Secretary
Service Date
May 25, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO PO~R CO~ ANY FOR AUTHOIDTY )
TO INCREASE ITS INTERIM Al\T)) BASE
RA rES AND CHARGES FOR ELECTIDC SERVICE. CASE NO. IPC-03-
ORDER NO. 29505
ISSUED MAY 25, 2004
BOISE, IDAHO
EXHIBIT B
Small General Service Customers (Schedule 7). .............................................................. 56
Large General Service Customers (Schedule 9). .............................................................. 57
Large Power Service Customers (Schedule 19)................................................:............... 60
Irrigation Customers (Schedule 24 and Schedule 25)....................................~.................. 63
Other Rate Design Issues (Schedules 15 42 and Schedules 26, 29, 30). .............
ADJUSTl\fENTS TO THE PCA ............................................................................................... 66
INTER VEN 0 R FUNDING ...... .....
........ ..... .............. ......... .....
.................. ......... ..... ................. ... 66
NEW CASES AND OTHER ISSUES ....................................................................................... 68
ULTIMATE FINDINGS OF FACT .......................................................................................... 69
CON CL USI 0 NS OF LAW ........................................................................................................ 70
0 R D E R .................................................................................................................................... 70
ORDER NO. 29505
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TABLE OF CONTENTS
S U1\1J\fAR Y ... .... ....
........... ............. .... .......... .............. ....... ...................... .... ............ ..... ........ .......
... 1
AP P EARAN CE S ............. .... ......... ........ .......
..... ....... ....... ..... .........
............... .... .......... ... ........... ...... 1
PRO CED URAL m S TORY. .... ................ ............. ........ ........................ ........... .............. ...... ........ 2
TE STYE AR ........ ............... ........ ........ .
~... ...... .................. .... ........ .... ~......... .......... ..... .........
............ 3
ADJUSTl\tENTS TO RATE BASE ............................................................................................ 41. Update to Actuals. ............... ................. ......... ""'" ........ ..................
"""""'" ................
........ 42. Annualizing Plant Adjustments. ....
""""""""
........ ................... ...... .....,....... .............. ......... 5
3. IERCO Investment - Unused Equipment Adjustment. ...................................................... 4. Biological Opinion Adjustment. ......................................................................................... 95. Brownlee Woodhead Park Adjustment............................................................................. 10
6. Known and Measurable Physical Plant Improvements. ................................................... 7. Document Management System. ...................................................................................... 138. Prepaid Pension Expense. .
....... ........ ...... """'"
................... ................................ ........ ....... 149. Capitalized Incentive Pay Adjustment. ..................................................... .......... ....... ....... 15
10. Depreciation Expense and Accumulated Depreciation Adjustment................................. 16
11. Cloud Seeding.
......... .......... ...... ................ ..... ....... ............ ......
.......................... ............ ..... 16
12. Danskin Power Plant. ....... ......... ..... ......
""""" .......
............... .......... .......... ................ ......... 17
ADJUSTMENTS TO TEST YEAR REVENUE AND EXPENSES ...................................... 191. Total Operating Pension Expense Adjustments................................................................ 192. Memberships and Contributions Adjustment. .................................................................. 213. Interest on American Falls Bonds and Pollution Control Bonds. ..................................... 224. Operating Payroll Adjustments. ...... ............. ............................. ...... ............ ................. ..... 235. Incentive Pay Operating Expense Adjustment. ................................................................6. Amortization of Unusual Cases. ........................................................................................ 267. Adjustments to Legal Expenses. ....................................................................................... 278. Adjustments to Property and Liability Insurance Expenses. ............................................ 289. Adjustments to Management Expenses. ........................................................................... 29
10. Intervenor Funding Amortization. .................................................................................... 29
11. Additional Income Tax Assessment. ................................................................................ 30
12. Low Income Weatherization Assistance.................................................................. .........
13. Income Tax Expense.
....... ...... ... ..... ..... .................. """"""""""""""""""'"
........ ............. 33
14. Summary of Adjustments to Rate Base and Test Year Revenues and Expenses. ............ 35
CAPITAL STRUCTURE AND RATE OF RETURN ............................................................. 361. Capital Structure. ...... ................
......... ..................... ............... """""""""""
..................... 362. Cost of Debt. ....
....... """""""""""" """'"
........................................ ............................ ..... 363. Cost of Preferred Stock.. .... ................... ................................................. ........................... 374. Cost of CoIIlIIlon Equity Capital.....
"""""""""""""""'"
.............................. ............ ....... 37
CALCULATION OF REVENlJE DEFICIENCY................................................................... 43
rumSD I CTI 0 N AL SEP ARA TI 0 NS ...................................................................................... 44
COST OF SERVICE l\IE THO DO LOGY ................................................................................ 44
CLASS REVENlJE ALLOCA TI ONS....................................................................................... 47
RATE DESIGN AND TARIFF ISSUES...................................................................................
The Service Charge. .....
"'" ........................ ................................. ............................ ......
..... 51
Residential Customers (Schedule 1). ........................................................................... ..... 54
ORDER NO. 29505
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER CO~ ANY FOR AUTHORITY )
TO INCREASE ITS INTERIM AND BASE
RATES AND CHARGES FOR ELECTRIC SERVICE.
CASE NO. IPC-E-O3-
ORDER NO. 29505
SUMMARY
This is a fmal Order establishing the revenue requirement and rates for Idaho Power
Company s (Idaho Power; Company) electric services in the State of Idaho. Idaho Power filed
an Application on October 16, 2003 for authority to increase revenues by $85,561 910, an
increase of 17.68%, effective November 15, 2003. The Company also requested that, if the
Commission suspended the proposed effective date pursuant to Idaho Code 9 61-622, interim
rates be set effective November 15 , 2003. In Order No. 29369 issued October 28, 2003, the
Commission did suspend the proposed effective date of Idaho Power s new rates and charges
and subsequently considered the appropriateness of interim rates. In Order No. 29403 issued
December 22, 2003, the Commission denied the Company s request for interim rates pending
resolution of this case. By this Order, we authorize Idaho Power to increase its Idaho revenues
by $25 327 533, or approximately 5.2%. As a result, electric base rates for specific classes will
be increased on average by the following percentages: Residential 5.98%; Small General
Service 5.97%; Large General Service 1.98%; Industrial 2.41 %; and Irrigation 13 .95%.
APPEARANCES
Following the filing of Idaho Power s Application, the Commission issued a Notice
of Application and provided an opportunity for interested parties to file petitions to intervene.
The Commission approved all petitions to intervene, resulting in the parties and their attorneys
identified below:
Idaho Power Company:Barton L. Kline
Monica B. Moen
Commission Staff:Lisa Nordstrom
Weldon B. Stutzman
Deputy Attorneys General
ORDER NO. 29505
Industrial Customers of Idaho Power:Peter J. Richardson
Richardson & O'leary
Idaho Irrigation )'umpers Association, Inc.Randall C. Budge
Eric L. Olsen
Racine, Olson, Nye, Budge
Bailey, Chartered
The United States Department of Energy:Lawrence A. Gollomp
Assistant General Counsel
United Water Idaho Inc.Dean J. Miller
McDevitt & Miller LLP
NW Energy Coalition:William M. Eddie
Advocates for the West
Micron Technology, Inc.Conley E. Ward.
Givens Pursley LLP
Community Action Partnership
Association of Idaho:
Brad M. Purdy
Attorney at Law
AARP:Brad M. Purdy
Attorney at Law
Kroger Company:Michael L. Kurtz
Kurt J. Boehm
Boehm, Kurtz & Lowry
PROCEDURAL mSTORY
Idaho Power included in its Application a request for a uniform percentage increase
of 4.16% on all existing rates contained in the Company s tariffs pending a hearing on its
Application and a fmal Order. The Commission convened a hearing on November 13 2003, to
consider Idaho Power s request for interim rate relief. The proposed interim rates were based on
the Company s assertion that it should be permitted to immediately add to rate base its
investment in the Danskin Power Plant, investments it has made in the relicensing of hydro
projects, adjustments to the Company s annual depreciation accounts, and an annual revenue
requirement amount attributable to wholesale power supply contracts that have expired. The
Commission determined that Idaho Power had not demonstrated the existence of a fmancial
emergency to justify interim rate relief, and denied the Company s request for temporary rates in
ORDER NO. 29505
Order No. 29403 issued December 22 2003. The Commission convened a technical hearing on
Idaho Power s Application commencing March 29, 2004 and concluding on April 5, 2004.
Prior to the filing of testimony, the CoIIlIIlission Staff in January 2004 conducted four
workshops for interested customers to discuss the Company s Application and to answer
questions. Formal hearings were held in Pocatello, Jerome, McCall, Payette and Boise in March
2004 to hear from members of the public on the issues presented in this case. Approximately 50
people attended the workshops and about 300 people attended the five hearings. Of those who
attended, 88 people testified at the hearings. In Order No. 29436, the Commission also solicited
written public comments regarding the Application to be filed on or before April 30, 2004. The
Commission received more than 500 timely written comments from the public.
The Commission greatly appreciates the efforts ratepayers made to express their
opinions regarding their electric rates and the proper regulatory oversight necessary to keep
unreasonable expenses out of rates. We heard from many residential customers, the majority of
whom opposed the Company s proposed increase in the service charge. Irrigation customers
also contributed in large numbers to the record and expressed concern about the impact Idaho
Power s proposed 25% increase would have on individual fanns and the agricultural community.
The Commission also heard from a large number of low-income and senior citizens, who asked
us to consider current economic conditions before granting any rate increase. Numerous
customers expressed concern about the lapse of a decade between rate cases, resulting in a large
rate increase request and possible rate shock, rather than smaller incremental changes that would
occur with more frequent rate cases.
With this background in mind, we now discuss the test year and revenue requirement
issues presented in this case.
TEST YEAR
Idaho Power proposed a 2003 test year and initially provided actual account
information for the flTst six months of 2003, and proposed to use projected account information
for the second half of2003. Tr. at 515 , 1247. Because actual data would be available at the time
of hearing, Staff and others argued that actual year-end figures should be used because they are
more accurate than projected figures and better align costs and revenues. Tr. at 542, 1404-
1451-2426-28. Idaho Power did provide actual numbers for the test year accounts showing
year-end balances.
ORDER NO. 29505
Based on the evidence in the record, the Commission fmds use of a 2003 test year to
be reasonable and appropriate in this case. We further find that the 2003 test year shall be
updated with account information through December 2003 as discussed in greater detail below.
ADJUSTl\IENTS TO RATE BASE
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the future period when rates will be in effect." Order No. 25880 at 3. The Idaho
Supreme Court has described "rate base" as "the utility's capital investment amount." Industrial
Customers of Idaho Power v. Idaho PUC 134 Idaho 285, 291 , 1 P.3d 786, 792 (2000).
Adjustments to test year accounts generally fall into three categories: 1) normalizing adjustments
made for unusual occurrences, like one-time events or extreme weather conditions, so they do
not unduly affect the test year; 2) annualizing adjustments made for events that occurred at some
point in the test year to average their effect as if they had been in existence during the entire
year; and 3) known and measurable adjustments made to include events that occur outside the
test year but will continue in the future to affect Company income and expenses. Tr. at 554-55.
This section of the Order addresses the proposed adjustments to rate base, followed by a
discussion of adjustments to test year revenue and expenses.
Idaho Power projected a total electric system rate base for the 12 months ending
December 31 , 2003 to be $1 752 511 220, and made adjustments for known and measurable
changes that reduced the rate base by $79 227 443 , bringing the total proposed jurisdictional rate
base (covering multiple jurisdictions) to $1,673 283 777. Exhibit 21. Idaho Power alleged it
was entitled to an Idaho system rate base in the amount of $1 ,547 443 530. Staff and intervenors
recommended additional adjustments to the rate base calculation, some of which were accepted
by the Company. In this section of the Order we discuss the contested adjustments to rate base
and determine the appropriate rate base for Idaho Power s operations in Idaho.
On the evidence presented and as discussed more particularly below, the Commission
fmds a total system rate base in the amount of $1 643 706 370 to be just and reasonable, of
which the Idaho jurisdiction rate base is $1 519 924 799.
1. Update to Actuals.
As noted earlier, Idaho Power filed its case using actual account information for the
fIrst six months of the test year, and projected amounts for the second half of 2003. Tr. at 515
ORDER NO. 29505
1267. At the prehearing conference, Idaho Power agreed to provide Staff with the opportunity to
review the actual data and present updated infonnation on a supplemental basis if necessary
before the Commission made a final decision. Tr. at 38, 1404. Staff proposed to use actual
account information for the second half of the test year, as that infonnation would be available
prior to a final decision in this case. Tr. at 1404-, 1451-54. Before updating with actual
December figures, Staff witness Holm initially testified that the difference between Idaho
Power s six months of projected data and its actual non-operating revenues, expenses and rate
base amounts through November 2003 was about $6.5 million. Tr. at 1404. In addition, Staff
estimated the customer benefit of updating Idaho Power s December 2003 projection to be an
additional $1.3 million. Tr. at 1405. On March 31 , 2004, under direct examination, Mr. Holm
provided an update of the actual account balances at December 31 , 2003. The resulting revenue
requirement difference between budget and actual numbers is $7.6 million.
The Commission fmds it most reasonable to base its decision on actual account
infonnation for the entire test year. Although Idaho Power witness Smith testified that the actual
account data would "validate" the projected amounts (Tr. at 537), we fmd the $7.6 million
revenue requirement difference between the .actuaI and forecasted half of the test year to be
substantial. It would make little sense to carefully track account information through to the end
of the test year only to disregard actual amounts in favor of forecasted numbers that are less
accurate and merely estimates. The Commission accepts this adjustment as fair and reflective of
the best information available to us in the record.
2. Annualizing Plant Adjustments.
When significant plant improvements are completed late in the test year, the
challenge is to reasonably include the investments in the test year in a way that fairly
compensates the Company for its investment, but also fairly treats ratepayers by matching
investment revenues with investment expenses. Idaho Power proposed, and the Commission has
historically approved, use of an "average" rate base rather than a "year-end" rate base on which
! The test year revenue requirement difference between budget and actual numbers is $7.6 million if the Company
642 gross-up rate is used. If Staffs recommended tax gross-up rate of 1.446 is used instead, the revenuerequirement difference between the 2003 test year budget and actual data is approximately $6.6 million. The $6.
million is calculated by adding the $6.5 million difference between budget and actual data through November 2003
(Tr. at 1404) to the additional $1.3 million forecast for December 2003 (Tr. at 1405); and then subtracting the $1.2
million Company revenue requirement benefit as updated by Mr. Holm under direct examination on March 31, 2004for the actual account balances at December 31 , 2003 (Tr. at 1449).
ORDER NO. 29505
to earn its authorized investment return. Idaho Power proposed to increase its overall rate base
in the amount of $19 779 389 by annualizing plant improvements completed in the last part of
the test year. The rate base impact can be attributed to $6 621 907 for the rewind of Bridger Unit
No.3 and $13 157 482 for completion of the Brownlee-Oxbow transmission line. Tr. at 555.
Staff witness Leckie objected to these Idaho Power adjustments as "not consistent
with Commission-approved methodology for calculating an average-year rate base." Tr. at 1545.
Mr. Leckie contended the adjustment for these plant additions "has the same effect as if Idaho
Power were using the year-end balance for these additions to plant in determining rate base.Id.
Micron also testified that the Compariy-proposed annualization adjustment created a clear
mismatch of revenues and expenses. Rather than recommending disallowance of the Company
proposed adjustments, however, Micron witness Peseau advocated annualizing revenues to year-
end levels assuming a 4.06% growth rate.2 Micron s annualizing adjustment would add
731 765 to Idaho Power s test year revenues. Tr. at 2428-2430.
In rebuttal, the Company recognized that there has been considerable debate over use
of an average rate base or a year-end rate base. Company witness Gale argued that the key
question is "whether the investment in plant under consideration produces revenues.Tr. at
3154. "If the plant that is added does not add additional revenue or if that additional revenue is
de minimis then there is no mismatch of revenues and expenses when the full or year-end
investment of the plant item is included in rate base.Id. Idaho Power stated that the Bridger
rewind and the Brownlee-Oxbow transmission line were completed for system reliability
purposes and will not generate additional revenues. Regarding the Brownlee-Oxbow
transmission line, Mr. Gale argued "that line was constructed for reliability purposes to add an
additional power source to the greater Boise area and does not add additional revenue to the test
year that is not already included." Tr. at 3156.
We generally believe that including investment in the calculation of average-year rate
base as if it were in service the entire year when it was not, as proposed by Idaho Power in this
case, creates a mismatch between test year revenues and expenses. Although the Company
insists that these plant investments will not generate additional revenues, the Commission has
previously noted that "in terms of cash flow all depreciable investments are revenue producing.
2 The Commission declined to adopt Micron s annualization ofrevenues because it would exacerbate the mismatch
issue, as much of the additional revenue that Micron proposes to include is associated with disnibution and other
consumer-related plant that has not been annualized.
ORDER NO. 29505
Order No. 20592 at 12-13.Both the Bridger rewind project and the Brownlee-Oxbow
transmission line should decrease Idaho Power s future maintenance costs. Plant improvements
that increase reliability, especially ones that also "add an additional power source to the greater
Boise area," will undoubtedly enable the Company to earn additional revenues because new
customers will be added to its more reliable plant. Tr. at 3156. We also believe that this new
transmission line may facilitate additional wheeling or allow the Company to sell excess capacity
to other parties on this line or on other lines where capacity has been freed up.
Generally speaking, the Commission expects all utilities to attempt to identify
expense saving and revenue producing effects when proposing rate base adjustments for major
plant additions. It is unfair to ratepayers to assume that the investment in these plants will not
increase Company revenues or decrease Company expenses in the future. Further, it is
unreasonable to expect the Commission to allow full recovery of plant investment as if the plant
had been in operation the full year without a corresponding adjustment to revenues and expenses.
In this case, we want to make clear to Idaho Power and the fmancial community that
the Commission supports prudent plant investment constructed to improve system reliability -
particularly transmission facilities. We find it reasonable to allow Idaho Power s proposed
annualizing plant adjustment for the Bridger rewind and the Brownlee-Oxbow transmission line
based on the particular circumstances of this case. Accordingly, the test year rate base will be
increased by $19 779 389 to account for plant additions that are currently in service and
benefiting customers.
However, we fmd it difficult to justify annualizing plant rate base adjustments
without the Company first attempting to calculate all revenues and expenses, including expense
reductions that would have occurred had the plant been in operation the entire year. Rather than
deny the adjustment outright or require Idaho Power to wait for its next rate case to include this
plant in rate base, we fmd it is just and reasonable to impute increased revenues or reduced
expenses of $995 497 as a proxy for items that were not properly reflected tinder the matching
concept.
Although the proxy s specific calculation should not be used as precedent in other
cases, this proxy amount generally incorporates recognition that on average, plant facilities
recorded in the same account category will over time have similar characteristics related to the
average operation of the system. Information associated with these categories provides the best
ORDER NO. 29505
information available at this time for use as a proxy to determine opportunities available for
additional revenues or reduced expenses. The categories included in the Company
annualization adjustment are Stearn Production, Transmission Station Equipment and
Transmission Lines. New plant requires less maintenance than older plant so the use of averages
is probably conservative when estimating the benefits of reduced maintenance costs and
increased reliability. Increased reliability provides opportunities not previously available that
directly or indirectly generates additional revenues or reduces expenses. This conservative
estimate does not include arbitrage or ancillary service opportunities that may be enhanced over
other transmission lines as reliability increases. It also does not recognize the potential for
increased customer revenues when new growth is served with the increased reliability. Only the
average ratios of revenues and expenses compared to the total plant in each category have been
used to develop the proxy figure.
The approximately $2 million cash flow associated with this plant from depreciation
and the return is greater than the $995 497 imputed for revenues and reduced expenses. Even
with the imputation, the Commission has allowed Idaho Power to recover all out of pocket
expenses associated with this plant and still have a positive cash flow. The impact of our
adjustment is less than either the Staff-proposed $19 779 389 adjustment to rate base and
$623 915 adjustment to expenses, or the $9 731 765 Micron-proposed adjustment that attempted -
to address this mismatch by reducing the Company s revenue requirement.
Considering this Commission s desire to adequately support reasonable infrastructure
investments, we believe our overall result is fairer to Idaho Power than the adjustments
recommended by the other parties. It is also a reasonable outcome for ratepayers, who will
experience greater service reliability as a result of this plant investment. Any additional
revenues or reduced expenses will be known and properly reflected in the next general rate case
that Company witness Gale indicates can be expected in "two to three years." Tr. at 3193. The
Company is directed to better identify all the increased revenues, reduced expenses or any other
benefits if it wishes to annualize plant investment in future cases.
3. IERCO Investment Unused Equipment Adjustment.
The primary purpose of the Idaho Energy Resources Company (IERCO) is to mine
coal for the Bridger Power Plant. Idaho Power treats IERCO's coal operations as a part of Idaho
Power s utility operation and adds current year IERCO earnings to electric operating income and
ORDER NO. 29505
its investment in IERCO to net electric rate base. Tr. at 521-22. Idaho Power reduced IERCO'
rate base for notes payable of $5 909,558 and associated interest income of $78 613. Tr. at 522-
23. Staff recommended further reducing the IERCO rate base by $280 937 for equipment no
longer used and useful. Tr. at 1571. The assets identified as no longer used and useful are: a
dragline and bulk lube system, the dragline monitoring, and inergin fITe system for the dragline;
two 62-yard buckets; a Hitachi power shovel; a lowboy tractor; and a 1995 Ford truck. Tr. at
1573.
The Commission accepts adjustments to IERCO rate base made by Idaho Power, and
also finds Staff's recommendations to be reasonable and fair. Assets no longer used in utility
operations should be removed from rate base. Accordingly, Idaho Power s one-third interest in
the IERCO rate base, as reflected in Idaho Power s rate base, shall be reduced by $280 937. This
rate base adjustment will also reduce annual depreciation expense for the equipment no longer
used and useful by $133,554.
4. Biological Opinion Adjustment
Idaho Power included in rate base its costs incurred defending against a lawsuit
related to a National Marine Fisheries' Biological Opinion. In March 1997, the Sierra Club
Legal Defense Fund filed a "notice of intent to sue" for violation of the Endangered Species Act
with the Federal Energy Regulatory Commission on behalf of several environmental groups
alleging that operation of the Hells Canyon Complex imperiled certain anadromous fish. Tr.
634-36. Idaho Power defended its Hells Canyon operations, incurring attorney fees totaling
$654 740 during 2000 and 2001. Idaho Power capitalized the entire amount and included it in
rate base. Tr. at 1567. Staff objected to this rate base adjustment, contending the costs incurred
should have been booked as an expense rather than to rate base. Staff witness Leckie argued
without some benefit that would extend into the test year and beyond, it is not reasonable for
Idaho Power to capitalize these expenses and include them in rate base.Jd.
In rebuttal testimony, Idaho Power explained the reason for capitalizing these defense
costs. If the challenge brought to its Hells Canyon operations had been successful, it would have
impacted each year of operation into the future. Tr. at 636. Thus, Company witness Prescott
contended the Company s defense "prevented negative impacts to revenues and expenses in the
test year as well as years into the future." Tr. at 637.
ORDER NO. 29505
The CoIIlIIlission finds that the legal expenses incurred by the Company to oppose
the legal action regarding the Biological Opinion should be booked in the year incurred as an
expense, rather than capitalized and added to rate base. We find this to be reasonable and
consistent with Idaho Power s expensing of Snake River Basin Adjudication legal costs to
defend the Company s water rights over the last decade. These Biological Opinion legal
expenses were incurred over a short duration and are not the type of expense to be normally
capitalized. Accordingly, the rate base requested by Idaho Power shall be decreased by
$654 740.
S. Brownlee Woodhead Park Adjustment
Idaho Power included in rate base investments it made for improvements to the
Brownlee-Woodhead Park that is part of its Hells Canyon Complex. The costs of the
improvements totaled $7 525 237. Staff argued this amount should not be allowed in rate base
until after Idaho Power completes relicensing of its Hells Canyon hydroelectric plants. Staff
witness Leckie argued "it is reasonable to conclude that Idaho Power is hopeful that these
additional improvements will facilitate a smoother relicensing process " and that "the extent of
the park reconstruction and enhancements were meant to exceed the life of the current license
term." Tr. at 1564-65.
In rebuttal testimony, Idaho Power pointed out that the park improvements were
completed in 1996 and are currently used extensively by the public. Tr. at 630. Company
witness Prescott testified that while '"the primary motivation for the improvements was
compliance with the existing FERC license " the Company conceded "that a significant benefit
of rebuilding the facility prior to relicensing was to demonstrate responsiveness to public needs
and moderate requests for additional facilities at Woodhead Park during the relicensing process.
Tr. at 631. There is no question that the Woodhead Park improvements are complete, used and
useful. Tr. at 633.
The Commission finds that the $7 525 237 in improvements made by Idaho Power to
Woodhead Park should be capitalized and included in rate base. The evidence is uncontroverted
that the improvements were completed as a requirement of the existing and/or future FERC
licenses for Idaho Power s Hells Canyon Complex, and that the improvements are currently used
and useful. Although there is some question regarding whether the Company built the park
larger than the current license requires, the Commission believes doing so was not imprudent and
ORDER NO. 29505
may have been cost-effective in light of the current relicensing proceedings. The Commission
also notes that the inclusion of these costs in rate base serves as a reminder of the financial
impact that projects related to relicensing have on customer rates. We encourage Idaho Power to
evaluate current park usage fees to minimize park costs to be recovered from ratepayers in the
future. Tr. at 1566.
6. Known and Measurable Physical Plant Improvements.
Idaho Power proposed an upward adjustment to rate base for plant improvements it
expects to complete by May 2004. Because the costs are known and measurable, Idaho Power
added $18 388 690 to the 2003 test year rate base for upgrades to the Brownlee-Oxbow
transmission line and Star, Vallivue, Midrose and Goshen transmission stations. Tr. at 555.
Staff witness Leckie agreed these known improvement costs should be included in rate base, but
objected to the manner in which the Company added the costs, noting "it is a question of how the
cost of these projects should be included in computing the 13-month average rate base." Tr.
1555. The Company proposed to add the entire amount to each month of the test year rate base
and also increase related test year expenses for these projects by $447 375 for depreciation
$112 171 for property taxes, and $8 199 for insurance. Noting that the Company did not make
any attempt "in its testimony or exhibits to quantify customer benefits that result from these
additions to plant," Mr. Leckie claimed including only the costs without adjusting revenues
created a mismatch in the test year that "is not fair to ratepayers.Tr. at 1556.S taff
recommended the project costs be added to rate base only in one month of the test year and then
averaged over the 13-month test year. In that way, the projects would be recognized in rate base
with no need for an offsetting increase in revenues. Staff's recommendation would decrease the
Company s adjustment to rate base by $16 974 175. Tr. at 1561.
Micron also objected to the Company s proposed known and measurable adjustments
for major plant additions. Dr. Peseau testified that with the exception of depreciation, all
remaining known and measurable adjustments should be denied because they are not sufficiently
certain to occur and Idaho Power has made no effort to quantify offsetting revenue benefits like
the embedded cost of long-term debt. Tr. at 2434-36. Micron s proposed adjustment would
reduce Idaho revenue requirement by $11 768 222. Tr. at 2438.
In rebuttal testimony, the Company argued that the project costs should be included
in the test year rate base. Although falling outside the test year, Company witness Obenchain
ORDER NO. 29505
insisted they "will be plant-in-service and used and useful by the time the rates determined by
this proceeding go into effect." Tr. at 2792. He also maintained that "customers are receiving
the benefits of these sizable plant investments now " these transmission projects increase the
system reliability, and that "even though these investments may not produce revenues(,) they do
produce benefits for customers." Tr. at 2795.
It is true that these projects, if completed on schedule as planned, will be operational
by the time new rates go into effect, and thus produce a benefit for customers. But it also is true
that these projects produce a benefit for Idaho Power that may include additional revenues, and
the Company made no effort to quantify the benefits it will receive from the additional
investments. The Commission generally believes that putting the known and measurable
adjustments in rate base for a full year creates a mismatch between revenues and expenses in the
test year if benefits are not needed too. Although the Company insists that these plant
investments will not generate additional revenues, the Commission has previously noted above
and in Order No. 20592 that all depreciable investments produce revenue. Idaho Power s newly
built transmission stations will reduce maintenance expenses for the old Goshen station and
create additional revenues from the growth served by the new Star, Vallivue and Midrose
substations. Again, we know. these benefits exist but are without the information necessary to
precisely calculate them, and thus we must use some reasonable means of estimating them.
As we explained in the "Annualized Plant Adjustments" section (supra at 5), we
generally expect all utilities to identify expense saving and revenue producing effects when
proposing rate base adjustments outside the test year for major plant additions. In keeping with
our desire to promote reasonable plant additions, we also find it reasonable to allow Idaho Power
to include the $18 388 690 of known and measurable plant adjustments for the Brownlee-Oxbow
transmission line and Star, Vallivue, Midrose and Goshen transmission stations in rate base and
earn a return on this investment.
However, we also believe it is critical to match revenues and expenses to these plant
additions. We, therefore, fmd it reasonable to use a proxy for the actual additional revenues or
reduced expenses that have not been adequately quantified by Idaho Power and impute
031 733 of revenue and reduced expenses in calculating the Company s revenue requirement.
This revenue and expense reduction imputation for the known and measurable adjustment is
calculated in the same manner as that imputed for the annualized plant. The account categories
ORDER NO. 29505
for the known and measurable plant include Transmission Station Equipment and Transmission
Lines.
The impact of this imputation is less than either the $16 974 175 Staff-proposed rate
base adjustment or the Micron-proposed adjustment that attempted to address this mismatch by
reducing the Company s revenue requirement. Again, this imputed revenue may be conservative
but we believe the overall result is just and reasonable.
The approximately $1.9 million in cash flow associated with this plant from
depreciation and the return is greater than the $1 031 733 imputed for revenues and reduced
expenses. Even with this imputation, the Commission has allowed Idaho Power to recover all
out of pocket expenses associated with this known and measurable plant adjustment as it did
with the annualizing adjustment. Although this imputation achieves a fair result in this case, the
specific calculation should not be used as precedent in other cases.
7. Document Management System.
Idaho Power added $106 275 to the test year rate base for the entire cost of a
Shareowners' Document Management System. Noting that Idaho Power only has one
shareowner, IDACORP, Staff testified that only IDACORP has enough shareowners to require a
shareowners' document management system , and thus the benefits of the system flow mostly to
IDACORP. Tr. at 1569. Staff witness Leckie recommended the cost of the system be shared
equally between the ratepayers and shareowners, which "is the same treatment as that used to
allocate Board of Directors' fees.Tr. at 1570. Sta:frs recommendation would remove $53 137
from Idaho Power s proposed rate base, and reduce the Company s annual depreciation expense
by $7 295. Id. The Company offered no response to Staff's proposed adjustment in its rebuttal
testimony.
The Commission finds that including the entire cost of the Shareowners' Document
Management System in rate base would be unfair to ratepayers. Because the system benefits
IDACORP in its administrative responsibilities much like the fees paid to its Board of Directors
we fmd that it should be allocated the same as the Board of Director s fees in this case.
Therefore, only one-half the cost of the system should be included in Idaho Power s rate base.
Accordingly, Idaho Power s rate base adjustment will be reduced by $53 137 reflecting the cost
of the system, and by $7 295 for reduced depreciation expense.
ORDER NO. 29505
8. Prepaid Pension Expense.
Idaho Power included in test year rate base $17 800 477 for prepaid pension expense.
Staff witness English contended none of the prepaid pension amount should be included in rate
base. He argued that "prepaid pension expense is not an asset of the Company, but rather an
asset of. the trust that maintains the assets of the pension plan," and, as such, it "is not an asset
that provides electric service on which shareholders are entitled to earn a return.Tr. at 1510-
Il. Staff insisted the prepaid pension amount "is clearly not an asset that should earn a return if
Idaho Power has no ownership of the funds, no discretion on how those funds can be used, and
those funds cannot be returned to them.Tr. at 1511. Mr. English also pointed out that the
Company "has not made any contributions to the pension plan since 1995 , and any contributions
prior to that were funded by customers." Tr. at 1512.
Idaho Power witness Fowler argued in rebuttal testimony that the prepaid pension
amount should be included in rate base because the "asset represents a use of cash. It is a
consequence of providing a pension plan for employees, following the required rules for funding
the plan, and recording the expense of the plan on the Company s books." Tr. at 2870-71. Idaho
Power asserted the pension plan itself "is an important benefit for attracting and retaining the
employees needed to provide reliable electric service to the Company s customers.fd.
The Commission agrees that the Company s pension plan is important to its
employees and helps retain effective workers. The question, however, is whether an
accumulated pension amount should be included in rate base for ratemaking purposes so that
customers pay a return on the prepaid pension amount.
Idaho Power collected enough money in rates from customers since the last rate case
to fund its pension plan. Because Idaho Power did not accurately predict that its pension fund
would experience favorable investment results, the pension fund was subsequently over funded.
The over funded portion exceeded the amount the Company recorded on its books, creating a
prepaid pension asset. If Idaho Power had predicted this at the time of its last rate case, the
Company s revenue requirement would have been reduced, ratepayers would not have paid in as
much, and Idaho Power s pension plan would not be as over funded as it is now. An over-
funded pension plan benefits the Company and its employees.
Because prepaid pension assets result from accounting procedures rather than funds
actually contributed, they are not the type of asset providing electric service upon which Idaho
ORDER NO. 29505
Power and its shareholders are entitled to earn a return on investment. Furthermore, as a result of
these prepaid pension assets, Idaho Power s actual cash contribution during the 2003 test year
was zero. Evidence in the record indicates that no contributions will be made in the next several
years as well. Tr. at 1509, 2879. Therefore, we find it is unreasonable to include the
$17 800 477 prepaid pension amount in rate base.
9. Capitalized Incentive Pay7tdjustmenL
Idaho Power proposed an approximately $5.1 inillion increase in payroll expense for
incentive pay, but later updated its forecast of incentive payments to $4 837 358 instead of the
original $5 114 821. Tr. at 1426. The incentive plan, implemented by the Company in 1995
pays employees an additional percentage of their base salary when IDACORP's earnings per
share reach certain levels. Staff argued that employee incentive plan costs should not be
included in the test year rate base for two reasons. First, employees already receive adequate
compensation. Second, the incentive amount is tied to IDACORP earnings, not Idaho Power
performance. Because a portion of employee incentive payments are capitalized, Staff identified
the amount of $7 741 747 that shoUld be removed from rate base if the Commission disallows
the incentive plan costs in the test year. Tr. at 1427. Micron also recommended denial of the
incentive pay adjustment because it is not certain to occur, its net impact on revenue requirement
cannot be quantified, and the adjustment could as easily be positive or negative. Tr. at 2432-33.
Idaho Power argued on rebuttal that Staff's arguments that incentive pay overpays
employees in the current labor market and does not benefit customers are erroneous. Company
witness Minor stated that if Idaho Power had not implemented an incentive pay plan and had
continued to maintain the salary structure at the poth percentile base level, base compensation
would be $7-8 million higher. Tr. at 2827. If the Commission denies its requested incentive pay
expense, Mr. Minor testified that management ",rill be forced to make adjustments in base pay to
bring its total class compensation back to the 60th percentile with a resulting increase in Idaho
Power s fixed total compensation. Tr. at 2829-2840 2846.
As discussed in greater detail in a following section dealing with adjustments to test
year revenues and expenses, the CoIIlIIlission concludes the incentive plan costs should not be
included in the test year. We only note here that one effect of that decision is a reduction to the
test year rate base of $7 741 747 to remove the capitalized portion of the plan costs from rate
base along with the associated $230 594 depreciation expense.
ORDER NO. 29505
10. Depreciation Expense and Accumulated Depreciation Adjustment
In 2003, Idaho Power flIed and the CoIIlIIlission approved changes in the
depreciation rates for the Company s plant investments. In this case, proposed test year
adjustments to the accumulated depreciation balances are based on the depreciation rates it
initially sought in Case No. IPC-03-7. Staff pointed out that the Company stipulated to the
new depreciation rates in that docket and recommended the test year depreciation accounts
reflect the new depreciation rates approved by the Commission in Order No. 29363. More
specifically, Staff recommended the accumulated depreciation balance included in rate base be
reduced by $2 205 647, and the annual depreciation expense be reduced by $4,411 294 to reflect
the Commission findings in that Order. In rebuttal testimony, the Company stated that,
obviously, the Company agrees with the reduction of depreciation expense of $4 411 292. This
amount is reflective of the settlement depreciation case, IPC-03- 7" that was approved after the
filing of the general rate case. Tr. at 3180.
Multiple parties (including Idaho Power) stipulated to these rates that were approved
last October. Given Idaho Power s agreement with the reduction in the depreciation expense, it
follows that the accumulated depreciation in rate base must also be reduced by $2 205 647.
Consequently, the Commission finds it appropriate that the accumulated depreciation amount
Idaho Power proposed for rate base be reduced by $2 205 647.
11. Cloud Seeding.
Idaho Power included in the test year operating expenses of $897 448 and capital
costs of $214 600 for a cloud seeding program. Cloud seeding is an experimental program to
artificially increase winter precipitation. Staff witness Hessing testified that the Company "did
not provide enough information in its filing for Staff to make a recoIIlIIlendation on the merits of
cloud seeding.Tr. at 1628. Noting the "experimental and somewhat controversial nature of
cloud seeding programs and the sizable amount of money requested to be included in rates " Mr.
Hessing recommended the costs be removed from the test year if the Company did not provide
additional information demonstrating that the costs were prudently incurred. Tr. at 1629. The
Irrigators also objected to the cloud seeding costs. They reviewed Idaho Power s response to
questions about Account 536, the expense account that includes the cloud seeding program
where the Company stated "the cloud seeding program was started in late 2002, but the test year
(2003) includes expenses for a full year of operation.Tr. at 2541. Mr. Yankel testified that
ORDER NO. 29505
cloud seeding is not a regular activity and should not be included as a normal test year
expense.
In rebuttal testimony, Idaho Power responded to Staff's complaint that the Company
had not provided information about the cloud seeding program. Idaho Power acknowledged,
There is no question that cloud seeding is somewhat controversial and. experimentation is
ongoing.Tr. at 640. The Company provided a brief history of its past interest in a cloud
seeding program, culminating with the hiring of a full-time meteorologist in 2002 and the
initiation of an operational program in late January 2003. Tr. at 642. Cloud seeding began in
February and continued until April 15, 2003. Id Idaho Power explained that the Company will
do "an in-depth evaluation phase over the current and the next winter seasons " and that a
university affiliated institute "has initiated work this winter to evaluate the program.Tr. at
644-46. Negative results for the aircraft or ground seeding component "that cannot be
adequately explained will likely lead to cancellation of that piece of the program.Id The
Company was optimistic that "results from the assessment are expected to. demonstrate the
effectiveness of the project." Tr. at 652.
Given the experimental nature of the cloud seeding program and the lack of
demonstrated effectiveness, the Commission fmds that cloud seeding expenses are not a normal
test year expense and should not be included in the test year. The program lasted only three and
a half months of the test year and results are at this time speculative. Evaluation and analysis of
the program could lead to its cancellation, and that evaluation is only beginning. Under these
circumstances, it would be unfair to ratepayers to include all cloud seeding program costs in the
test year as if it were continuing each year into the future. Moreover, we believe that the money
invested in cloud seeding could be better spent on programs that will provide a known benefit,
such as demand-side management or smart meters.
12. Dansl.:in Power Plant.
Idaho Power included in rate base the cost of constructing the Danskin Power Plant,
which totaled $53 440 376. This figure does not include amounts paid for natural gas costs
which are flowed through the Power Cost Adjustment (PCA) and thus reconciled with expenses
in this case. Danskin was completed in the summer of2001 to serve as a peaking facility, that is
it is "primarily used to meet extreme load conditions, which for Idaho Power Company usually
occur during the later afternoon or evening hours in mid summer.Tr. at 603. Staff witness
ORDER NO. 29505
Sterling s testimony reviewed the conditions at the time Danskin was developed and
recommended the Commission include the construction costs in rate base. Tr. at 1649.
The Industrial Customers of Idaho Power (ICIP) witness, Dr. Reading, recommended
the Commission not give the Company rate base treatment for Danskin.Tr. at 1334. ICIP
noted that the Commission, when considering approval of the construction of Danskin, asked the
Company to provide more information about alternatives it considered and the forecasted need
for the facility. ICIP maintained that the Company failed to provide any additional information
in this case, and that Danskin is operating significantly fewer hours per year and at higher costs
than anticipated. Tr. at 1314-25. Moreover, ICIP argued that Idaho Power should have
reassessed Danskin' s economic viability at the time the Commission approved its Certificate.
Tr. at 1334.
Idaho Power in its rebuttal testimony responded to the criticisms of ICIP and
provided additional information regarding the Danskin plant. Tr. at 603-27. Mr. Prescott
pointed out that Danskin is a "resource of last resort," which means the plant is operated only
when there is no transmission available or when market prices are so high that market purchases
are unattractive." Tr. at 613.
The Commission finds that Idaho Power is entitled to include Danskin plant costs in
rate base. The extraordinary conditions that existed at the time Danskin was developed
warranted a rapid response by the Company, and justify the investment in a peaking facility that
by design is more costly to operate than other types of facilities. While the hourly operation
numbers projected by Idaho Power have not materialized and are unlikely to do so in the
foreseeable future, they are within the hours of operation discussed for purposes of its certificate
of convenience and necessity. For these reasons, we believe that authorizing the requested
Danskin rate base amount and associated expenses to be appropriate and reasonable.
Although the Company did not provide additional information requested by the
Commission until after its omission was pointed out by ICIP, we decline to withhold ratemaking
treatment of its investment solely on that ground. The Company s inattentiveness to this filing
requirement made it considerably more difficult for us to review Danskin' s plant costs for rate
base recovery. We expect the Company will not place the Commission in a similar position
when it seeks cost recovery of the Bennett Mountain generating facility. Tr. at 3193.
ORDER NO. 29505
ADJUSTl\tENTS TO TEST YEAR REVENUE AND EXPENSES
Micron had a general criticism to Idaho Power s adjustments to test year expenses.
Dr. Peseau noted that the Company proposes to use test year revenues, after updating the
projected figures with actual 2003 figures normalized for weather and other standard
adjustments, but that "expenses and rate base are treated in a much different manner.Tr. at
2426-28. Furthermore, by annualizing operating and maintenance expenses and certain rate base
items, Idaho Power creates a mismatch between revenues and expenses that is made worse with
its proposed known and measurable adjustments. The result is a "partially projected test year
ending on May 31 , 2004 for rate base and expenses, matched against revenues centered on June
, 2003.Tr. at 2428. To correct the mismatch, Micron recommended that revenues be
annualized to 2003 year-end levels, which would add $9,731 765 to Idaho Power s test year
revenues. Tr. at 2428-29.
The Commission recognizes that Micron is correct and that a mismatch of revenues
and expenses exists. We have chosen, however, to address this with individual adjustments
rather than annualizing revenues to 2003 year-end levels because annualizing revenues for
customer growth would create a different mismatch between rate base, revenues and expenses.
Not all customer-related plant and expenses were annualized or proformed to year-end levels, so
we decline to adjust revenues in total to year-end levels in this case.
Before discussing individual adjustments to test year revenue and expense accounts
we note that Idaho Power accepted some of the adjustments proposed by the other parties
resulting in a reduction of the additional revenue requirement requested by the Company. Idaho
Power originally requested approval to increase its annual revenue by $85 561 910, but reduced
the amount to $70 675 029 after accepting some of the test year adjustments recommended by
Staff and other parties. Tr. at 3183. The adjustments Idaho Power accepted included changes to
pension expense, memberships and contributions, year-end payroll, the Standard Salary
Adjustment (SSA), incentive pay, and depreciation. Exhibit 80.
1. Total Operating Pension Expense Adjustments.
Idaho Power included in its test year expenses $9,188 163 for employee pension
expenses, including a proposed expense adjustment of $2 170 163 to change the pension expense
accounting from Net Periodic Pension Cost to Service Cost. Tr. at 529, 1253, 1497-98.
Company witnesses justified the additional expense based on the Service Cost standard as more
ORDER NO. 29505
accurately reflecting future pension costs and necessary to remove market volatility and interest
rate volatility. ld. and 1252-53. Staff disagreed with the expense adjustment to reflect Service
Cost, and in its rebuttal filing the Company agreed the $2 170 163 pension cost adjustment
should be removed from the test year expenses. Tr. at 2858 3181.
Staff also recoIIlIIlended two other reductions in test year pension expense, one
totaling $1 379 149 and the other totaling $5 638 851 , that together would bring test year pension
expenses to zero. Staff's fIrst recommendation was to disallow additional pension expense
resulting from Idaho Power s test year changes to actuarial assumptions used in calculating
pension costs. Staff testified that the Company s reduction in the pension plan discount rate and
future expected return on plan assets were not justified by any change in circumstances, and "the
fact that these changes served to increase pension expense during the test year seemed a little
suspect." Tr. at 1501-02. Staff recommended that the long-term rate of return on pension assets
of 9.0% used by Idaho Power prior to the test year continue to be used, resulting in an expense
reduction of $1 379 148 in the test year. Tr. at 1504. In rebuttal testimony, the Company
pension expert testified that many corporations lowered expected long-term rates of return for
their pension plans between 2002 and 2003. Tr. at 2859. For example, the median assumed
long-term rate of return on pension assets for the 100 largest corporations declined from 9.50%
to 9.00%. ld. Thus, Idaho Power believes it is reasonable to reduce its assumed pension return
from 9.00% to 8.50%.
Staff's fmal adjustment to test year pension expense was to reduce the expense by
638 851 , bringing the test year pension expense to zero. Staff witness English explained that
this adjustment "is a reconciliation between cash and accrual accounting." Tr. at 1505. In other
words, although the Company accrues a pension contribution on its books for fmancial reporting
purposes, Idaho Power "did not contribute to the plan for 2003 and therefore did not incur any
actual costs.ld. In fact, Mr. English testified the Company "could not have legally contributed
to the pension plan (in 2003) without incurring penalties.Tr. at 1507-08. Furthermore, the
Company has not been able to contribute to the pension plan since 1995, but "continued to
recover in rates more than $3 million per year from ratepayers for pension expenses.Tr. at
1508. Mr. English concluded the Company "has recovered nearly $19 million more than (it)
actually contributed to the pension plan since 1993.ld. Idaho Power opposed Staff's final
adjustment to the test year pension expense. Company witness Fowler testified "the critical need
ORDER NO. 29505
for using a consistent methodology from year to year is disregarded when the pension cost
allowed is switched from a FAS 87 basis (accrual accounting methodology) in one rate filing to a
cash basis in the next." Ir. at 2864.
Based on the information in the record and the Company s concurrence with Staff's
recommendation, the Commission accordingly accepts the reduction in test year pension expense
of $2 170 160 reflecting the use of Net Periodic Pension Cost rather than Service Cost. The
Commission also fmds it reasonable to leave the long-term assumed rate of return on pension
assets at 9.00% based upon the testimony presented and returns on pension assets that have
averaged 12.97% over the past 15 years. Tr. at 1504 2871. Accordingly, the Commission will
reduce Idaho Power s adjustment to the test year pension expense by $1 379,148.
On the evidence presented in this case, the Commission also fmds the final
adjustment proposed by the Staff for the pension plan expenses to reconcile cash and accrual
accounting to be fair and reasonable. Accordingly, the test year pension plan expenses will be
reduced to zero, reflecting the actual pension plan expenses incurred by the Company. Idaho
Power has said that one can "expect a general rate case in two to three years." Tr. at 3193. The
pension expense can be re-evaluated at that time to determine if a ratemaking adjustment is
warranted.
2. Memberships and Contributions Adjustment.
Staff proposed to reduce test year operating and maintenance expenses by $326 014
to disallow some of the membership and association dues paid by the Company. Tr. at 1513-
Revised Exhibit 110. The bulk of the $246 048 reduction recommended by Staff removes 75%
of the dues paid to the Edison Electric Institute (EEI). Tr. at 1514, Exhibit 110. Staff's
remaining reductions are for dues paid to Rotary Clubs, Lion s Clubs, Chambers of Commerce
political parties, the Arid Club in Boise, and small fees paid to a number of other organizations.
Staff recognized the Company s participation in various organizations may enhance the Idaho
Power image and provide a social presence for the Company and its employees. Tr. at 1514.
The Company in rebuttal testimony agreed that some of the fees identified by Staff
should not be included in test year expenses. Specifically, the Company agreed that the amount
it included should be reduced by $38 066, representing fees paid to political parties and
charitable contributions made by the Company. Tr. at 3143-46. Idaho Power vigorously
ORDER NO. 29505
opposed elimination of the remaining expenses as having legitimate business purposes
particUlarly its EEl-related expenses. Tr. at 3131-47.
The Commission has consistently disallowed for ratemaking purposes political and
charitable contributions and a portion of the dues and association fees paid by the Company. We
find it reasonable and appropriate to do so in this case. The Commission agrees with Staff and
the Company that $38,066 should be removed for political and charitable contributions. We also
recognize that the Company s participation in some organizations has a legitimate business
purpose and benefits its customers. The Commission further finds that EEI offers its members
education on industry issues and management training, both of which are legitimate business-
related expenses. Accordingly, we adopt only one-third of Staffs proposed expense reduction
reflect remaining activities that are not appropriately in rates. Therefore, the Commission
determines it just and reasonable to reduce the test year contribution and membership expenses
by $95 983.
3. Interest on American Falls Bonds and Pollution Control Bonds.
Idaho Power made a test year adjustment to its interest expense on American Falls
bonds, claiming an increase in 2004 was known and measurable in the amount of $297 436. The
American Falls bonds are guarantees reflected in operating expenses as a falling water payment,
not in the cost of debt and overall rate of return like other bonds. Staff witness English
recommended disallowing the Company s adjustment, arguing the increase in interest expense
above the test year amount was "neither knO\\'Il nor measurable.Tr. at 1523. Idaho Power
originally forecast the interest expense for the second half of 2003, as well as for 2004. Staff
noted that the Company s forecast methodology assumed a jump in the bond interest rate from
3% on December 31 , 2003, to 4.2% the next day, January 1 2004. Tr. at 1522. Because Staff
believed "the methodology used by Idaho Power grossly overstates the forecasted interest rate
Mr. English recommended the test year adjustment proposed by Idaho Power to increase
American Falls bond interest expense in the amount of $297 436 be disallowed. Tr. at 1523. In
addition, Staff proposed a reduction in the test year interest expense based on the most recent
interest rate available, 2.35% on January 20, 2004. fd If this rate were applied to the test year
American Falls bonds, the test year interest expense would be reduced by $29 418.50.
Staff also recommended a similar adjustment to cost of debt and test year interest
expense related to the Pollution Control Revenue Bonds. As with the American Falls bonds
ORDER NO. 29505
Idaho Power used an estimated interest rate based on a ten-year average of the Bond Market
Association (BMA) index to state the interest expense for these Pollution Control Bonds. Tr.
1524 2754 Stafi ess tes1:l d "e ten-year average is not reflective of the
current rate or the rates for the last several years.Tr. at 1524. Instead, Staff recommended
using the current interest rate as of December 31, 2003 to determine the actual 2003 year-end
cost of debt." Tr. at 1525. If the year-end interest rate is used, the test year interest expense on
the Pollution Control Bonds would be reduced in the amount of $3 083,000. Id.
In rebuttal testimony, Idaho Power witness Gribble noted that the American Falls
bonds interest expense "is based on a variable interest rate with the interest rate resetting on a
weekly basis.Tr. at 2756. If the bond interest expense is based on the latest variable rate of
2.35% on January 20, 2004, it would place "the Company at risk of not recovering its actual
American Falls interest expense in a rising interest rate environment." Tr. at 2756-57. Although
Idaho Power continued to advocate for a ten-year average rate, Mr. Gribble stated "the Company
could support a five-year average methodology for determining the American Falls interest rate
known and measurable expense adjustment." Tr. at 2757. Idaho Power noted that in its last rate
case, the Commission accepted a five-year historical average for the Company s auction of
preferred stock instead of using the actual rate as of the end of the test year. Tr. at 2753.
Based upon the record, the Commission finds it fair and reasonable to use a five- year
historical average as the appropriate measure of variable interest expense for the test year. This
BMA average rate of 2.48% reflects that the interest rate varies while providing an averaging to
reflect the lower rates currently and in the past few years. This methodology provides a
$225 308 adjustment to test year interest in the falling water expense for the American Falls
Bonds. Using the five-year average as the base variable pollution control rate results in the
Pollution Control Bonds at 4.24%, with an authorized debt return at 5.769% for use in the overall
rate ofreturn. The Commission s acceptance of this methodology in this case, however, does not
constitute a guaranteed acceptance of this variable rate bond methodology in future rate cases as
requested by Idaho Power in its rebuttal testimony. Tr. at 2756.
4. Operating Payroll Adjustments.
Idaho Power proposed two adjustments to test year payroll expenses based on
projections the Company made for those expenses during the second half of the test year. Staff
testified the Company s payroll adjustments are appropriate, but should be based on actual
ORDER NO. 29505
expenses for the test year rather than on projections. Staff initially testified that if actual costs
are used, the two test year payroll expenses are reduced by $2 052 654 and $116 675.
The flfSt payroll adjustment Idaho Power proposed was for an increase in its base
salary expense, and resulted from the Company s projection that its annual salary expense would
increase by $2 913 244 during the test year. Staff reviewed the actual December 2003 payroll
amount and discovered the actual adjustment should be $2 052 654 lower than the Company
projected. Tr. at 1429. Staff recommended the actual figure be used, which would increase test
year salary expenses by $860 590 rather than the $2.9 million amount projected by Idaho Power.
The second payroll adjustment recommended by Staff follows from the first. Idaho
Power estimated the annual increase in its base payroll expense, referred to as a Salary Structure
Adjustment (SSA), based on a historical average annual increase of three percent. Because the
actual test year payroll was significantly lower than projected by the Company, the amount of
SSA adjustment will be lower. Staff initially recommended a reduction in the test year projected
payroll related to SSA of $116 675. Tr. at 1429. In supplemental testimony, however, Staff
witness Holm testified that neither the SSA amounts nor the incentive pay amounts (discussed in
the next section) will be paid by the Company for 2003. Tr. at 1456. Staff argued that
adjustments to the test year, for what the Company had said were known and measurable
changes, should not be allowed. Staff contends, because the Company will not pay the SSA until
2005, if at all, the amount Idaho Power proposed to be included in the test year for SSA is not
known or measurable. Staff recommended removing the entire adjustment to the test year for
SSA pay in the amount of$2 241 595. Tr. at 1456.
In rebuttal testimony, the Company agreed with the reductions in test year payroll
expenses of $2 052 264 and $116 675, based on actual payroll figures for the test year. Tr.
3180-81. Company witness Minor also acknowledged that the SSA salary increase was not
actually paid for 2003, and testified that current financial conditions "effectively deferred any
upward Salary Structure Adjustment until such time that the Company s financial situation
improves." Tr. at 2828.
As agreed by Staff and the Company, we find it reasonable to use the actual test year
payroll expense numbers to calculate the revenue requirement and thus reduce payroll expense
by $2 052 264.The Salary Structure Adjustment is based on year-end payroll and other
ORDER NO. 29505
unknown items such as earnings. It is not possible, therefore, to accurately calculate an SSA
adjustment before January 2005. The Company acknowledged that current fmancial conditions
, and we believe they ought to, dictate a tightening of the Company s belt so to speak with
regard to salaries. Because of this and the fact that the SSA adjustment is neither known nor
measurable at this time, the Commission accordingly will remove $2 241 595 from test year
expenses for the SSA.
5. Incentive Pay Operating Expense Adjustment
Idaho Power made an adjustment to test year payroll expenses to add a component
for its incentive compensation program. The Company originally projected a test year expense
of $5 114 821, but reduced the amount of incentive pay to $4 837 358 based on actual year-end
payroll figures. Tr. at 1414. Staff recommended that none of the incentive pay costs be included
in the test year. Tr. at 1414-29. Staff witness Holm initially objected to this test year adjustment
because "Idaho Power compensates its employees adequately without the incentive pay," and
because the incentive pay plan is tied to IDACORP's earning goals, rather than to Idaho Power
perfonnance. Tr. at 1427. He argued that "ratepayers do not directly benefit when IDACORP'
earning goals are achieved or exceeded and thus should not fund this program.Id
supplemental direct testimony, Mr. Holm identified an additional reason for disallowing a test
year expense adjustment for the incentive pay plan. Idaho Power provided to Staff a copy of a
Company newsletter that revealed no incentive pay would be paid for 2003, and thus the earliest
that incentive pay would be paid by the Company would be January 2005, if at all. Tr. at 1456.
Staff thus contended it was not possible or appropriate to make a "known and measurable
adjustment to the test year for incentive pay. Id.
Micron also testified that the incentive pay adjustment to the test year expenses
should not be allowed. Micron witness Peseau testified that the proposed incentive pay "is not
truly a known change because the incentive will presumably not be paid if the savings don
actually materialize. Furthermore, this type of incentive pay makes no sense unless it results in
savings that exceed the incentive pay, in which case there is no need to further reward the
Company for a program that will be essentially self funding." Ir. a 2432.
In rebuttal testimony, Idaho Power witness Minor explained the goal of the incentive
pay program is "to focus utility employees' behavior on achieving operational excellence making
a difference where they can through excellence in customer service, working efficiently, safely,
ORDER NO. 29505
and controlling utility operations and maintenance expenses.Tr. at 2827. Mr. Minor also
acknowledged that
, "
in 2003, no incentive payout was made to Company employees.Tr. at
2819.
The Commission finds that the Company-proposed adjustment for the incentive pay
program should not be included in the 2003 test year. First, Idaho Power adequately
compensates its employees with the base salaries and additional benefits it provides, such as
health benefits, pension plan contributions, and paid vacation time and holidays. In addition
because the incentive pay fluctuates, may not be paid at all in the future and was not paid in the
test year, it would not be appropriate to include it as a known and measurable adjustment to the
test year. Tr. at 2837-38. Finally, there is validity in Micron s argument that incentive pay
should be self-funding. When earnings goals are achieved, it is not necessary to offer a financial
reward for doing one s job with funds collected in rates when employees can share the gains with
shareholders. Accordingly, the Commission rejects the Company s adjustment to the test year
for incentive pay in the amount of $4 837 358.
The Commission is also concerned about the public perception of IDA CORP benefits
and employee bonuses when rates are increasing. We received considerable comment and
testimony from customers expressing their frustration that Idaho Power s employees received
bonuses and incentive pay during periods when customers had to "tighten their belts" to pay
unprecedented high electric rates. It is difficult to explain why Idaho Power expected its
ratepayers to pay extraordinary power supply costs while it simultaneously rewarded employees
with bonuses. Although the Company maintained it was the performance of IDACORP that
resulted in those bonuses, this disparity is evidence that Idaho Power s incentive plan is not
properly aligned with the interests of its customers. With no incentive pay allowed in this case
customer rates do not include this controversial compensation.
6. Amortization of Unusual Cases.
Idaho Power included in test year expenses fees it paid to consultants in three
different cases that occurred during the test year, including this general rate case. The fees paid
for experts to participate in the three cases totaled $99 720. Tr. at 1443. Staff witness Holm
argued that the cases are unusual "in that they are infrequent and will not occur during a typical
year." Tr. at 1444. Mr. Holm further contended the costs should not be reflected in a single year
in their entirety as an annual cost, and proposed "to amortize the expenses associated with these
ORDER NO. 29505 '
cases over five years instead of expensing them all at once.Id. If the consultant fees are
amortized over five years, test year expenses as proposed by Idaho Power would be reduced by
$79 776. Id. In rebuttal testimony, Idaho Power witness Gale stated that the Company retains
outside expert services every year, and that "these three instances are indicative of the usual level
of expense, not a one-time phenomenon and should be recovered fully in the test year." Tr.
3160.
The Commission finds these outside consultant fees to be legitimate busines~
expenses but atypical ones that do not carry on from one year to the next. Therefore, we find
that these expenses should be recovered over a five-year period rather than in each year going
forward. Test year expenses shall be reduced in the amount of $79 776. Fees that are typical
remain in the test year expenses at the full amount.
7. Adjustments to Legal Expenses.
Staff recommended litigation expenses arising from the Company s participation in
two cases referred to in testimony as the "California Refund Case" and the "Pacific Northwest
Refund Case" not be allowed in test year expenses. The Refund Cases were brought by
wholesale energy purchasers claiming that energy traders improperly manipulated spot market
prices during the 2000-2001 energy debacle. Staff argued that it was IDACORP Energy
participation as an energy trader that created the litigation expenses incurred by Idaho Power
and thus those expenses should be born entirely by IDACORP or IDACORP Energy. Tr. at
1520-21.
In rebuttal testimony, Idaho Power witness Gale testified the Refund Case expenses
were incurred solely to ensure that Idaho Power would not be precluded from receiving refunds
that might ultimately be ordered by the FERC." Tr. at 3147-49. Idaho Power contends its legal
fees were paid to a law firm to represent its interests, and that IDA CORP Energy hired a separate
law fmn to protect its interests. Tr. at 3149. Mr. Gale stated it is not seeking reimbursement of
any legal expenses to defend IDA CORP Energy, and that "the legal expenses in question were
incurred to preserve potential benefits for utility customers." Tr. at 3151.
We believe the Company prudently acted to ensure that its ratepayers would be able
to receive any potential refunds that may have resulted in these cases. That said, there is no
reason to believe the entire amount of defending against these cases should be included in the
test year as if the same amount will be incurred each year into the future. Because this litigation
ORDER NO. 29505
was unusual with its relationship to trading activities, the Commission fmds it appropriate to
reduce test year litigation expenses by the entire amount of $352 544. Although these particular
legal fees are not recoverable, the majority of legal costs incurred in 2003 remain in the test year
expenses for recovery.
Company witness Gale testified "if the Company knows it will be unable to recover
its legal expenses incurred to pursue these refunds, it would be logical for the Company to cease
actively participating in the cases and thereby reduce its exposure to unrecoverable legal
expenses." Tr. at 3151. The Commission assumes that the Company will act in good faith to
protect the interests of its ratepayers and shareholders, both of whom have a stake in proceedings
involving power costs due to the PCA's 90/10 sharing mechanism. We would be extremely
concerned if Idaho Power failed to effectively advocate for ratepayers who have no other
representation in such proceedings. Denial of legal expenses for the Refund Cases in this Order
in no way minimizes their importance; it merely recognizes that the regulatory accounting
system does not permit inclusion of unusual expenses in a test year for ratemaking purposes.
8. Adjustments to Property and Liability Insurance Expenses.
Idaho Power proposed two increases in the test year expenses for property and
liability insurance. Several insurance policies will expire during 2004, and the Company
anticipates renewing the policies at higher premiums. Idaho Power proposes to increase test year
expenses by the amount of additional insurance costs it claims are known and measurable to
occur in 2004. The second adjustment the Company proposes is to annualize the new insurance
costs so the total increased amount is collected each year in the future. Tr. at 528. Thus, Idaho
Power proposed to add insurance costs for 2004 that are $364 014 higher than actually occurred
in the test year, and then add an additional $384 586 to annualize the higher costs for recovery in
future years. Id.; Tr. at 559.
Staff recommended removal of both insurance expense adjustments included in the
test year by Idaho Power. Staff witness Holm argued that the amount of increase is not known or
measurable
, "
it is simply an estimate of the new policy costs that may go into effect sometime
during 2004.Tr. at 1412. According to Staff, Idaho Power stated that insurance coverage
amounts might change; some may increase while others decrease. Id. Mr. Holm recommended
removing Idaho Power s expense adjustment for higher insurance costs it anticipates v.ill occur
in 2004, because "the costs of the policies are not known at this time; they are simply estimated.
ORDER NO. 29505
Id. For the same reason, Staff recommended the annualizing adjustment also not be allowed. Tr.
at 1414.
The Commission finds that the Company-proposed increases to test year expenses for
additional insurance costs are speculative and not based on known and measurable charges.
Accordingly, the Commission will remove from the test year expenseS the $748,600 Idaho
Power added for increased property and liability insurance.
9. Adjustments to Management Expenses.
Staff presented Revised Exhibit 111 showing a recommended reduction of $63 291
to test year expenses for management personnel costs. Most of the expenses Staff would remove
were for travel and expenses for Edison Electric Institute (EEl) conferences. Tr. at 1519. Other
expenses included costs for meetings with politicians and lobbyists, green fees at golf courses
liquor store purchases, wine purchases, and excessive meal expenses. Id. Company witness
Gale conceded that Staff's audit uncovered some items that were inappropriately included in test
year expenses, but argued "the bulk of these expenses are legitimate.Tr. at 3146-47. Idaho
Power stated its membership in EEl is a bona fide business expense of the Company, and that
Idaho Power must be able to communicate with legislators and lobbyists "concerning important
matters impacting both the Company and its customers." Tr. at 3147.
The Commission finds that some of the services. EEl offers its members, such as
education on industry issues and management training, are legitimate business-related expenses.
Therefore, the Commission finds it just and reasonable to adopt only one-third of Staffs
proposed expense reduction for inappropriate expenditures. Weare convinced this level of
adjustment will ensure that ratepayers are funding only those activities that are legitimate.
Accordingly, test year expenses relating to management expenses will be reduced by $21 097.
10. Intervenor Funding Amortization.
Idaho Power included in the test year operating expenses the amounts it was required
to pay intervenors in two separate cases in 2003. Intervenor awards were granted to the Land
and Water Fund in Case No. IPC-01-16 in the amount of $4 956, and to the Irrigators in Case
No. IPC-O3-5 in the amount of $5 335. Staff witness Holm recoIIlIIlended these amounts be
amortized and collected over five years, rather than allowing the Company to recover them "year
after year until the next rate case.Tr. at 1445. As an alternative to a five-year amortization,
Staff suggested the PCA could be used to allow a one-time recovery of the intervenor amounts.
ORDER NO. 29505
Id. In rebuttal testimony, Company witness Gale suggested the PCA "is the perfect tool to
recover intervenor funding amounts." Tr. at 3160.
Both Staff and the Company agreed that intervenor funding costs should be
recovered just once and suggested different methods to achieve that end. We find it reasonable
to place $10 291 of intervenor funding amounts in the 2005-2006 PCA for recovery in rates.
Although we try to avoid unduly complicating the PCA, the Commission finds that PCA
recovery of this small monetary amount will: (1) direct the costs to the customer classes that
benefited from the intervention, (2) ensure that the amounts will only be recovered once, and (3)
minimize interest accumulating until the amounts are fully recovered.
11. Additional Income Tax Assessment.
Idaho Power requested $2.9 million for additional tax payments made for the 1998-
2000 audit cycle. Rather than collect this three-year amount each year in test year expenses,
Staff supported use of a three-year average of the additional tax payments. This would decrease
960 529 from the federal tax test year expense and add $55 846 to the state tax test year
expense. Tr. at 1440-42.
In its rebuttal testimony, Idaho Power noted that the Commission previously ordered
that any income tax deficiencies actually paid during the test year should be included in the
regulatory tax expense as set forth in Order No. 17499. Tr. at 2947-48. Moreover, the Company
argued this was fair because it did not include deficiencies from previous audit cycles. Tr. at
2915.
The Company is correct that more than 20 years ago the Commission stated it
would allow the Company to recover as a tax expense any contingency actually paid in the year
that it is paid." Order No. 17499 at 24. This language regarding the method of treatment was
clearly not optimal. Ratepayers should pay the amount of the tax deficiencies once, not the
entire three-year deficiency every single year. If the Commission implemented the Company
proposal, ratepayers would pay more than the actual tax expense. That would create an illogical
and unreasonable ratemaking result. Because the Company s three-year audit cycle allows for
the possibility of tax deficiencies every third year, the Commission finds it reasonable to average
the additional tax payments over a three-year period. This symmetry between tax expense and
collection in rates will allow the Company to recover its legitimate tax costs while minimizing
the potential for over-collection.
ORDER NO. 29505
12. Low Income WeatheriZiltion Assistance.
In its Application, Idaho Power s expenses included low-income weatherization
assistance (LIW A) payments to Community Action Partnership (CAP) agencies at their current
level of approximately $0.2 million per year. LIW A's services enable low-income families to
permanently reduce their energy bills by making their homes more energy efficient. Three major
LIW A funding sources for the CAP agencies are the U. S. Department of Energy (DOE), the
S. Department of Health and Human Services, and Idaho Power. Tr. at 2105. The Bonneville
Power Administration also contributes funds to the CAP agencies for LIW A, both directly and
indirectly through utilities. in its Conservation and Renewable Discount program, as do
PacifiCorp and Avista Utilities. Thus, each CAP agency providing weatherization services in
Idaho receives funding for LIW A from three to five agencies and utilities.
The Community Action Partnership Association of Idaho (CAP AI), represented by
Ken Robinette and Teri Ottens, requested that Idaho Power s funding level be increased to $1.2
million per year from the current level. Tr. at 2124. CAPAI said $1.2 million would fully fund
440 homes per year. Id. The Northwest Energy Coalition, represented by Nancy Hirsch, also
offered evidence and arguments supporting increased LIW A funding. Tr. at 2186-94.
CAPAI also requested that Idaho Power s contract allow the CAP agencies to submit
their reimbursement requests to Idaho Power for the full amount of cost-effective work
completed as determined by DOE's energy audit. Tr. at 2129. Currently CAP agencies can
request only 50% of the cost of weatherizing a house from Idaho Power. Tr. at 2124, 3097.
CAP AI argued that removing the 50% matching requirement would allow the CAP agencies to
...
maximize their leveraging of federal and private (utility) funds." Tr. at 2129.
Finally, CAP AI requested that Idaho Power s administrative cost allowance for CAP
agencies be increased from $75 per house weatherized as set in 1989 to $150 per house. Tr. at
2130. CAPAI said its projected administrative costs in 1998 were $146 per house. Tr. at 2122.
On rebuttal, Idaho Power opposed funding the full costs of the weatherization jobs
and argued that the 50% matching requirement allows Idaho Power opportunity to assure that its
customers' funds are used effectively. Tr. at 3097-99. The Company said it was willing to
consider: (1) increasing the CAPs' administrative cost allowance , (2) reducing the savings to
investment ratio (SIR) from 1.1 to 1.0, and (3) investigating its LIW A funding level. The
Company indicated, however, that the rate case proceeding was not the appropriate place to
ORDER NO. 29505
consider these changes and instead. suggested that CAP AI's proposals be addressed outside the
rate case during the preparation of next year s contracts and/or through the Company s Energy
Efficiency Advisory Group. Tr. at 3097-3101.
The Commission believes that funds devoted to LIW A are a wise investment that
will benefit all Idaho Power ratepayers not just those who experience reduced power bills. Tr. at
1194, 2188-89. Increased LIW A funding can provide significant benefits in terms of lowering
uncollectables and creating permanent load reduction. The record reflects that in past years
LIWA has run out of funds mid-year in its efforts to achieve these ends. Tr. at 2124.
The Commission finds it just and reasonable to increase Idaho Power s annually
expensed LIW A payments to CAP agencies by $1 million to approximately $1.2 million for each
of the next three years, effective coincident with the rate increases authorized by this Order. The
approximately $1.2 million annually shall include CAP agency administrative costs, but exclude
any funds that Idaho Power may pass through to LlW A from other sources such as BP A. These
dollars are to be booked and tracked in a separate balancing sub-account and paid directly to
LlW A's administering agencies as projects are completed. Any unpaid funds shall carry over
and be available in the next year. Furthermore, these funds are to be used only within Idaho
Power s service territory and cannot be used to divert funds that otherwise would have been used
within Idaho Power s territory. To this end, CAP agencies shall administer these funds using the
historical allocation of LlW A funds as a basis to demonstrate that these funds were not used to
divert other resources. If the allocation of other funding sources changes compared to historical
allocations, we expect appropriate explanations will be included in the CAP AI's reports to Idaho
Power and that Idaho Power will include these explanations in its reports to the Commission.
We also find that it is reasonable to increase the CAP administrative costs and
suggest that $125 might be the appropriate amount going forward based on the 52% consumer
price index increase since 1989. We believe this issue as well as whether the CAP agencies
should be allowed to submit reimbursements up to the full cost of weatherizing a home, whether
the SIR should remain at 1.1 or revert back to 1.0, and other program design changes should be
negotiated between Idaho Power and CAPAI. Furthermore, we believe Idaho Power s proposal
to have its EEAG review these issues is a valid one. We expect Idaho Power to file a report with
the Commission at the conclusion of this process providing details and explanations of its LIW A
program changes.
ORDER NO. 29505
In addition., Idaho Power shall be required to file an annual LIW A report with the
Commission. This report shall be separate from its annual demand side management (DSM)
report, although at least a synopsis of the LIW A report should be included in the DSM report.
The LIW A report should include, but is not necessarily limited to: the number of homes
weatherized by county, a projection of homes to be served in the future, the cost per home
served, a comparison of administrative costs to funds actually spent on homes weatherized, some
detail of weatherization measures installed, associated energy savings, and overall cost-
effectiveness. Idaho Power shall notify the Co~ssion within 60 days of this Order s issuance
of an appropriate date to file its annual report to provide the best available data. To continue
receiving these funds beyond June 1 , 2007, CAP AI must file an application to extend LIW A
funding in early 2007. Depending upon the results of the annual reports and the three-year
review in 2007, the Commission reserves the right to discontinue the LIW A fundir;lg authorized
by this Order.
13. Income Tax Expense.
Idaho, Power requested the Commission grant an effective tax rate of 32.795% for
federal and 5.9% for state taxes. Tr. at 580. However, Staff argued it was more appropriate to
average the federal and state income tax rates over five years, producing a 25.24% federal and
62% state tax rate for ratemaking purposes. Tr. at 1438. According to Staff, its proposal
recognizes the higher tax expense ratepayers will pay in future years when the tax timing turns
around. The Company chose to use a federal tax methodology where it can expense costs that
were formerly capitalized. In addition, Idaho Power used the flow-through method for the tax
change so ratepayers did not receive any benefit at the time the change was made. Tr. at 1430-
, 1471. This methodology change produced an immediate one-time tax refund or windfall for
Idaho Power in 2002 of approximately $41 million. In exchange for that immediate tax refund,
taxable income will increase over the remaining lives of the assets as repayment of the timing
difference. Tr. at 1436. Staff's adjustment would also reduce deferred taxes by $352 405 and
decrease the gross-up factor from 1.642 to 1.446. Tr. at 1439-40.
On rebuttal, Idaho Power alleged that Staff is trying to take advantage of Idaho
Power s abnormally low effective tax rate in 2002 that resulted from a non-recurring deduction
for an accounting method change. Tr. at 2941. Moreover, the Company believes Staffs
adjustment would violate the normalization requirement of the IRS Code and constitutes
ORDER NO. 29505
retroactive ratemaking. Staff argued that its proposal would do neither of these things because
its proposed five-year average would be applied prospectively to approximate the future effects
of the tax methodology change and would be used only for ratemaking purposes. Staff Post-
Hearing Brief at 8.
As we see it, in 2002 the U.S. Treasury essentially made a loan in excess of $41
million to Idaho Power that must be repaid in the form of higher future taxes. Had this been an
outright gift to Idaho Power requiring no future obligation by ratepayers, this Commission could
find it reasonable to adopt the Company s income tax arguments. Because this money was
neither a gift nor a grant of funds, ratepayers are in the worst of all positions because they: (1)
did not share the tax (loan) proceeds Idaho Power s shareholders received in 2002, (2) will have
to repay more than $41 million in higher tax expense in future years, and (3) could be subject to
a tax deficiency payment if the IRS determines that Idaho Power did not properly file the 2001
tax return that resulted from the tax methodology change (loan). This unfair outcome constitutes
improper ratemaking without an adjustment to offset the higher tax expense ratepayers will pay
in the future. Consequently, we adopt Staff's recommendation for a five-year average for the
income tax test year expense to account for the increased taxes ratepayers will pay in future
years. Although Idaho Power may have interpreted Staff's adjustment as seizing out-of-period
revenues or as punishment for choosing the windfall over normalizing the methodology change
this adjustment merely achieves a neutral economic impact for Idaho Power and its ratepayers
over time.
The Company has argued that a five-year average tax expense would result in a
normalization violation. A normalization violation exists when tax benefits are flowed to
ratepayers faster than the IRS allows. Company witness MacMahon testified, "the normalization
rules require a legal minimum of tax expense to be provided in a regulatory proceeding in order
to enjoy the benefits of accelerated tax depreciation and this legally required minimum has not
been met by Staffs methodology." Tr. at 1920-21. The Commission has no desire to run afoul
of IRS regulations and jeopardize the Company s use of accelerated depreciation. We do not
believe a normalization violation will occur in this case where only the test year taxes are
changed because tax benefits are not being passed through to ratepayers faster than IRS
regulations allow. The full amount could have been flowed through to ratepayers in 2002 with
the flow-through method. Passing it through now to customers for ratemaking purposes using a
ORDER NO. 29505
five-year average is slower than allowed, not faster. We also note that Idaho Power could have
avoided this issue by normalizing the tax methodology change rather than flowing it through in a
single year.
Idaho Power argues that it would be retroactive ratemaking to take into account
previous extraordinary revenues or expenses that will not reoccur. Tr. at 2941-42. Because the
tax methodology change has essentially caused the taxes paid from 1987-2000 to "reoccur" such
that these amounts will have to be repaid in the future, our decision to use the five-year average
to approximate this amount does not constitute retroactive ratemaking. This adjustment
anticipates and reasonably attempts to rectify a future anomaly caused by the Company
decision. We are looking forward, not back. The five-year average, a methodology the
Company has advocated for setting variable interest rates, is a well-established proxy that
establishes tax expense using the past as an indicator of the future. Moreover, the five-year
average will be re-evaluated when the Company files its next general rate case expected in the
next "two to three years." Tr. at 3193.
Deferred taxes are created by timing differences that result when the Company takes
tax benefits early that will have to be paid back later. Although Idaho Power claimed that Staffs
tax proposal would decrease deferred taxes by $53 million in rate base, the record does not
disclose how that number was calculated. Tr. at 2917. Although we recognize that the deferred
tax amount to be adjusted could be higher than that proposed by Staff, there was not adequate
information in the record to calculate a different number. Using the best information provided
this case, we believe it is just and reasonable to use Staff's deferred tax number and reduce
deferred taxes by $352 405.
The gross-up factor is used to calculate income taxes on the projected revenue
deficiency that results when newly authorized earnings exceed actual earnings. Because the
gross-up multiplier impacts future earnings rather than those in the test year, we fmd it
reasonable to use the Company s proposed 1.642 gross-up factor to avoid under-recovery of tax
expense associated with incremental increased revenue resulting from this case.
14. Summary of Adjustments to Rate Base and Test Year Revenues and Expenses.
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable total system operating expenses for the 2003 test year in
the amount of$515 637 445 , and total operating revenues in the amount of$618 503 239. After
ORDER NO. 29505
all adjustments, we find a 2003 total system rate base amount of $1 643 706 370 to be just and
reasonable. The Idaho jurisdiction rate base is $1 519,924 799; Idaho operating expenses total
$481 521 037, and Idaho operating revenues total $578 752 380 for the 2003 test year.
Appendix 1 to this Order summarizes the Commission s findings on rate base and operating
results for the test year.
CAPITAL STRUCTURE AND RATE OF RETURN
1. Capital Structure.
In its initial filing, Idaho Power estimated year-end 2003 balances for its capital
structure of long-term debt, preferred stock and common equity for use in determining a return
on rate base and overall rate of return, but recommended the Commission update the capital
structure to reflect an actual year-end 2003 capital structure. Tr. at 474. Staff used the
December 31, 2003 equity infusion to adjust the November 30, 2003 capital structure
recommending the Commission adopt a capital structure consisting of 51.38% long-term debt,
99% preferred stock, and 45.63% common equity. Tr. at 1826. Idaho Power in rebuttal
testimony provided the actual year-end capital structure as 51.060% long-term debt, 2.969%
preferred stock, and 45.971 % common equity. Tr. at 2750.
The Commission finds Idaho Power s actual capital structure at December 31 , 2003
as stated by the Company, to be appropriate for calculating the Company s overall rate of return.
Our decision to use the actual year-end capital structure to determine the overall rate of return is
consistent with Order No. 25880 issued in Idaho Power s last rate case proceeding in Case No.
IPC-94-
2. Cost of Debt
Idaho Power testified that its embedded cost of debt is 5.983%. Tr. at 475. Staff
determined the Company s cost of debt to be 5.63% by adjusting the debt rate used by Idaho
Power to reflect maturity of a fixed 8% interest mortgage bond and its replacement with 6%
interest bonds. Tr. at 1826-27. Micron also restated Idaho Power s cost of debt in light of the
refinancing of the mortgage bond, using a 5.7% interest rate, to reach a 5.839% cost of debt. Tr.
at 2456. Staffs determination of the cost of debt also reflected a lower interest rate for the
Pollution Control Bonds, which is a variable rate bond. Tr. at 1827. Staff used the 2003 year-
end rate for the variable rate bonds, while Idaho Power used a ten-year average to establish the
interest rate for variable rate debt. Tr. at 2754-56. Company witness Dennis Gribble testified
ORDER NO. 29505
however, that the Company could support a five-year average to determine the interest rate for
the variable rate bonds so long as that methodology is applied consistently in future rate cases.
Tr. at 2756-57. During the hearing, Idaho Power also indicated it was appropriate to use the
actual 5.5% interest rate now in place on the first mortgage bonds refinanced March 26, 2004 to
calculate its cost of debt. Tr. at 2759-61.
The Commission finds the appropriate calculation of Idaho Power s cost of debt to be
769%. This figure includes the refmancing of the 8% Series First Mortgage Bonds in March
2004 at 5.5% with an all in cost of 5.6%. With regard to variable rate bonds, the Commission
finds it reasonable to use a five-year average of the Bond Market Association (BMA) Municipal
Swap Index in this case as the most appropriate measure of the variable rate for the Pollution
Control Revenue Bonds outstanding. This BMA rate reflects that the interest rate varies while
providing an averaging to reflect the lower rates currently and in the past few years. The use of
this methodology is reasonable based on the evidence in this record. It does not constitute a
guaranteed acceptance of this variable rate bond methodology in future rate cases as requested by
Idaho Power in its rebuttal testimony. Tr. at 2756.
3. Cost of Preferred Stock.
Idaho Power testified its embedded cost of preferred stock used in the forecasted
2003 capital structure is 6.534%. Tr. at 482. Staff verified the Company s rate and used it in
Staff's capital structure recommendation. Tr. at 1827. Accordingly, the Commission adopts
534% as the appropriate cost rate for preferred stock in determining the Company s capital
structure and rate of return.
4. Cost of Common Equity CapitaL
We turn next to a determination of the appropriate cost of common equity capital.
The cost of common equity is primarily an attempt to quantify a rate of return required by
investors for that particular investment. Idaho Power s witnesses testified that the possible range
for its cost of common equity is 10.6% to 11., and that 11.2% is "the minimum required rate
of return considering the Company s overall management efforts throughout these last ten
years.Tr. at 449 and 956. Staff witness Carlock concluded "the fair and reasonable cost of
common equity capital. . . for Idaho Power is in the range of 9.5% - 10.5%." Tr. at 1827. Staff
used a mid-point rate of 10% in calculating the overall rate of return. Id. Finally, Micron
witness Peseau determined the appropriate range for Idaho Power s cost of common equity to be
ORDER NO. 29505
8.4% to 10., and recommended the midpoint rate of 9.5%. Tr. at 2454. Micron also pointed
out that the Commission determined the appropriate cost of common equity for Idaho Power to
be 11 % in the Company s last rate case. Noting "investors' expected earnings on both bonds and
stocks have dropped dramatically since 1994 " Dr. Peseau testified "Idaho Power s request for an
11.2% return on equity, some 20 basis points higher than the Commission authorized in 1995, is
unreasonable on its face." Tr. at 2454-55.
The Commission in its last Idaho Power rate case, Order No. 25880, summarized the
different methodologies used to analyze and ascertain a fair rate of return on common equity
capital. The Commission has relied primarily on the discounted cash flow method (DCF) and
the comparable earnings method in previous rate cases, and we do so again in this case. Order
No. 25880 at 21. A third methodology is a risk premium analysis, which begins with a low risk
investment, such as government or utility bonds, and adds a premium based on the relative risk
associated with a utility's stock. Id. The capital asset pricing model (CAPM) measures risk
using the beta coefficient. The return on equity is measured in relation to the market as a whole.
As markets change, new concerns develop in various fmancial circles related to the calculations
used to determine the cost of equity. One such concern continues to be the measurement and
proper use of Beta. This Commission has not focused on Beta or CAPM for determining the cost
of equity; therefore any new concerns are not at issue in this case for this Order and will not be
specifically addressed. We have evaluated the concerns addressed by the parties in this case and
heard from the financial community associated with the determination of the grov.1h rates and
the use of accounting numbers in the era of accounting scandals. Weare confident that by
evaluating all the methods presented in this case and using each as a check on the other when
setting the allowed rate of return, we have not focused our determination such that these
concerns are an issue. The growth rate has been properly matched to the dividend yield in the
DCF method and the comparable earnings using accounting data is being used as a check for
reasonableness. The goal of each methodology is to ascertain a rate of return on common equity
at a point sufficiently attractive that investors will consider purchasing common equity shares in
the company. However
, "
the methods to evaluate a common equity rate of return are imperfect
predictors of future performance " and "the rate of return on equity specified by a regulatory
agency is but one factor considered by prudent investors when evaluating a utility's stock."
Order No. 25880 at 20-21.
ORDER NO. 29505
Idaho Power s cost of capital witness Dr. William Avera described the DCF model
he used to assess the Company s cost of equity. Essentially, the DCF model estimates "the cash
flows investors expect to receive from the stock in the way of future dividends and capital gains"
and, given the current price of the stock, calculates the investors' required rate of return. Tr. at
992. Put another way, "the cash flows that investors expect from a stock are estimated, and
given its current market price, we can 'back-into' the discount rate, or cost of equity, that
investors presumptively used in bidding the stock to that price.ld Dr. Avera did not apply the
DCF model directly to Idaho Power because as a wholly owned subsidiary of IDACORP it does
not have publicly traded stock, and because the Company last year cut its common dividend
payment. Tr. at 995. Instead, Avera applied the DCF analysis to a "reference group of other
electric utilities composed of those companies included by Value Line in their Electric Utilities
(West) Industry group.Tr. at 995-97. Avera eliminated six companies from the proxy group,
leaving eight utilities "engaged in electric utility operations in the western region of the U.s.
Tr. at 997.
Avera s fJIst step in implementing the DCF model was to determine the expected
dividend yield for the companies in the proxy group. That is accomplished by dividing each
company s expected dividend by the company s stock price. Tr. at 1004-05. Avera concluded
the dividend yields for the eight companies range from 3.2% to 6%, with the average being
4.4%. Tr. at 1005. The next step in the DCF methodology is to estimate investors' long-term
growth expectations for the company being evaluated. Tr. at 1004. Avera provided growth
expectations for the proxy group published by four different security analysts, showing growth
rates of2.7% to 5.5%. Tr. at 1011. Avera also looked at historical growth in earnings, showing
growth rates of 7.3% during the last 10 years, and 8.1 % during the last 5 years. Tr. at 1012.
Finally, Avera looked at the relationships between retained earnings and earned rates of return as
an indication of the growth investors might expect from the reinvestment of earnings within a
firm, the review of which yielded an average expected growth rate of 4.7% for the proxy group.
Tr. at 1013-15. Avera concluded "investors currently expect growth on the order of 5.0 to 7.
percent for the average firm in the electric utility proxy group." Tr. at 1015.
The final step in the DCF model is to combine the dividend yield and the estimated
growth rate to arrive at an estimate of the company s cost of equity. Tr. at 1005. Avera added
ORDER NO. 29505
his 4.4% average dividend yield with the 6% midpoint of his expected growth range to determine
a DCF cost of equity for the proxy group of 10.4%. Tr. at 1015.
Avera also used a risk premium analysis to evaluate Idaho Power s cost of equity.
Because the Commission gives more weight to the DCF analysis, we will not attempt to explain
in this order the application of the risk premium analysis. Avera concluded the yield on public
utility bonds in August 2003 implied a current equity risk premium of 4.39% for electric utilities.
Adding this equity risk premium to the August 2003 yield on single-A public utility bonds of
79 percent implies a current cost of equity for Idaho Power of approximately 11.2 percent."
Tr. at 1023-24. Avera used an alternate method to determine the risk premium to estimate a
current cost of equity of approximately 11.7%. Tr. at 1027. Avera concluded his DCF model
and risk premium analyses produced a range for Idaho Power s cost of equity of 10.4% to
11., to which he then added 20 basis points in flotation costs to increase his estimated range
for Idaho Power s cost of equity to 10.6% to 11.9%. Tr. at 1032. "Flotation costs" cover the
expenses of issuing common stock in the market.
Micron s cost of common equity witness was Dr. Dennis Peseau. Dr. Peseau
criticized Avera s analyses because they "suffer from stale capital market data," and testified that
changing capital markets have changed the inputs to all of Dr. Avera s analytical methods.
Tr. at 2438 and 2442. According to Dr. Peseau, "Dr. Avera developed his analyses using capital
market information from last summer, and both debt and equity markets have improved
enormously since that time." Tr. at 2444. If Dr. Avera s cost of equity analyses are replicated
using his methods "exactly with no changes other than updated numbers " according to Dr.
Peseau, Idaho Power s cost of equity is within a range of9.7% to 10.6%. Tr. at 2443.
Dr. Peseau also proposed specific corrections to Dr. Avera s risk premium and DCF
analyses. For example, Dr. Peseau noted that Dr. Avera used an average public utility bond yield
in part of his risk premium analysis, and the yield on a single A- rated bond in another part. Tr at
2444. Noting that "most Idaho Power debt instruments carry the A- rated credit standing," and
the "point of these exercises is to solve for Idaho Power s risk premium, not that of the average
utility," Dr. Peseau claimed "Dr. Avera s substitution biases his estimates upward.Id. Using
the same bond yield throughout the risk premium analysis reduces Dr. Avera s cost of equity
result from 11.2% to 10.59%. Tr. at 2445.
ORDER NO. 29505
Regarding Dr. Avera s DCF analysis, Dr. Peseau testified Dr. Avera s DCF
methodology is not unreasonable, but its implementation is flawed.Tr. at 2448. Dr. Peseau
claimed Dr. Avera s selection process for the proxy group of utility companies "high grades the
proxy group," and that a second problem "is that the group is so small that there is a serious risk
of sampling errors." Tr. at 2448-50. Dr. Peseau recommended adding back in to the group the
four dividend paying companies that Dr. Avera "arbitrarily removed," and rejecting altogether
Dr. Avera s five- and ten-year historical calculations he used to determine a yield component as
unreliable. Tr. at 2450-51. With the corrections Dr. Peseau recommended to Dr. Avera
analyses, Dr. Peseau produced cost of equity results for Idaho Power that range from 8.4 % to
10., with a midpoint of 9.5%. Tr. at 2453-54.
Tern Carlock, who used the DCF and Comparable Earnings methods to determine
the appropriate cost of equity, presented the Staff's evidence on Idaho Power s cost of equity.
Tr. at 1820. Applying the DCF model directly to IDACORP, and thus Idaho Power, rather than
to a proxy group of utility companies, Carlock determined a cost of equity range of 7.4% to
8%. Tr. at 1825. Carlock's Comparable Earnings analysis produced a cost of equity range for
Idaho Power of 10% to 11%. Tr. at 1827. Carlock concluded that "the fair and reasonable cost
of common equity capital. . . for Idaho Power is in the range of9.5% to 10.5%.
In his rebuttal testimony, Dr. Avera identified perceived weaknesses in Staff's cost of
equity analysis and responded to Dr. Peseau s criticisms of his cost of equity analyses. Dr.
Avera s primary criticism of Carlock's analysis is that
, "
because she restricted her DCF analysis
to a single company - IDACORP - Ms. Carlock's results are extremely susceptible to
measurement error and bias.Tr. p. 1063. Carlock explained on cross-examination that she
utilized the proxy utility group DCF analysis to verify the reasonableness of using IDACORP for
the primary DCF analysis. Tr. at 1836, 1851. She also clarified that flotation costs were
included in the dividend yield component of her DCF. Tr. at 1832-, 1835. Avera also
criticized Carlock for not applying the risk premium approach, stating that "no single method or
model should be relied upon to determine a utility's cost of equity because no single approach
can be regarded as wholly reliable." However, Dr. Avera failed to acknowledge that Carlock had
also perfonned a comparable earnings analysis. Tr. p. 1066-68.
Dr. Avera argued that Dr. Peseau did not do an independent analysis but merely
updated" the dividend yield in Avera s DCF model while ignoring the equation s growth rate.
ORDER NO. 29505
Tr. at 1076. Dr. Avera also criticized Dr. Peseau s remaining modifications as ignoring
historical trends in earnings growth in applying the DCF model, using alternative bond yields to
apply Dr. Avera s risk premium approaches, substituting a lower market return in the CAPM
and ignoring the flotation cost adjustment. ld. Finally, Dr. Avera denied that his risk premium
approaches had inconsistencies that biased the results upward. Tr. at 1081.
As part of our determination of the appropriate return on equity, the Commission will
consider information regarding the risk an investor may consider in deciding to purchase a utility
stock. That may include information regarding the efficient management of the utility. Each of
the cost of capital witnesses discussed risks associated with utilities in general, and Idaho Power
in particular, that investors may consider when deciding whether to purchase IDACORP stock.
For example, Idaho Power witnesses Dr. Avera and Gribble testified that investors
are likely to consider the impact of industry uncertainty stemming from western power market
crises, the Enron meltdown, the Midwest/northeast blackouts, counter party credit erosion
environmental pressures, and inflation on the required rates of return for utilities. Tr. at 451
965-79. They also believe Idaho Power is particularly susceptible to risks created by low
streamflows for hydroelectric generation, wholesale market volatility, hydroelectric relicensing,
and regulatory uncertainty. Tr. at 452-, 1039-44 2746-49.
Micron witness Dr. Peseau argued that Dr. Avera s observations are accurate enough
but present "too bleak a picture of the industry.Tr. at 2440. He explained that the
overwhelming majority of the Nation s electric utilities have weathered these disasters and are
now strengthening their core businesses in a nearly ideal economic environment. ld Although
problems and uncertainties still exist in the electric industry, these are not unique to electric
utilities. ld. Dr. Peseau also suggested that investors do not widely share Dr. Avera s "doom
and gloom" outlook for Idaho Power or the industry, particularly given that Idaho Power
shareholders received a rate of return in excess of 40% in the last year over the 2003 year when
including both price appreciation and dividend yield. Tr. at 2441.
Staff witness Carlock testified that competitive risks are limited for Idaho Power
because the demand for utility services is relatively stable as compared to unregulated or other
utility industries due to its low-cost power and customer mix. Tr. at 1822-23. As compared to
most other electric companies, Idaho Power s competitive risks are less because of its low-cost
source of power and relatively low retail rates. ld Ms. Carlock also believes that while the
ORDER NO. 29505
Company has less investment risk due to power supply cost recovery in the PCA mechanism,
IDACORP's main risks are primarily due to non-regulated operation.
The evidence in this case supports a rate of return on common equity for Idaho
Power ranging from 8.4% to 11.9%. We find Idaho Power s reasonable required rate of return
on common equity to be 10.25%. When this rate is placed in the calculation of the Company
cost of capital, the result is an overall rate of return of 7.852%. This overall return also reflects
the impact that low interest rates have on the cost of equity.
In authorizing a 10.25% return on common equity, this Commission acknowledges
its desire to maintain Idaho Power as a financially viable utility with credit ratings at or above
the current level. With the wind down of IDACORP Energy, IDACORP, and Idaho Power
specifically, are sheltered from many risks that impact other utilities. Idaho Power s annual PCA
mechanism continues to limit the risk of the Company. Idaho is not likely to have deregulation
risks like those experienced by other states and continues to have low power costs. The Idaho
Commission s authority over security issuances indirectly "ringfences" or limits the Company
financial and/or bankruptcy risk exposures. These factors may not eliminate Idaho Power
risks, but they minimize them. The overall impact of this Order supports plant investment,
provides a return on equity of 1 0.25% in a low interest rate environment, and improves Idaho
Power s revenue stream from the current level.
The use of this cost of common equity, together with the costs of debt, preferred
equity and capital structure previously found, yields the following overall return for rate base:
Component % of Capital Structure Cost Weighted Cost
Debt 51.060%769%946%
Preferred Equity 969%534%0.194%
Common Equity 45.971 %10.250%712%
TOTAL 100.000%852%
CALCULATION OF REVENUE DEFICIENCY
With the Idaho rate base, revenue requirement and return on common equity
established, the Commission determines the Idaho revenue requirement with the following
calculation:
ORDER NO. 29505
Rate Base
Rate of Return
Revenue Requirement
519 924 799
852
$119,344 495
Adjusted Net Operating Income
Income Deficiency
$103,918 528
$15 425 967
Incremental Tax Multiplier
Revenue Deficiency
Percent Increase Required
642
$25 329,438
23%
JURISDICTIONAL SEPARATIONS
Compared to previous Idaho Power rate cases, there is relatively little dispute in this
case regarding the Company s jurisdictional separations methodology. The jurisdictional
separations methodology, referred to as the 12 coincident peak (12 CP) methodology, is used to
allocate total electric system costs to the Idaho, Oregon or Federal Energy Regulatory
Commission (FERC) jurisdictions. The FERC jurisdiction is comprised of Idaho Power
wholesale sales of energy to other utilities. The Company used the same jurisdictional
separation methodology it has used for more than 25 years to allocate the Company s annual
expenses amon:g the jurisdictions it serves. Tr. at 567. Staff and some intervenors recommended
the Commission approve Idaho Power s jurisdictional separations methodology, and no party
objected to the Company s jurisdiction separations results.
On this record, the Commission fmds that the 12 CP methodology the Company used
to separate system costs between the Idaho, Oregon and FERC jurisdictions is reasonable and
appropriate. The 12 CP jurisdictional separations study results in an Idaho system revenue
requirement allocation of $509,394 816.
COST OF SERVICE METHODOLOGY
Once total Idaho jurisdictional costs are determined with the jurisdictional
separations study, the next step is to allocate those costs among the different customer classes
served by Idaho Power. This allocation of costs is accomplished with a Class cost of service
ORDER NO. 29505
study, which is similar to the jurisdictional separations study in assigning cost responsibility.
However, as the Commission has cautioned in past Idaho Power rate cases, a cost of service
study is not a perfect tool for assigning system and service costs to customer classes. The
Commission relies on a cost of service study as a starting point to allocate costs, "but in the end
we must, and do, consider other factors such as rate continuity, equity and proportionality.
Order No. 25880 at 27.
Idaho Power proposed use of a weighted 12 coincident peaks (W12CP) cost of
service study to assign costs to customer classes. The Commission used this methodology in
Idaho Power s last three rate cases. Tr. at 750-, Order No. 25880 at 27. The W12CP
methodology assigns a value (weighting factor) to each calendar month based on system capacity
and power supply costs needed to meet monthly peak energy demands. Staff used the
Company s cost of service study to allocate Idaho jurisdiction costs to the various customer
classes, but also performed two other studies as a check on the W12CP results. The other two
studies by Staff were variations on the W12CP methodology. In one, Staff weighted the month
of June at zero; in the second, Staff used a traditional unweighted 12 CP methodology. Tr. at
1617 -18. Staff performed the additional studies because the Company study showed that a
substantial rate increase was needed to bring the irrigation class to full cost of service, and Staff
wanted to know how sensitive class allocations, especially irrigation class allocations, are to
allocation factor changes." n. at 1618. Using Staff's test year revenue requirement , Staff's cost
of service studies showed required rate increases to bring the irrigation class to full cost of
service range from 29.1% (unweighted 12 CP) to 47.2% (W12CP). Tr. at 1617-18. With the
Company results validated by the studies, Staff recommended the Company s W12CP cost of
service study be accepted as the starting point to allocate costs to customer classes. Tr. at 1620-
21.
With the exception of the Irrigators, the intervenors that addressed the Company
cost of service study either recommended its use or did not object to it while offering suggestions
for improvement. For example, the Industrial Customers noted that peak energy demands are
used to determine allocation factors in the cost of service study, and that different customer
classes may react differently to peak load under different weather conditions. Tr. at 1342-43.
The Industrial Customers witness Dr. Reading suggested the Company "investigate how peak
loads react to weather conditions and what impact that it may have on inter-class allocations.
ORDER NO. 29505
Tr. at 1344. DOE witness Goins also recommended a change in the way Idaho Power
determined allocation factors, specifically in the way the Company classified hydro and steam
production costs as demand- and energy-related. Tr. at 2233-36. DOE nonetheless
recommended the Commission accept Idaho Power s cost of service methodology, testifying that
although "class responsibility cannot be determined with certainty. . . !PC's cost study reflects a
reasonable approximation of class cost responsibility." Tr. at 2231 2255.
Other than the Irrigators, Micron expressed the greatest concern with Idaho Power
W12CP methodology. Micron witness Dr. Peseau testified that "Idaho Power s cost of service
study is consistent with sound costing methods and prior Commission orders, with one very
significant exception.Tr. at 2456. The exception Micron identified is in the generation and
transmission demand allocators, where Idaho Power averaged weighted 12 CP allocators with
unweighted monthly allocators. Tr. at 2458. Micron performed a cost of service study using
weighted 12 CP allocators for generation and transmission costs rather than Idaho Power
average of monthly allocators. The result is that, "the cost of service for all classes other than the
irrigation class are lower in (Micron s) study compared to the Company , and the cost of service
for the irrigation class is higher." Tr. at 2464.
Not surprisingly given the results of the study, the Irrigators' witness Yankel
objected to Idaho Power s cost of service study, describing it as "fatally flawed and cannot be
relied upon to give accurate results.Tr. at 2558. The Irrigators discussed difficulties in
accessing the cost of service computer model, problems in the way Idaho Power weighted the
coincident peaks in the 12 months and in the use of marginal cost weighting factors, and
problems with data Idaho Power used for modeling inputs. In addition, the Irrigators suggest
that new customer growth in other classes have caused the increased costs while the irrigation
class has remained virtually unchanged. Mr. Yankel recommended that more costs be placed on
the growing classes that cause them rather than placing an increased burden on the irrigation
class. Tr. at 2620-22. Yankel asked the Commission to approve an equal percentage "across the
board (rate) increase to all customer classes " rather than approve rates based on an assignment
of costs as derived from Idaho Power s cost of service study. Tr. at 2599.
As we have in past rate cases, the Commission finds the W12CP cost of service study
is the appropriate starting point to allocate costs to customer classes. The Industrial Customers
Micron, DOE, Staff, Kroger, and AARP all agreed that Idaho Power s study was appropriate for
ORDER NO. 29505
allocating costs. Consequently, we find that the W12CP cost of service results reflect "
reasonable approximation of class responsibility" and thus provide a measure of relative revenue
responsibility among the customer classes. Tr. at 2255, Order No. 25880 at 27.
While we find Idaho Power s study appropriate for allocating costs in this case, we
are not determining the soundness of each component or input to the methodology. In fact, we
believe the Irrigators and other parties have raised serious legitimate questions regarding the cost
of service components and that they deserve additional investigation. Therefore, we open a
separate docket for the purpose of evaluating cost of service issues raised in this proceeding.
Specifically, we direct Staff and interested parties to evaluate appropriate issues through a series
of workshops (as needed), including: (1) how best to determine and weight monthly generation
and transmission allocators, (2) how to most accurately capture coincident peak demand
responsibility, and (3) whether new growth is properly covering its cost of service. We expect
consensus investigation results and recommendations to be documented in a final report and
submitted to the Commission no later than February 28, 2005.
With respect to the issue of new growth and how its cost flows through the cost of
service study, we also expect the parties to submit recommendations regarding any needed
changes in Idaho Power s line extension rules that are identified by the investigation. Once the
cost of service investigative report is received, the Commission can then determine how best to
proceed in addressing any recommended line extension tariff changes.
CLASS REVENUE ALLOCATIONS
Accepting the W12CP cost of service results as a starting point, the Commission
must determine the appropriate revenue requirement to be recovered in the rates of the different
customer ~lasses.The summary results of the W12CP cost of service study using the
Commission established revenue requirement is shown in Appendix 2.
A significant hurdle to implementing rates for each class in line with the results of
the cost of service study is the size of the increase the study assigns to the irrigation class. For
example, Idaho Power s cost of service study, using the Company s proposed revenue
requirement, showed an increase of more than 67% would be required to move the irrigation
class to full cost of service study results. Tr. at 1356. Staff's cost of service study, using the
same W12CP methodology but a greatly reduced Idaho jurisdiction revenue requirement,
ORDER NO. 29505
indicated a rate increase of approximately 47% to bring the irrigation class to full cost of service.
Tr. at 1707.
Most of the witnesses testifying on class revenue allocation addressed the size of the
rate increase it would take to move the irrigation class to match the cost of service study results.
Idaho. Power proposed to cap the rate of increase for the irrigation class at 25%, and Staff
suggested the irrigation customer rate increase be capped at 15%. Tr. at 1256, 1679. DOE
recommended the irrigation class be given a rate increase twice as large as the overall average
system increase. Tr. at 2243. AARP recommended annual increases in the irrigation rates for
four years after new rates are implemented. The example AARP provided, using Idaho Power
cost of service results, would initially increase the irrigation rates 25% as the Company
proposed, and then increase rates 4% each year for the next four years. Tr. at 2354-56. Kroger
recommended the Commission adopt a rate plan that moves the irrigation class rates one-third of
the way to full cost of service using annual increases for three years after implementation of new
rates in this case. Using Idaho Power s cost of service results, Kroger s recommendation would
increase the irrigation rates 25% and then annually for three years by 4~ 7%. Tr. at 2053-54.
Micron recommended the irrigation class be given the same percentage rate increase each year
for the next five years. Using Idaho Power s proposed revenue requirement, the irrigation class
would receive an annual rate increase of 18.6% for the next five years under Micron s proposal
but would see a rate reduction of 28.77% in the sixth year. Tr. at 2471-72. United Water
summarized the different recommendations regarding the irrigation class revenue requirement
and suggested the Commission give serious consideration to Micron s proposal. Tr. at 2289-91.
U sing the Commission-determined Idaho jurisdictional revenue requirement, the cost
of service study indicates a rate increase of 48.7% for the irrigation customers to move to full
cost of service. A number of witnesses testified to the importance of moving the irrigation rates
closer to full cost of service to avoid unfairness to the remaining customer classes. For example
United Water noted that under Idaho Power s revenue allocation proposal, rates for Schedule 9
customers are 5.4% higher than they would be if the irrigation rates were at full cost of service.
Tr. at 2285. United Water witness Healy also testified that residential customers receive the
heaviest burden from the irrigation class revenue requirement. "United's residential customers
are paying for the (irrigation) subsidy first through their electric rates and then again through
their water rates, which include United's electric power costs.Id. AARP witness Power
ORDER NO. 29505
testified that shifting part of the irrigation costs of service to residential customers and other
businesses reduces the expenditures the households can make in local businesses, and burdens
other businesses with higher costs so that one type of business can have lower costs. Tr. at 2350-
51. Micron witness Dr. Peseau testified that a revenue subsidy is created when electricity to a
class of customers is under-priced compared with the actual cost of serving the class "because
under normal ratemaking, any shortfall to a class is made up by overcharging some or all of the
remaining customer classes." Tr. at 2466. DOE witness Goins noted that Idaho Power proposes
to "overcharge" other customers to make up the shortfall in revenue assigned to the irrigation
class, and testified that "these interclass subsidies are unjustified and should be e1irninated~r at
a minimum, mitigated by moving rates for each class much closer to cost of service than !PC has
proposed." Tr. at 2241-42. Staff witness Schunke proposed allocation of revenue requirement to
the irrigation class at less than cost of service, which means "the revenue responsibility of the
irrigation class is reduced by over $19 million and this amount is reallocated to the other
customer classes." Tr. at 1679.
Not all the testimony in the record supported moving the irrigation class to full cost
of service. The Commission received public testimony from irrigators who were concerned with
the size of the proposed irrigation rate increase. Many individual irrigators testified the 25%
irrigation rate increase requested by the Company, or even the Staff-proposed 15% increase on
top of the rates they paid in 2003, would drive them or other irrigators out of business in the
current farming economic climate. Tr. at 61 , 67, 94, 145, 180 208, 234, 241 , 257, 1927-
2008. Individual irrigators also questioned how such a large percentage of costs could be
allocated to the irrigation class. For example, a member of the Bell Rapids Board of Directors
from Buhl doubted the need for irrigators to "pay a 15% increase that is four times the increase
of any other ratepayer.Tr. at 180. An Oakley director of the Idaho Ground Water Users
Association testified that most of the increase in peak power consumption has resulted from
residential use. Thus, irrigators should not be expected "to pick up that liability where we
been stable for 30 (or) 40 years in our development." Tr. at 256. The Chairman of the Power
County Commissioners testified
, "
it appears that rate increases are being unfairly targeted at
irrigation even though their usage hasn t gone up measurably.Tr. at 45. He suggested that
large residential growth in some parts of the state" likely created the need "for the increased
production and for handling the spikes in power usage.Id. An American Falls irrigator further
ORDER NO. 29505
testified that because Idaho Power s line extension tariffs are not adequate to fund growth
farmers in small towns (are being asked) to subsidize expansion in urban areas." Tr. at 66.
Given the less than perfect results from cost of service studies, and the other
considerations that are part of revenue allocation decisions, we find that the revenue requirement
assigned to the irrigation class should be less than indicated by the cost of service study. The
Commission has often stated that considerations such as rate stability and proportionality justify
limiting the amount of the rate increase to any class of customers. Cost of service studies have
consistently shown, however, that the irrigation class is paying rates significantly below the cost
to serve it relative to the cost to serve other classes. We stated in the last Idaho Power rate case
regarding the irrigation customer rates that, although cost of service studies are not precise
, "
think it important that cross subsidies among customer classes should be minimized." Order No.
25880 at 36.
We find that the rate increase for the irrigation class should not exceed 13.95%. The
irrigation class increase approved by the Commission is more than twice the approved system
rate increase, yet has a smaller dollar impact on irrigators than the options the parties
recommended from the cost of service results. For example, Idaho Power proposed to increase
the irrigation revenue requirement by over $15 million, while Staff recommended an increase in
excess of $9 million. The following chart shows the affect of the Commission approved revenue
increase for the irrigation class compared to the other recommendations:
Irrieation Base Rates % Increase Cents per kWh $ Increase
Current Base Rates 726
Company-Proposed 25.650 $15,078 364
Base Rates
Staff-Proposed 15.4.285 $9,059,627
Base Rates
Commission-Ordered 13.95%246 428,099
Base Rates
We also find that the remaining revenue requirement should be apportioned equitably
among the other customer classes. The spread of the revenue requirement to the customer
classes the Commission finds to be just, fair and reasonable is set forth in Appendix 3. No
customer class subject to a rate increase in this case, experiences a revenue requirement greater
than 5% above that indicated by the cost of service study. When deficiencies in the cost
service study identified by the various parties are considered in conjunction with the devastating
ORDER NO. 29505
effect a 100% move to cost of service could have on irrigators, we believe our decision is
warranted and reasonable. We have directed the parties to investigate the various components of
cost of service to provide more definitive information regarding appropriate cost responsibility
for each class. Until that information is provided to us, we find an irrigation class percentage
incre~e of more than twice the average increase for other classes in this case to be equitable.
RATE DESIGN Al\T)) T AmFF ISSUES
Idaho Power proposed numerous changes to rate design for the different customer
classes, including renaming the fIXed customer charge and significantly increasing it for most
customers. The Company s proposal for large increases in the customer charge generated the
most response from members of the public, and also was opposed by Staff and every intervenor
that discussed it. In addition to increased customer charges, the Company also proposed to
increase energy charges for every customer class in order to generate its proposed revenue
requirement. Idaho Power also recommended the implementation of higher energy rates during
the summer months for most customer classes and, in the case of the irrigation customers
(Schedules 24 and 25), proposed a higher "out of season" energy rate. Following a discussion of
the proposed increase to the customer charges, this section of the Order addresses Idaho Power
proposed rate changes for each customer class. We turn fIrst to the proposal to rename the fixed
customer charge.
Idaho Power proposed to change the name of the fixed "customer charge" to "service
charge" for Schedules 1, 7, 9, 19,24 and 25. Tr. at 790. The Company believes that the new
name would more accurately describe the fIXed service-related expenses the charge is designed
to recover. Id. The other parties did not generally oppose the name change. Consequently we
authorize the Company to change the fixed customer charge to "service charge." Although most
witnesses referred to it in testimony as "customer charge " we will refer to it as the "service
charge" in this Order.
1. The Service Charge.
As already noted, Idaho Power proposed significant increases in the service charge
each class of customers pays each month. For example, residential customers (Schedule 1) and
small general service customers (Schedule 7) currently pay a monthly service charge of $2.51
and the Company proposed to increase it to $10 per month for both classes. Exhibit 43 at 2-
The Company proposed to increase the service charge for large general service customers
ORDER NO. 29505
(Schedule 9-Secondary) from $5.54 to $21 per month.Exhibit 43 at 4.Primary and
transmission customers on Schedule 9, and many large power service customers (Schedule 19),
would see a new monthly service charge of $500, a significant increase from either $5.54 or
approximately $85 per month those customers currently are paying. Exhibit 43 at 5, 6, 8-10.
Idaho Power explained its reasoning for these significant increases. Company
witness Brilz insisted that the proper expenses to be included in the service charge are
investment in meters, a portion of the investment associated with distribution facilities, the costs
associated with meter reading and billing, and the costs associated with maintaining the
availability of service regardless of whether such service is actually taken.Tr. at 754-55. In
other words, the Company believes the service charge should include a component for "the
collection of facilities and expenses (unrelated to energy) required to serve a customer from the
grid." Tr. at 3171. With this objective in mind, Idaho Power witness Gale asserted the monthly
fixed charge for residential customers "should actually be much higher than the current proposal
potentially in the $25 to $30 range." Tr. at 3169.
Every intervenor that addressed Idaho Power s proposal to significantly increase the
fixed service charges opposed the proposal. The NW Energy Coalition testified that only costs
for meters, line drops, meter reading, and billing are customer-specific and should be included in
a service charge. Tr. at 2168. NW Energy Coalition witness Hirsh testified that costs related to
distribution and other infrastructure "reflect area-wide conditions and cannot be attributed to an
individual customer " and, thus do not belong in a monthly service charge. Tr. at 2170. In
addition, the Energy Coalition expressed concern that customers become less motivated to
reduce consumption and improve efficiency with a high fixed monthly charge, and that an
increase in fixed charges disproportionately impacts low and fixed income customers. Tr. at
2177-79. The Community Action Partnership Association witness Ottens likewise testified that
low income customers are hardest hit by a high service charge, stating: "Because it is a charge
not directly correlated to the level of actual energy usage, low income customers cannot
compensate by simply turning the lights off and the heat down." Tr. at 2100-01.
Staff witness Schunke testified that a service charge "should be based on the direct
cost of meter reading and billing and should not include any fixed plant cost." Tr. at 1690. Mr.
Schunke expressed concern that "a large customer charge would also be inconsistent with energy
conservation goals " noting that "the (residential) customer with the lowest usage would see a
ORDER NO. 29505
298% increase while the largest users would see only an 8% increase." Tr. at 1688-89; Exhibit
44 at 1. AARP also urged the Commission to reject "IPC's per customer allocation of a
significant part of the costs of the distribution system.Tr. at 2344-45. According to AARP
witness Power
, "
the appropriate definition of customer costs is those that could be avoided if the
customer ceased to take service " and would only include "'those meter reading and billing
functions that actually vary with the number of customers." Tr. at 2371.
The Commission fmds that a monthly service charge should recover costs that are
directly attributed to the customer paying the charge. Typically, those charges are related to
meter reading and customer billing. For residential customers, the cost of service study indicates
meter reading and customer billing costs are approximately $4.20 per month. Tr. at 1690. The
Commission finds, however, that increasing the residential service charge to this level is not
appropriate. We agree with the concerns expressed by the witnesses about the affects of a
relatively high monthly service charge. In particular, fIXed monthly charges dampen the
incentive for customers to conserve energy.
The Commission finds that the appropriate service charge for residential customers is
$3.30 per month. This is an increase of 31.47%. We find a service charge of that amount
provides a reasonable balance between recovering specific customer service costs in a fIXed fee
while preserving the ability to provide price signals for conservation purposes. For the same
reasons, the Commission approves increases in the service charges paid by most of the other
customer classes, but establishes a charge lower than what Idaho Power proposed to strike a
reasonable balance between the competing interests involved in establishing a fixed, monthly
service charge and to reflect the lower overall revenue requirement approved by this Order. By
increasing the service charges, the Commission also recognizes that Idaho Power will face
reduced risk due to greater cost recovery through higher fixed charges and the increased cash
flow that will result. The amount of the service charges for the other customer classes will be
discussed as part of each class' rate design and are summarized as follows:
ORDER NO. 29505
Rate Schedules Current Service Charge Ordered Service Charge
Residential (1)$2.$3.
Small General Service (7)$2.$3.30
Large General Service $5.$5.
(9 secondary)
Large General Service $85.$125.
(9 primary and transmission)
Industrial $5.$5.
(19 secondary)
Industrial $85.$125.
(19 primary and transmission)
Irrigation (24 and 25)
m-season $10.$12.
out -of-season $2.$3.
2. Residential Customers (Schedule 1).
Idaho Power proposed implementing higher summer energy rates for residential and
small general service customers (Schedules 1 and 7). The proposed summer months are June
July and August? The Company explained it is the summer peak usage that requires it to obtain
energy from higher cost sources, such as Idaho Power s Danskin plant or by purchasing power
from the wholesale market. The higher summer rates "are intended to signal customers that
consumption during the summer months is more costly." Tr. at 783-84. The Company did not
propose to include a "block" of energy during the summer at a lower, non-summer rate, and
instead proposed that all energy consumption during the three summer months be charged a rate
25% higher than the non-summer rate.
Staff witness Schunke agreed with the objectives of a higher residential summer rate
advocating a "peak period energy rate (that) would be about 20% higher than the base rate to
reflect the higher power supply cost in that period." Tr. at 1692. Staff proposed, however, that
the summer rate apply only to energy used in excess of 800 kWh per month during the three
summer months. AARP also recommended a lower rate for a block of energy, suggesting a price
3 The Company also proposes to implement rate differential designs for large general service, large power and
irrigation customers (Schedules 9, 19, 24 and 25). Rate differentials for these customers are discussed in the
appropriate sections below.
ORDER NO. 29505
differential at 400 kWh per month. Tr. at 2364. AARP proposed a rate 25% higher for usage
above the 400 kWh block, and also proposed leaving the two rates in effect year-round rather
than just during the SUIIlIIler. Tr. at 2364-66. According to AARP, a higher rate in effect only
during the SUIIlIIler does not address the winter peak that also occurs on Idaho Power s system
and AARP testified a year-round tiered rate would help convey to customers the higher marginal
energy cost that occurs in both the SUIIlIIler and winter peaks. Tr. at 2364. AARP witness Power
testified that a modest block of energy at lower rates "will provide some rate relief for smaller
households and those who cannot afford larger homes and more electric using appliances." Tr.
at 2366. The NW Energy Coalition witness Hirsh also expressed support for a block rate design
as an alternative to a high customer charge and as a way to alert customers to the high cost of
power during peak load hours." Tr. at 2198-99.
Company witness Brilz opposed the proposals for a block rate structure in rebuttal
testimony, stating that "the proposed blocked rates have no cost basis, penalize customers who
utilize electric energy for space heating, and provide an artificially low price signal to customers
who use less than the second-block threshold amount." Tr. at 2965. Ms. Brilz explained
regarding its cost basis argument, that a block rate structure does not address the variables that
determine the costs of energy, "including the time of day and time of year during which it is
produced or purchased, the balance between supply and demand, and the availability
transmission capacity." Tr. at 2966. Regarding electric space heat, Brilz argued that block rates
simply cause customers with electric space heat, many of whom do not have an alternative form
of space heating available, to pay higher bills while other customers with other forms of space
heat receive an artificially low price signal.Tr. at 2966-68. Regarding price signal, the
Company argued a block rate structure "implies that the energy consumed by high-use customers
is more valuable than energy consumed by low-use customers and, therefore, provides more
emphasis on energy conservation by high-use customers than by low-use customers.Tr. at
2968
The Commission fmds that a block of energy at a lower rate during the summer
months is reasonable, fair and appropriate, and provides proper price signals during the period
that the Company s energy costs are highest. We are not persuaded by Idaho Power s arguments
against a block rate design, and note that variations on its arguments can be applied to the
Company s proposal for a higher summer rate applied to all energy consumption. For example
ORDER NO. 29505
a higher summer rate does not take into account the many variables that determine the costs of
energy, but simply penalizes all customers that use energy during the summer, including
customers that do not use electricity for air conditioning. We also believe, contrary to Idaho
Power s argument, that it is proper to place .emphasis on energy conservation by high-use
residential customers because those customers are more likely to have a greater amount of
discretionary use that can be curtailed. In fact, the Commission s rate design assists electric
space heating customers because the higher rate applies only in the summer. By collecting a
greater portion of the revenue requirement in the summer, winter energy rates are lower than
they would otherwise need to be.
For residential customers, the Commission finds that a higher summer rate is
appropriate for the summer peak. months of June, July and August, except a 300 kWh block of
energy should be available at a lower, non-summer rate. The summer rate should be high
enough to send a price signal to customers that power used then is more costly. We find that
12.56% differential is reasonable. Providing the first 300 kWh of summer usage at the non-
summer rate allows some basic electric usage, such as for lighting and home appliances, that is
not subject to the summer differential.
Based on the Commission approved revenue requirement and revenue allocation to
the residential customers, the Commission fmds a rate of $0.056940 per kWh is appropriate for
summer usage above 300 kWh. A rate of $0.050585 per kWh is appropriate for the first 300
kWh of energy during the summer months and for all non-summer energy usage by residential
customers.
3. SmaU General Service Customers (Schedule 7).
As with the residential customers, Idaho Power proposed to increase the service
charge for small general service customers from $2.51 to $10 per month. For the same reasons
discussed above, the Commission finds that a service charge of $3.30 per month is reasonable
and appropriate for Schedule 7 customers.
The Company also proposed a higher summer rate for Schedule 7 customers, with no
separate rate for a block amount of energy. Staff rate recommendations for Schedule 7
customers were similar to those for residential customers. Staff witness Schunke proposed
summer rates that would include a lower rate for the first 600 kWh of energy consumed, and a
higher rate for energy above the block amount. The lower block rate would also be in effect
ORDER NO. 29505
during the nine, non-summer months. Tr. at 1699-1701. Staff recommended the summer peak
period rate should be approximately 17% higher than the lower non-summer rate.
Again for the same reasons we discussed in the above section on residential rates, the
Commission fmds that a summer block rate is appropriate for Schedule 7 customers. The
Commission fmds that a block rate design is appropriate for the summer peak months of June
July and August, and that the appropriate block for the lower rate is 300 kWh. Based on the
Commission approved revenue requirement and revenue allocation to the Schedule 7 customers
the Commission finds a rate of $0.068538 per kWh for summer usage above 300 kWh is just,
fair and reasonable. A rate of $0.060842 per kWh is appropriate for the first 300 kWh of energy
used during June, July and August, and for all energy usage during the non-summer months.
The differential between the summer second block and the non-summer energy rate is
approximately 12.66%, or slightly higher than the 12.56% differential established for residential
customers. While we recognize that variability in usage characteristics for this class may be
significantly greater than those of the residential class, we believe that a summer fU'St block
300 kWh provides a reasonable average base level of consumption.
Idaho Power also proposed to change the way that customers' usage is evaluated to
determine whether they qualify for Schedule 7 rates. Currently, a customer s usage is evaluated
once each year, after which the customer is switched to a different schedule for the next year if
the usage falls within a different schedule. The Company proposed to eliminate the annUal
review and instead review customer usage each month, making transfers to the appropriate
schedule timelier. No one objected to this proposed change to Schedule 7, and the Commission
fmds it to be fair and reasonable.
4. Large General Service Customers (Schedule 9).
Large general service customers receive energy at levels classified as primary,
secondary or transmission, and there are significant differences in some of the rate elements for
the different customers. All Schedule 9 customers pay a service charge, an energy charge, a
demand charge, a basic charge, and transmission level customers may also pay a facilities
charge. The demand charge is assessed on peak demand each month and the basic charge is
assessed on the average of the two highest peak demands for the current 12-month period. Tr. at
802. Idaho Power proposed increases in Schedule 9 service charges, basic charges, demand
ORDER NO. 29505
charges and energy charges, and in addition would implement summer rates for demand and
energy charges.
Currently the service charge for Schedule 9 secondary service customers is $5.54 per
month and is $85.58 per month for primary and transmission customers. Idaho Power proposed
significant increases to the service charges-secondary service customers would pay $21 per
month, and primary and transmission service customers would pay $500 per month. We do not
believe changes in customer charges for secondary service Schedule 9 are warranted at the same
level as those established for residential and general service schedules. These schedules already
have service charges that more than recover the cost associated with fIXed customer service costs
and therefore should remain relatively unchanged at $5.60 per month. The Commission does
fmd that Schedule 9 primary and transmission service charges should be increased to $125 per
month to better reflect the higher fixed customer service costs associated with providing service
under these schedules.
Idaho Power also proposed increases in the other Schedule 9 rates to recover its
projected revenue requirement. Based on its much lower revenue requirement for the Company,
Staff recoIIlIIlended a slight decrease in demand and energy charges for secondary service
customers, but increases of approximately 13% in demand and energy charges for primary
customers and transmission customers. Tr. at 1704-05. Kroger witness Higgins pointed out
Staff's recommendation alters the price differential that currently exists in the Schedule 9 rates.
Under current rates, primary service is 9 to 13 percent less expensive than secondary service,
but under Staff's proposal , this differential is virtually eliminated.Tr. at 2071. Kroger
testified that primary service is cheaper to provide, and recommended that the existing price
differential between the Schedule 9 types of service be retained. Tr. at 2079.
The Commission approves increases in the Schedule 9 demand and energy charges.
Because the revenue requirement we approve is significantly lower than that proposed by the
Company, the rates we find fair and reasonable are lower than the Company requested. We also
agree with Kroger that a price differential should be maintained between the types of service in
Schedule 9. We recognize that in some cases a customer may pay more taking primary service
than secondary. Although this result seems counter-intuitive, it occurs because of the customer
particular configuration and usage. The basic charges the Commission finds to be fair, just and
reasonable are $.37 per kW for secondary customers
, $.
85 per kW for primary customers, and
ORDER NO. 29505
$.43 per kW for transmission customers. The demand charges the Commission approves for
Schedule 9 are as follows:
Secondary customers: summer $3.00 per kW; non-summer $2.73 per kW
Primary customers: summer $3.16 per kW; non-summer $2.82 per kW
Transmission customers: summer $3.06 per kW; non-summer $2.73 per kW
The energy charges the Commission approves for Schedule 9 are as follows:
Secondary customers: summer $0.028903 per kWh; non-summer$0.025784
per kWh
Primary customers: summer $0.025325 per kWh; non-summer $0.022700
per kWh
Transmission customers: summer $0.024761 per kWh; non-summer
$0.022291 per kWh
The Commission finds the rates set forth above to be just, fair and reasonable for Idaho Power
large general service customers. As we explained in our discussion of Schedule 7, Idaho Power
also proposed new eligibility criteria for Schedule 9. The Commission approves the same
change in the Schedule 9 tariffs.
Kroger recommended, noting Idaho Power s proposal to implement mandatory time-
of-use (TOll) rates for Schedule 19, that the Commission also approve Tau rates for Schedule 9
so that these customers could better respond to price signals, as well as pay rates that are more
closely aligned with the costs they cause.Tr. at 2057-58. Kroger proposed the Schedule 9
TOU rates, however, should be voluntary, leaving it to individual customers to choose TOU
rates. Tr. at 2061. In rebuttal testimony, Company witness Brilz testified that voluntary TOU
rates are attractive only to customers that will benefit by lower rates, so that "the result is a
reduction in revenue for the Company without any corresponding benefit." Tr. at 2979. Idaho
Power also noted that only primary and transmission level customers currently have the metering
in place to facilitate TOU pricing. The Company recommended that the TOU rates for Schedule
19 be implemented and evaluated prior to implementing TOU rates for Schedule 9 customers.
Tr. at 2983.
The Commission fmds the rebuttal arguments by Idaho Power to be persuasive and
will not require TOU rates for Schedule 9 customers. However, we anticipate that after the
ORDER NO. 29505
Company has gained experience with its Schedule 19 TOU rates, it will turn its attention to
designing and proposing a TOU rate structure for Schedule 9.
5. Large Power Service Customers (Schedule 19).
The current rate structure for large power service customers is similar to the rate
design of the large general service customers, and some of the rate changes Idaho Power
proposed for Schedule 19 are the same as it proposed for Schedule 9. For example, large power
customers currently pay service charges similar to service charges for Schedule 9 customers, and
the Company proposed to increase all Schedule 19 service charges to $500 per month. The
Commission approves the same service charges for Schedule 19 as it did for Schedule 9:
secondary service customers will pay a $5.60 service charge, primary and transmission
customers will pay a $125 per month service charge.
The most significant difference in the Company s proposals for Schedule 9 and
Schedule 19 is to implement mandatory time-of-use (TOU) rates for Schedule 19 customers.
The Company-proposed rates would include on-peak, mid-peak and off-peak energy prices to be
in effect during June, July and August. During the other nine months, mid-peak. and off-peak
energy rates would be in effect. Staff witness Schunke testified that TOU rates are appropriate
for Schedule 19 customers "who are sophisticated enough to understand them and where the
metering equipment already exists." Tr. at 1706-07. Staff believes TOU rates send at least two
important price signals: "The higher price during the periods when costs are higher encourages
customers to reduce consumption and allows rates to be lower when the cost of power is lower
thus encouraging use during these off-peak periods. By shifting load, peaking facilities and peak
power purchases can be reduced and existing base load facilities can be better utilized." Tr.
1681.
DOE also supported implementation of mandatory TOU rates for Schedule 19, but
expressed concern that some of the large commercial and industrial customers that take service
under Schedule 19 are not prepared to operate cost-effectively under the new TOU rates. Tr.
2247. DOE witness Goins recommended the TOU rates be implemented, but that the
Commission "require !PC to prepare and file semiannual reports for the first year in which the
rate is in effect concerning the implementation of the new TOU rate.Tr. at 2248. DOE'
recommendation generated testimony from others about a phasing-in of the TOU rates.
ORDER NO. 29505
The Industrial Customers opposed mandatory TOU rates for Schedule 19 customers.
Noting the complexity ofTOU rates, the Industrial Customers witness Teinert testified that Idaho
Power "is proposing the implementation of the mandatory time-of-use rate without carefully
analyzing the impact of the proposed Schedule 19 rate on either the Company or the Schedule 19
customers." Tr. at 1374. Mr. Teinert also testified that "Schedule 19 customers have not caused
the Company to incur the costs associated with the need for summer peaking resources " one of
the primary issues TOU rates are intended to address. Tr. at 1376. The Industrial Customers
compared the Schedule 19 and residential customer classes for seasonal changes in load growth
and customer growth in each class to support its argument that the Schedule 19 customers have
not caused Idaho Power to invest in additional peaking resources. Tr. at 1376-78. In rebuttal
testimony, the Industrial Customers expressed in stronger terms, in light of support of TOU rates
from Staff and DOE, its objection to mandatory TOU rates.
The Commission approves the Company s proposal for mandatory TOU rates for
Schedule 19, but requires a phase-in period before they are implemented. For a period of six
months, Idaho Power shall provide two bills to the Schedule 19 customers. The second bill will
show the charges that would be incurred under the TOU rates. After six months, Idaho Power
can fully implement the TOU rates and bill customers according to the new rates.
accommodate the phase-in period, the Commission approves new rates for Schedule 19 for use
during the flI'st six months, and also approves TOU rates for implementation after six months.
The new Schedule 19 rates approved by the Commission are set forth in Appendix 4, pages 7
through 12. The Commission fmds these rates to be fair, just and reasonable.
Because this case represents the flI'st time mandatory TOU rates have been
established by the Commission, we find that summer peak and off-peak energy differentials
should be established at conservative levels for the three Schedule 19 service classifications. The
secondary differential is set at approximately 13%, the primary differential at approximately
19% and the transmission schedule at approximately 19%. Given the established phase-in period
and the Company s expressed intent to file another general rate case within the next three years
we find the established differentials to be a reasonable first step toward implementing and
evaluating mandatory TOU. As we explained in our discussion of Schedules 7 and 9, Idaho
Power proposed new eligibility criteria for Schedule 19. The Commission approves the same
change in the Schedule 19 tariffs.
ORDER NO. 29505
The Industrial Customers witness Teinert objected to Idaho Power s current line
extension provisions in Schedule 19 tariffs, and also to the monthly conservation charge paid by
Schedule 19 customers because "currently Idaho Power does not administer any conservation or
DSM (demand side management) programs specifically for the Schedule 19 customer class." Tr.
at 1386. The Industrial Customers additionally objected to the Company s proposal to increase
the minimum power factor in Schedule 19 from 85% to 90%.
The Company is not proposing any changes to the line extension provisions for
Schedule 19 customers. Tr. at 884, 2991. The Commission approved those terms in January
1993. Tr. at 2991. The Commission is not convinced by the record in this case that the Schedule
19 tariff provisions on line extensions need to be revised. That said, we believe a proceeding to
modify Idaho Power line extension schedules may be an appropriate offshoot of the cost of
service investigation previously addressed in this Order. To the extent that investigation results
in recommended changes to new customer contributions or allowances, a line extension
proceeding will be a valid method of addressing those recommendations.
Regarding the Company s proposal to adjust the power factor minimum for Schedule
19 customers, the Industrial Customers simply asserted Idaho Power "does not offer evidence or
testimony that its delivery system is capacity constrained due to power factor. Therefore, the
increase in the minimum is not warranted." Tr. at 1386. In rebuttal testimony, Company witness
Brilz testified its 2002 Integrated Resource Plan "identified multiple delivery system capacity
constraints " and that its "distribution system is typically voltage and capacity constrained." Tr.
at 2993. Brilz argued it "must install capacitors to correct for loads with less than unity power
factors" in order to maintain system capacity. Tr. at 2993. The Commission approves the
Company s proposal to increase the minimum power factor from 85% to 90% for Schedule 19
customers. The change will properly align the cost burden of customers whose reactive loads are
placing increased costs on the Company.
Finally, regarding the Schedule 19 tariff provisions addressing conservation
programs, Industrial Customers witness Teinert noted that each customer pays a monthly charge
through the Company s Energy Efficiency Rider, Schedule 91 , but that "currently Idaho Power
does not administer any Conservation or DSM program specifically for the Schedule 19
customer class.Tr. at 1386. The Industrial Customers recommended
, "
each industrial and
special contract customer should be allowed to use the funds it contributes to Idaho Power
ORDER NO. 29505
energy efficiency rider for projects at their own industrial sites.Tr. at 1387. In rebuttal
testimony, Idaho Power testified that its Industrial Efficiency Program began in October 2003
and that it is targeted at customers with 500 kW or more of load. Tr. at 2994. Accordingto
Company witness Brilz
, "
two proposals have been approved for implementation and an
additional three proposals are undergoing the approval process.Tr. at 2994. Staff
recommended the Commission make no change to the Energy Efficiency Rider. Tr. at 1716.
The Commission is not convinced the record in this case establishes that changes are
required for the Energy Efficiency Rider, Schedule 91. The Commission would like the
Company to develop and present a conservation program targeted specifically to Schedule 19
customers. The new time of use (TOll) rates we approve for the Schedule 19 customers are
intended to assist them in identifying conservation measures for their facilities and operations.
We note that the Industrial Efficiency Program implemented in October 2003 is targeted to
customers whose load is at least 500 kW, while customers are required to have at least 1 000 kW
of demand to qualify for Schedule 19 rates. There was no indication in the record that any of the
five industrial efficiency proposals already approved or under review by Idaho Power were for
Schedule 19 customers. Given the new, mandatory TOU rates for Schedule 19 customers, the
Commission would like to see a DSM program that allows Schedule 19 customers to determine
appropriate energy conservation improvements to their own facilities and receive matching funds
from their contributions to Energy Efficiency Rider program to install the improvements. Idaho
Power should work With the Schedule 19 industrial customers to develop a proposal to submit to
the Commission.
6. Irrigation Customers (Schedule 24 and Schedule 25).
Idaho Power did not propose significant rate design changes for irrigation customers.
The controversial issue was the amount of the rate increase the irrigation class should receive.
The Commission previously discussed the cost of service results, where the Company proposed a
Schedule 24 rate increase of 25% based on its recommended revenue requirement, and Staff
proposed a 15% rate increase based on a much lower revenue requirement. Other parties
recommended annual rate increases for the irrigation class to bring its rates in line with the cost
of service study results.
The Company proposed to increase the irrigation class seI"Vlce charge, which
currently is $10.07 per month during the "in-season" period (May through September) and is
ORDER NO. 29505
$2.50 per month for the "out-season" period. Idaho Power proposed to increase only the in-
season service charge, to $25 per month for secondary service customers and $500 per month for
transmission level customers, although currently the Company has no transmission level
irrigation customers. The Company also would increase the in-season demand charge from
$3.58 per kW to $5.40 per kW, and the energy rate from $0.028416 (in-season) to $0.032634 per
kWh.
To implement its recommended revenue requirement, Staff proposed to increase the
in-season Schedule 24 service charge from $10.07 to $12, and the out-season service charge and
the minimum charge from $2.50 to $3 per month. Tr. at 171 O. Staff proposed an in-season
demand charge of $4 per kW and an out-season demand charge of $.80 per kW. Finally, Staff
proposed to change the existing energy rates to remove the in-season and out-season differential
so that both rates are equal at $0.032830 per kWh. Tr. at 1710.
The Commission finds that an overall rate increase of 13.95% for the irrigation
customers is just, fair and reasonable. We recognize that this rate increase is significant.
However, it is unavoidable. Even if the precise results of the cost of service methodology are
discounted, the large disparity between those results and existing irrigation base rates shows that
in a relative sense, the irrigation class does not pay its own way, and other customer classes
makeup the difference. Even - with this large increase, the irrigation class remains behind
relatively in sharing the cost burden as demonstrated by the currently used cost of service
methodology. We fmd, to recover the assigned revenue requirement, the appropriate in-season
service charge for Schedule 24 is $12, and the demand charge is $4 per kW. The Commission
also finds a year-round energy rate of $0.032440 per kWh and an out of season demand charge
of $0.80 per kW to be just, fair and reasonable for Schedule 24 customers.
Idaho Power also proposed to remove non-agricultural irrigation customers from
Schedule 24. The Company stated that there are approximately 768 customers that use irrigation
for city parks, school grounds, cemeteries, common areas in subdivisions, and golf courses. Tr.
at 842. Idaho Power proposed to restrict Schedule 24 to agricultural use, and would move the
other customers to a higher priced general service schedule. The Company did not provide
evidence of the revenue impact of restricting Schedule 24 to agricultural use, nor did it provide
any justification for creating a distinction between different types of irrigation customers. The
ORDER NO. 29505
Commission denies the Company this proposed restriction for Schedule 24 customers without
further evidence that distinguishes these uses from agriculture.
Schedule 25 is a pilot irrigation program that implemented time-of-use rates in
October 2002. The Company plans to provide service under Schedule 25 through 2007, but is
not allowing new customers to sign on for Schedule 25 service. Idaho Power proposed increases
in the Schedule 25 rates and charges similar to those for Schedule 24. Tr. at 835-36, 1714-15.
We fmd, to recover the assigned revenue requirement, the appropriate in-season service charge
for Schedule 25 is $12, and the demand charge is $4 per kW. The Commission also finds energy
rates of $0.058854 per kWh (on-peak), $0.016815 per kWh (off-peak), and $0.033631 kWh
(mid-peak and out season) to be just, fair and reasonable for Schedule 25 customers. These TOU
rate differentials, while larger than those established for Schedule 19, are for a voluntary summer
only program and therefore are deemed appropriate in this case.
7. Other Rate Design Issues (Schedules 15,40,41,42 and Schedules 26,29,30).
Consistent with its proposed revenue requirement and cost of service study results
the Company proposed increases in rates for Dusk to Dawn Lighting (Schedule 15), Unmetered
General Service (Schedule 40), Street Lighting (Schedule 41) and Traffic Control (Schedule 42).
Idaho Power also proposed changes to some of the terms of service in these schedules. For
example, the Company would change Schedule 15 to allow light fixtures to be installed on a
customer provided support acceptable to the Company rather than restricting attachment to a
Company-owned pole. Based on its revenue requirement and cost of service results, Staff
proposed modest increases or, in some cases, modest decreases in the rates for these schedules.
The parties did not address the Company s proposed changes in the terms of
Schedules 15 41 and 42. The Commission approves the Company s proposed tariff changes
but not the Company s proposed rates. The rates for Schedules 15 , 40, 41 and 42 that the
Commission has determined are just, fair and reasonable, are based on its approved revenue
requirement contained in Appendix 3. Rate components for these schedules are modified on an
equal percentage based upon the percentage change in class revenue requirement.
The Company also proposed rate increases for its special contract customers Micron
(Schedule 26), Simplot (Schedule 29) and DOE (Schedule 30), and Staff recommended modest
increases or rate decreases for these customers; The rates for Schedules 26, 29 and 30 that the
Commission has determined are just, fair and reasonable, are based on its approved revenue
ORDER NO. 29505
requirement contained in Appendix 3. Rate components for these special contracts are modified
on an equal percentage based upon the percentage change in revenue requirement established for
each customer.
ADJUSTMENTS TO THE PCA
The Power Cost Adjustment (PCA) is a rate adjustment mechanism that annually
adjusts a portion of customer rates to allow Idaho Power to reCover or refund 90 percent of above
or below normal load adjusted power supply costs. Tr. at 1620. Base power supply costs are
established in a general rate case and are included in the revenue requirement that determines the
base rates for the customer classes. The various components of the PCA are also reviewed and
updated in a rate case, and Idaho Power accordingly proposed revisions to PCA calculations.
The Company s Exhibit 36 shows four PCA component calculations the Company proposes to
update, identified as Normalized PCA Expenses, the Normalized Base PCA Rate, the Idaho
Jurisdictional Percentage, and the Expense Adjustment Rate for Growth (EARG).
Only the Commission Staff addressed the Company s proposed updates to the PCA
calculations, and agreed with Idaho Power s adjustments to the Normalized PCA Expenses, the
Normalized Base PCA Rate, and the Idaho Jurisdictional Percentage. Tr. at 1622-23. Noting
significant differences between the Company and Staff positions on the EARG, the Company
suggested a separate proceeding to address adjustments to the EARG. Staff made a motion at the
hearing for the EARG to be considered in a proceeding outside this rate case. The Company as
well as DOE supported this motion, and the Commission granted the motion. Tr. at 349.
Accordingly, the Commission approves Idaho Power s proposed adjustments to the Normalized
PCA Expenses, the Normalized Base PCA Rate, and the Idaho. Jurisdictional Percentage
components of the PCA.
Based upon the evidence in the record, we find Idaho Power s adjustments to the
Normalized PCA Expenses, the Normalized Base PCA Rate, and the Idaho Jurisdictional
Percentage to be just and reasonable. At the request of Staff, Idaho Power and DOE, the
Commission will consider adjustments to the EARG in a separate proceeding as discussed
further in the "New Cases and Other Issues" section below.
INTERVENOR FUNDING
The Commission received timely requests for intervenor funding from the Idaho
Irrigation Pumpers Association, Inc. ($75 554.40), Community Action Partnership Association
ORDER NO. 29505
of Idaho ($21 293.52), and NW Energy Coalition ($11 512.30).Idaho Code ~ 61-617A
authorizes an intervenor cost award not to exceed a total of $40 000 for all intervening parties
combined. Individual awards must be based on fmdings that the intervenor s participation
materially contributed to the Commission s decision, the costs of intervention are reasonable and
would .be a significant financial hardship for the intervenor if no award is given, the
recoIIlIIlendations made by the intervenor differed materially from Staff s evidence, and the
intervenor s participation addressed issues of concern to the general body of users or consumers.
All three of the intervenors requesting funding materially contributed to the
Commission s decisions through their participation. Although the Commission did not adopt all
the proposals advocated by the intervenors, the advocacy of each intervenor influenced the
ultimate decisions that have been made. Each of the intervenors offered evidence that differed
materially from that offered by Staff. Each intervenor addressed issues of concern to the general
body of users or consumers, although this standard was met more completely by Community
Action and NW Energy, who participated in the case to represent public consumers in general
rather than a particular group of business customers.
The intervenor funding statute requires the Commission to consider reasonableness in
the costs of intervention and the relative hardship for each intervenor. Each of the three
intervenors fully participated in the case by presenting prefiled testimony, attending the hearings
and cross-examining witnesses. Community Action and NW Energy are public interest entities
with modest financial resources and would probably not be able to participate without intervenor
funding. They brought a perspective to the hearing that has historically been lacking or under-
represented. We appreciate their frugal approach to their funding requests.
Based on the record and the intervenor funding requests, we find that the policy stated
in Idaho Code ~ 61-617 A to encourage participation in Commission proceedings "so that all
affected customers receive full and fair representation" is furthered by awarding intervenor
funding to the Irrigators and Community Action the amount of $15 000 each, and NW Energy
the amount of $10 000. Community Action and NW Energy intervenor funding awards of
$15 000 and $10 000, respectively, are to be recovered from Schedule 1 customers, and the
Irrigators' award of $15 000 shall be recovered from Schedule 24 customers. We believe it is
reasonable to collect these amounts from the appropriate classes in the 2005-2006 PCA for the
reasons set forth above in our discussion of test year intervenor funding. We also note that it is
ORDER NO. 29505
extremely difficult to allocate a fixed monetary amount over reasonable requests that far exceed
that allowed by statute. However, we believe this allocation best satisfies the considerations set
forth in Idaho Code ~ 61-617A
NEW CASES AND OTHER ISSUES
Several issues arose in the testimony that the Commission has detennined should be
addressed in separate proceedings, although each may be handled in a workshop setting that does
not require a formal hearing. As previously mentioned, the Commission at the hearing granted
Staff's motion for a separate proceedipg to address Expense Adjustment Rate for Growth
component of the PCA formula. Idaho Power and Staff are directed to detennine a schedule for
one or more workshops and initiate a docket to address this piece of the PCA.
proposal for a second workshop proceeding was sponsored by NW Energy
Coalition, which argued that financial disincentives hinder Idaho Power s investments in cost-
effective energy efficiency and clean distributed generation. NW Energy Post Hearing Brief at
1. NW Energy filed with its brief an agreement signed by representatives of NW Energy, Idaho
Power, Staff and Industrial Customers committing them, should the Commission determine that
removing the disincentives is in the public interest, to "work together to investigate specific
mechanisms for achieving this objective, to identify areas of consensus, and to clarify
alternatives where consensus is not possible." NW Energy Joint Proposal at 1. The Commission
has determined that a proceeding to assess financial disincentives inherent in Company-
sponsored conservation programs is appropriate and should proceed by informal workshops.
The Commission specifically directs the parties to address possible revenue adjustment when
annual energy consumption is both above and below normal. The parties should also consider
how much adjustment is necessary to remove DSM investment disincentives and whether (and to
what extent) performance-based incentives such as revenue sharing could or should be
incorporated into the resolution of this issue. The Commission is interested in proposals that
could provide Idaho Power the opportunity to share and retain benefits gained from efficiencies
especially where efficiencies are derived from innovation and the use of new technologies. For
example, a proposal might include a way to average expense reductions that result in efficiencies
on the system that benefit the Company and its shareholders while maintaining or improving
service quality standards. The parties may also consider including service quality standards or
benchmarks as a component of an incentive mechanism. In short, the Commission believes
ORDER NO. 29505
opportunities exist for improvements in operating efficiency that would benefit the Company.
shareholders and its customers, and we encourage the parties to creatively consider the options
for a performance based mechanism to present to the Commission. The parties to the agreement
are directed to propose a workshop schedule and initiate a proceeding.
As previously stated, the Commission has also determined to initiate a proceeding to
consider and evaluate cost of service issues raised in this case. Witnesses for the Industrial
Customers, Micron, DOE and the Irrigators all identified problems with the cost of service study
components. These issues should be further investigated before the next Idaho Power general
rate case. The Commission also received testimony from irrigation customers and other
ratepayers who were concerned with how investments necessitated by customer growth should
be paid. Tr. at 65-, 2036. These witnesses suggested that a revised line extension policy could
appropriately align cost recovery with the customers who create the need for system
improvements. Consequently, the Commission has specifically directed the parties to address
load growth issues in the cost of service proceeding to determine if line extension modifications
are necessary. Staff is directed to determine a workshop schedule and initiate a proceeding for
that purpose.
Finally, the Commission s Consumer Division Staff presented in testimony specific
recommendations for Idaho Power to improve customer service issues. To its credit, the
Company responded in a positive way to Staff's recommendations , agreeing to implement the
recommendations or, in one case, by making suggestions that improved the recommendations.
These issues do not require a separate proceeding, but Staff should review the Company
implementation of the changes it agreed to and report to the Commission should any significant
issues arise in the implementation process.
ULTIMATE FINDINGS OF FACT
Idaho Power Company is an electrical corporation subject to the Commission
regulation under the Idaho Public Utilities Law. The rates of all its tariff customers in the State
of Idaho and of its contract customers are subject to this Commission s regulation under the
Public Utilities Law.
The Company s present rates do not provide it with an opportunity to earn a fair and
reasonable return on its investment. Allowing the Company to increase its rates and charges by
ORDER NO. 29505
$25 329 438 will provide it with the opportunity to earn a fair and reasonable return. The
average 2003 test year is the appropriate test year period for use in this proceeding.
The adjusted test year net operating income for Idaho of $103,918 528 is just and
reasonable for setting rates. The test year adjusted rate base for Idaho of $1 519 924 799 is just
and reasonable for setting rates. Idaho Power s actual capital structure at December 31 , 2003 is
the appropriate one for this case and an overall rate of return of 7.852%, to be applied to all rate
base, is a fair and reasonable rate of return for the Company.
The revenue allocation shown in Appendix 3 is a just, reasonable and non-
discriminatory allocation of the Company s revenue requirement among the various customer
classes. It is also fair, just and reasonable to design the customer class rates according to the
directives contained in the text of this Order.
The awards of intervenor funding in the amounts of $1 0 000 to NW Energy Coalition,
$15 000 to Idaho Irrigation Pumpers Association, Inc., and $15 000 to Community Action
Partnership Association of Idaho are reasonable.
CONCLUSIONS OF LAW
This Commission has jurisdiction and authority to authorize and require Idaho Power
Company to re-allocate its revenues among the customer classes, to change its rate components
within the customer classes, to address the other issues and to award intervenor funding in the
manner set forth in the text of this Order.
ORDER
IT IS HEREBY ORDERED that Idaho Power Company file tariffs in conformance
with this Order to be effective on June 1 2004, for service rendered on and after that date.
IT IS FURTHER ORDERED that Idaho Power Company comply with all other
directives of the text of this Order.
IT IS FURTHER ORDERED that the Community Action Partnership Association of
Idaho comply with the conditions and reporting requirements associated with the Low Income
Weatherization Assistance funding authorized by this Order.
IT IS FURTHER ORDERED that the parties determine a workshop schedule and
initiate separate proceedings to resolve issues regarding the Expense Adjustment Rate for
Growth, fmancial disincentives in Company-sponsored conservation programs, and cost of
ORDER NO. 29505
service study compOnents (including whether load growth is properly recovering its cost) as
discussed in this Order.
IT IS FURTIIER ORDERED that NW Energy Coalition is awarded intervenor
funding in the amount of $10 000, the Idaho Irrigation Pumpers Association, Inc. is awarded
intervenor funding in the amount of $15 000, and Community Action Partnership Association of
Idaho is awarded intervenor funding in the amount of $15 000. Idaho Power is directed to pay
these amounts within 28 days of the date of this Order.
TIllS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this Case No. IPC-03-
may petition for reconsideration within twenty-one (21) days of the service date of this Order
with regard to any matter decided in this Order or in interlocutory Orders previously issued in
this Case No. IPC-03-13. 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. 29505
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
day of May 2004.
j)~
MARSHA H. SMITH, COMMISSIONER
~~,J
ENNIS S. SE , C MMISSIONER
ATTEST:
Je D. Jewell
Commission Secretary
blslO: IPCEO313 - ws _final
ORDER NO. 29505
IPUC FINAL ORDER
JURISQICTIONAL SEPARATION STUDY - REVENUE REQUIREMENT
FOR THE TWELVE MONTHS ENDING DECEMBER 31 , 2003
TOTAL IDAHO
2 DESCRIPTION SYSTEM IPUC
RATE OF RETURN UNDER PRESENT RATES
TOTAL COMBINED RATE BASE 643,706,370 519,924,799
SALES REVENUES 576.039,178 543,332 605
OTHER OPERATING REVENUES 42.464.061 35.419.775
TOTAL OPERATING REVENUES 618.503.239 578,752,380
OPERATING EXPENSES
OPERATION & MAINTENANCE EXPENSES 367 262 862 343,856,114
DEPRECIATION EXPENSE 106,208 86,136 616
AMORTIZATION OF LIMITED TERM PLANT 825,386 090 099
TAXES OTHER THAN INCOME 20,910,436 18,979 024
PROVISION FOR DEFERRED INCOME TAXES 109 043 002 364
INVESTMENT TAX CREDIT ADJUSTMENT (308,166)(297,592)
FEDERAL INCOME TAXES 038,536 193 496
STATE INCOME TAXES 693 140 560.916
TOTAL OPERATING EXPENSES 515,637 445 481,521 037
OPERATING INCOME 102 865,794 231 343
ADD: IERCO OPERATING INCOME 106 583 687.185
CONSOLIDATED OPERATING INCOME 109.972,377 103 918.528
RATE OF RETURN UNDER PRESENT RATES 69%84%
DEVELOPMENT OF REVENUE REQUIREMENTS
RATE OF RETURN REQUIRED ~ 10.25% ROE 852%
RETURN AT CLAIMED RATE OF RETURN 119,344,495
EARNINGS DEFICIENCY 425,967
NET-TO-GROSS TAX MULTIPLIER 642
REVENUE DEFICIENCY 329,438
FIRM JURISDICTIONAL REVENUES 483 961 369
PERCENT INCREASE REQUIRED 23%
SALES AND WHEELING REVENUES REQUIRED 509,290,807
APPEND IX
ORDER NO. 29505
CASE NO. IPC-03-
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A
v
g
.
20
0
3

S
a
l
e
s
Cu
r
r
e
n
t
Ap
p
r
o
v
e
d
Av
g
.
LI
n
e
Sc
h
.
Nu
m
b
e
r

o
f
No
r
m
a
l
i
z
e
d
Ba
s
e
Ba
s
e
Mi
l
l
s
Pe
r
c
e
n
t
ca
s
Ta
r
i
f
f

D
e
s
c
r
i
ti
o
n
No
.
Cu
s
t
o
m
e
r
s
(k
W
h
)
Re
v
e
n
u
e
Re
v
e
n
u
e
Pe
r

K
W
H
Ch
a
n
Q
e
IN
D
E
X
Un
i
f
o
r
m

T
a
r
i
f
f

R
a
t
e
s
:
Re
s
i
d
e
n
t
i
a
l

S
e
r
v
i
c
e
33
5
60
5
14
1
,
39
3
,
4
2
6
21
4
28
9
41
4
22
7
11
3
78
2
54
.
98
%
10
5
%
Sm
a
l
l

G
e
n
e
r
a
l

S
e
r
v
i
c
e
31
6
26
5
,
33
5
66
7
79
8
47
6
80
1
08
0
67
.
97
%
10
5
%
La
r
g
e

G
e
n
e
r
a
l

S
e
r
v
i
c
e
29
9
66
7
,
37
6
23
7
97
,
34
9
13
8
99
,
27
8
73
9
37
.
98
%
10
5
%
La
r
g
e

G
e
n
e
r
a
l

S
e
r
v
i
c
e
11
6
34
7
,
05
0
74
9
10
.
31
9
,
87
4
11
,
39
3
,
16
4
32
.
10
.
4
0
%
10
0
%
Du
s
k

t
o

D
a
w
n

L
i
g
h
t
i
n
g
87
2
58
6
38
9
10
6
88
7
,
95
7
15
1
.
(3
6
.
08
)
%
La
r
g
e

P
o
w
e
r

S
e
r
v
i
c
e
10
5
97
8
82
4
.
23
7
06
3
,
57
3
39
3
,
25
0
28
.
2.
4
1
%
10
5
%
Ag
r
i
c
u
l
t
u
r
a
l

I
r
r
i
g
a
t
i
o
n

S
e
r
v
i
c
e
13
,
51
7
62
0
.
93
0
93
1
60
,
39
7
51
0
82
5
.
60
9
42
.
4
6
13
.
95
%
76
%
Un
m
e
t
e
r
e
d

G
e
n
e
r
a
l

S
e
r
v
i
c
e
22
4
16
,
05
4
.
94
2
90
7
,
68
9
82
1
53
4
51
.
(9
.
4
9
)
%

1
3
3
%
St
r
e
e
t

L
i
g
h
t
i
n
g
43
2
17
,
91
2
,
03
9
80
9
26
9
66
9
55
7
93
.
(7
.
72
)
%

1
2
6
%
Tr
a
f
f
i
c

C
o
n
t
r
o
l

L
i
g
h
t
i
n
g
38
4
.
21
8
28
4
.
14
5
29
2
03
6
31
.
78
%
10
5
%
To
t
a
l

U
n
i
f
o
r
m

T
a
r
i
f
f
s
40
1
.
67
2
11
,
07
0
,
13
5
03
2
45
8
60
8
19
4
48
4
47
6
,
7
0
8
43
.
64
%
10
0
%
Sp
e
c
i
a
l

C
o
n
t
r
a
c
t
s
:
Mi
c
r
o
n
63
6
96
7
67
0
16
.
20
4
,
10
4
80
2
,
80
6
24
.
(2
.
4
8
)
%

1
0
5
%
J
R

S
i
m
p
l
o
t
18
6
68
4
,
66
5
63
2
57
1
31
7
52
4
23
.
(6
.
80
)
%

1
0
5
%
DO
E
20
3
.
08
4
.
14
6
62
2
.
4
1
4
79
7
,
77
8
23
.
79
%
10
5
%
To
m
l

S
p
a
d
a
l

C
o
n
u
a
d
s
02
6
73
6
48
1
25
,
45
9
,
08
9
24
,
91
8
,
10
8
24
.
(2
.
12
)
%

1
0
5
%
16

To
t
a
l
l
d
a
h
o

R
e
t
a
i
l

S
a
l
e
s

40
1
.
67
5

1
2
,
09
6
87
1
.
51
3

4
8
4
,
06
7
28
3
An
o
m
a
l
y

I
n

th
e

Co
s
t

o
f

s
e
r
v
i
c
e

a
n
a
l
y
s
i
s

r
e
s
u
l
t
s

I
n

ne
g
a
t
i
v
e

C
D
S

I
n
d
e
x
50
9
39
4
81
6
42
.
23
%

10
0
%
IP
C
-
E
-
03
-
13

F
i
n
a
l

O
r
d
e
r
Su
m
m
a
r
y

o
f

R
e
v
e
n
u
e

I
m
p
a
c
t
St
a
t
e

o
f

I
d
a
h
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

e
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
,
20
0
3
Ap
p
r
o
v
e
d

B
a
s
e

R
a
t
e
s
Re
s
i
d
e
n
t
i
a
l

S
e
r
v
i
c
e
Sc
h
e
d
u
l
e

1
(1

)
(2
)
Cu
r
r
e
n
t
Ba
s
e
Ra
t
e
(3
)
Cu
r
r
e
n
t
Ba
s
e
Re
v
e
n
u
e
(4
)
Ap
p
r
o
v
e
d
Ba
s
e
Ra
t
e
(5
)
Ap
p
r
o
v
e
d
Ba
s
e
Re
v
e
n
u
e
(6
)
(7
)
Re
v
e
n
u
e
Di
f
f
e
r
e
n
c
e
Pe
r
c
e
n
t
Ch
a
n
q
e
Li
n
e
Us
e
De
s
c
r
i
p
t
i
o
n
Se
r
v
i
c
e

C
h
a
r
g
e
01
8
99
9
.
$2
.
$1
0
,
08
7
,
68
8
$1
3
.
26
2
.
69
8
$3
,
17
5
01
0
31
.
4
7
%
Mi
n
i
n
u
m

S
e
r
v

C
h
g
95
9
.
$1
.
26
,
95
9
80
,
87
7
53
,
91
8
20
0
.
00
%
Su
m
m
e
r

.c
:
:
:

30
0
k
w
h
25
7
.
62
3
.
90
5
04
9
3
0
3
12
,
70
1
63
1
05
0
5
8
5
03
1
90
5
33
0
27
4
60
%
Su
m
m
e
r
:
:
:
-
3
0
0

k
w
h
67
4
,
44
8
,
81
1
04
9
3
0
3
25
2
,
35
0
05
6
9
4
0
38
,
4
0
3
,
11
5
15
0
,
76
5
15
.
4
9
%
No
n
-
Su
m
m
e
r
20
9
32
0
71
0
04
9
3
0
3
15
8
,
22
9
13
9
05
0
5
8
5
16
2
34
3
,
4
8
8
11
4
,
34
9
60
%
To
t
a
l

k
W
h
14
1
,
39
3
,
4
2
6
20
4
,
18
3
12
0
21
3
,
77
8
,
50
8
59
5
38
8
70
%
su
m
m
e
r

d
i
f
f
e
r
e
n
t
i
a
l
00
6
3
5
5
12
.
56
%
Cu
s
t
o
m
e
r

A
d
j
.
(8
,
35
3
)
(8
,
35
3
)
00
%
To
t
a
l

B
i
l
l
i
n
g
$2
1
4
,
28
9
,
4
1
4
$2
2
7
,
11
3
73
0

$
1
2
,
82
4
31
6
98
%
IP
C
-
03
-
13

F
i
n
a
l

O
r
d
e
r
tV
)
tV
)
VI

a
VI

~
0\

I
""
"

N

U

~o
~
-
zo
'
8
Zp
:
:
;
Z
-
~~
~
P-
t
~
r
n
C
J
2J
~
Su
m
m
a
r
y

o
f

R
e
v
e
n
u
e

I
m
p
a
c
t
St
a
t
e

o
f

I
d
a
h
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

e
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
,

2
0
0
3
..
.
.
.
V)

~
0\

'
.q
-~d
~
-
Z
0

0
Z~
Z
N
~1
-
L
1
1
-
L
1
~~
U
)
C
)
cJ
~
Sm
a
l
l

G
e
n
e
r
a
l

S
e
r
v
i
c
e
Sc
h
e
d
u
l
e

7
(1
)
(2
)
(3
)
(4
)
(5
)
(6
)
(7
)
Cu
r
r
e
n
t
Cu
r
r
e
n
t
Ap
p
r
o
v
e
d
Ap
p
r
o
v
e
d
Li
n
e
Ba
s
e
Ba
s
e
Ba
s
e
Ba
s
e
Re
v
e
n
u
e
Pe
r
c
e
n
t
De
s
c
r
i
ti
o
n
Us
e
Ra
t
e
Re
v
e
n
u
e
Ra
t
e
Re
v
e
n
u
e
Di
f
f
e
r
e
n
c
e
Ch
a
n
Se
r
v
i
c
e

C
h
a
r
g
e
38
5
82
4
.
$2
.
$9
6
8
,
4
2
0
$3
.
27
3
,
22
2
$3
0
4
80
2
31
.
4
7
%
Mi
n
i
m
u
m

S
e
r
v

C
h
g
17
4
.
17
4
52
3
34
9
20
0
.
09
%
Su
m
m
e
r
:
:
-
3
0
0

k
w
h
23
4
13
1
05
9
6
4
9
93
6
76
7
06
8
5
3
8
37
4
,
4
0
9
43
7
64
2
14
.
90
%
Su
m
m
e
r

-:
:
3
0
0
24
1
,
21
0
05
9
6
4
9
14
7
,
71
9
06
0
8
4
2
17
0
,
67
4
95
5
00
%
No
n
-
Su
m
m
e
r
19
6
,
86
0
32
6
05
9
6
4
9
74
2
52
2
06
0
8
4
2
11

,
97
7
37
6
23
4
,
85
4
00
%
To
t
a
l

k
W
h
26
5
,
33
5
,
66
7
82
7
00
8
16
,
52
2
,
4
5
9
25
7
,
80
9
63
%
su
m
m
e
r

d
i
f
f
e
r
e
n
t
i
a
l
00
7
7
0
12
.
66
%
Cu
s
t
o
m
e
r

A
d
j
.
87
4
87
4
00
%
To
t
a
l

B
i
l
l
i
n
g
$1
6
,
79
8
,
4
7
6
$1
7
80
1
07
8
00
2
,
60
2
97
%
IP
C
-
E-
D
3
-
13

F
i
n
a
l

O
r
d
e
r
"'"
'
"'"
'
V)

0
V)

~
0\

I
Su
m
m
a
r
y

o
f

R
e
v
e
n
u
e

I
m
p
a
c
t
N
u

~
.
~
St
a
t
e

o
f

I
d
a
h
o
~
0

.
ZO
o
No
r
m
a
l
i
z
e
d

1
2
-
Mo
n
t
h
s

e
n
d
i
n
g

D
e
c
e
m
b
e
r

3
1
.

2
0
0
3
~~
Z
"
,
"
,
Ap
p
r
o
v
e
d

B
a
s
e

R
a
t
e
s
J.l
.
1
~~
~
p.
.
~
U
)
C
)
13
~
La
r
g
e

G
e
n
e
r
a
l

S
e
r
v
i
c
e
Sc
h
e
d
u
l
e

9

S
e
c
o
n
d
a
r
y

S
e
r
v
i
c
e
(1
)
(2
)
(3
)
(4
)
(5
)
(6
)
Cu
r
r
e
n
t
Cu
r
r
e
n
t
Ap
p
r
o
v
e
d
Ap
p
r
o
v
e
d
Li
n
e
Ba
s
e
Ba
s
e
Ba
s
e
Ba
s
e
De
s
c
r
i
ti
o
n
Us
e
Ra
t
e
Re
v
e
n
u
e
Ra
t
e
Re
v
e
n
u
e
ch
g
Se
r
v
i
c
e

C
h
a
r
g
e
20
3
,
54
8
.
$5
.
12
7
,
65
7
$5
.
13
9
87
0
Mi
n
i
m
u
m

S
e
r
v

C
h
g
51
6
29
0
58
0
10
0
%
Ba
s
i
c

C
h
a
r
a
e
Su
m
m
e
r
83
0
,
68
3
01
9
04
6
04
7
35
3
No
n
-
Su
m
m
e
r
91
0
,
00
8
84
7
60
3
92
6
70
3
To
t
a
l

B
a
s
i
c

C
h
a
r
g
e
74
0
,
69
1
86
6
64
9
97
4
05
6
De
m
a
n
d

C
h
a
r
a
e
Su
m
m
e
r
19
4
,
92
0
99
2
13
2
58
4
76
0
No
n
-
Su
m
m
e
r
13
3
,
44
5
74
4
,
30
5
16
,
74
4
30
5
To
t
a
l

D
e
m
a
n
d
32
8
,
36
5
73
6
,
4
3
7
23
,
32
9
06
5
En
e
r
Q
V

C
h
a
r
Q
e
Su
m
m
e
r
70
2
,
98
0
,
4
3
5
02
6
1
5
0
18
,
38
2
93
8
02
8
9
0
3
31
8
24
4
10
.
No
n
-
Su
m
m
e
r
96
4
,
39
5
,
80
2
02
6
1
5
0
51
,
36
8
,
95
0
02
5
7
8
4
64
9
98
1
1.
4
%
To
t
a
l

E
n
e
r
g
y
66
7
,
37
6
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Idaho Power Company
Summary of Revenue Impact
State of Idaho
Normalized 12-Months ending December 31, 2DD3
Approved Base Rates
Dusk to Dawn Customer Lighting
Schedule 15
(1)(2)(3)(5)(6)(7)
Current Current Approved ApprovedLineBaseBaseBaseBase
Descri tion Use Lames Rate Revenue Rate Revenue
Lames
100-Watt Sodium Vapor (A)664 282 108 117 $941 699 $603,293
200-Watt Sodium Vapor (A)526,020 746 14.109,451 101
200-Watt Sodium Vapor (D)586 867 547 17.146,837 11.017400-Watt Metal Halide (D)90,523 664 28.19,017 18.178400-Watt Sodium Vapor (A)156,334 144 22.797 14.16,519400-Watt Sodium Vapor (D)651 710 762 25.122,050 16.42 1921000-Watt Metal Halide(D)196,853 581 52.30,375 33.19,458
Total Com.llnd.872 589 131 561 395,226 893,758Minimum Charges 147 147 441
Customer Adj.(3)(6,267)(6,267)
Total Lamp Revenue 872 586 $1,389 106 $887 932
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 6 of 18
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Normalized 12-Months ending December 31,2003
Approved (Six Months) Base Rates
Large Power Service
Schedule 19 Secondary
(1)(2)(3)(4)(5)(6)
Current Current Approved ApprovedLineBaseBaseBaseBase
Descri tion Use Rate Revenue Rate Revenue chg
Service Charge 12.$5.$66 $5.$67
Basic Charge
Summer 777 720 $0.767
Non-Summer 13,918 010 $0.150
Total Basic Charge 18,695 730 917
Demand Charge
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On-Peak Summer 530 0 NA 0 NA
Non-Summer 12,400 852 32,736
Total Demand Charge 46,388 47,476
EnerQY Charge
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10 Mid-peak Summer 063,953 025576 212 0.028486 30,308 11.4%
Off-peak Summer 693 552 025576 17,738 0.028486 19,757 11.12 Total Summer Energy Charge 374 364 727 637 11.
13 Mid-peak Non-Summer 953,230 025576 101 108 0.025329 100 131
14 Off-peak Non-Summer 592,937 025576 317 0.025329 67715 Total Non-Summer energy charge 546,167 167 425 165,808
16 Total Energy Charge 920,531 228,152 233,445
17 Customer Adj.637 637
18 Total Billing $281,973 $288,542 33%
IPC-E-O3-13 Final Order
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-O3-
PAGE 10 ofl8
Summary of Revenue Impact
State of Idaho
Normalized 12-Months ending December 31,2003
Approved (Six months) Base Rates
Large Power Service
Schedule 19 Primary
(1)(2)(3)(4)(5)(6)
Current Current Approved ApprovedLineBaseBaseBaseBase
Descri ion Use Rate Revenue Rate Revenue chg
Service Charge 213.$85.$104,026 $125.$151,713 45.
Basic Char
Summer 103,973 850,059 $0.872,139
Non-Summer 303,749 543,887 $0.609.962Total Basic Charge 4,407,722 393,946 3,482 101
Demand Charae
Summer 970,688 572 323 028,547 17.On-Peak Summer 957,681 newNon-Summer 819,550 7,471,808 246.244Total Demand Charge 044 131 10,274,791
Enerav Cha
On-peak 126,670,888 0.020839 639 695 023403 964,479 12.
10 Mid-peak 213,686,573 020839 4,453,014 023403 000,907 12.
Off-peak 150,424 746 020839 134,701 023403 520,390 12.12 Summer Energy Charge 490,782,207 227 410 11,485,776 12.
Mid-Peak 843,585,690 020839 579,482 020603 17,380,39614 Off-peak 580,187,626 0.020839 090,530 020603 11,953,606
15 Non-Summer Energy Chrge 1.423,773,316 29,670,012 29,334,002
16 Total Energy Charge 914 555,523 39,897,422 40,819,778
17 Customer Adj (82,965)(82,965)
18 Total Billing $53,356,560 $54,645,418 42%
IPC-E-D3-13 Final Order
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 11 of 18
Summary of Revenue Impact
State of Idaho
Normalized 12-Months ending December 31, 2003
Approved (Six Months) Base Rates
large Power Service
Schedule 19 Transmission
(1)(2)(3)(4)(5)(6)
Current Current Approved ApprovedlineBaseBaseBaseBase
Descri tion Use Rate Revenue Rate Revenue chg
Service Charge 30.$85.597 $125.788 45.
Basic Char
Summer 21,154 250 $0.40 462
Non-Summer 683 856 $0.40 32,673
Total Basic Charge 102 837 106 41,135
Demand Charee
Summer 927 53,782 64,037 19.
On-Peak Summer 20,647 new
Non-Summer 75,313 193,554 189,036
Total Demand Charge 247,336 253,073
Enerev Charoe
On-peak 857 632 020375 58,224 022957 65,603 12.
Mid-peak 5,424,997 020375 110 534 022957 124,542 12.
Off-peak 228,895 020375 86,164 022957 083 12.
Summer Energy Charge 12,511 524 254,922 287,228 12.
Mid-peak 817 182 020375 485,275 020241 482,084
Off-peak 019,477 020375 387,522 020241 384,973
Non-Summer Energy Charge 42.836 659 872 797 867 057
16 Total Energy Charge 55,348 183 127 719 154,285
Customer Adj.282 282
18 Total Billing $1,425 040 $1,459 563 2.42%
IPC-E-O3-13 Final Order
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 12 of 18
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Bills-Out Season
Total In-Season
Total Out-Season
Total kW
Total In-Season
Total Out-Season
Total kWh
Customer Adj
Total Billing
Idaho Power Company
Summary of Revenue Impact
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Normalized 12-Months ending December 31 , 2003
Approved Base Rates
Agricultural Irrigation Service
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027021 030858
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APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 14 or18
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No.
Idaho Power Company
Summary of Revenue Impact
State of Idaho
Normalized 12-Months ending December 31, 2003
Approved Base Rates
Unmetered General Service
Schedule 40
(1)(2)(3)(4)(5)
Current Current Approved Approved
Base Base Base Base
Descri tion Use Rate Revenue Rate Revenue
Number of Bills 687.
Minimum Charges 566.$850 $850
Total kWh 16,054 942 05680 911 921 05143 825 706
Customer Adj.082)(5,082)
Total Billing $907 689 $821,474
APPE1'-.'DIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 16 ofl8
Idaho Power Company
Summary of Revenue Impact
Approved Base Rates
Street Lighting-Company Owned
Schedule 41
Non-Metered Service
(1)(2)(3)(4)(5)
Current Current Approved Approved
Line Annual Base Base Base Base
Descri tion LamDs Rate Revenue Rate Revenue
Sodium Va
100-Watt 168 346 072 364 957 889
200-Watt 23,907 177 868 158 982
250-Watt 098 8.42 245 268
40o-Watt 008 10.685 556
Total Sodium Vapor 194,359 270,162 134 695
Adjustment for
City of Ketchum Contract
70-Watt 238 683 504
100-Watt 636 859 344
Total City of Ketchum 874 542 848
Customer Adj (33 115)(33,115)
Non-Metered Company-Owned 243,589 107,428
Non-Metered Customer-Owned 565 680 562,034
Metered Company-Owned
Metered Customer-Owned
Total Street Lighting Revenue 809 269 669,462
15 Total Bills16 Total kWh
1,420
878,742
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 17 of 18
Idaho Power Company
Summary of Revenue Impact
State of Idaho
Normalized 12-Months ending December 31, 2003
Approved Base Rates
Traffic Control Lighting
Schedule 42
(1)(2)(3)(4)(5)
Current Current Approved ApprovedLineBaseBaseBaseBase
Descri tion Use Rate Revenue Rate Revenue
No. of Billings 696.
Traffic Lamps 384,218 $0.03105 $291,380 $0.03191 $299,450
Customer Adj.235 235
Total Billing $284,145 $292,215
APPENDIX 4
ORDER NO. 29505
CASE NO. IPC-03-
PAGE 18 of18
----------
Office of the Secretary
Service Date
June 2, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO PO~R COMPANY FOR AUTHORITY )
TO INCREASE ITS INTERIM AND BASE
RATES AND CHARGES FOR ELECTRIC SERVICE.
CASE NO. IPC-O3-
ERRATA TO
ORDER NO. 29505
On May 25, 2004, IPUC Order No. 29505 was issued by this Commission, The
following changes should be made to that Order:
Page 12, Paragraph 1 , lines 5-
READS:
The Commission generally believes that putting the known and measurable
adjustments in rate base for a full year creates a mismatch between revenues
and expenses in the test year if benefits are not needed too.
SHOULD READ:
The Commission generally believes that putting the known and measurable
adjustments in rate base for a full year creates a mismatch between revenues
and expenses in the test year if benefits are not included too.
Page 19, Paragraph 3 , lines 6-
READS:
The adjustments Idaho Power accepted included changes to pension
expense, memberships and contributions, year-end payroll, the Standard
Salary Adjustment (SSA), incentive pay, and depreciation. Exhibit 80,
SHOULD READ:
The adjustments Idaho Power accepted included changes to pension
expense, memberships and contributions, year-end payroll, the Salary
Structure Adjustment (SSA), incentive pay, and depreciation. Exhibit 80.
ERRATA TO
ORDER NO. 29505
Page 33, Paragraph 2, line 5
READS:
According to Staff, its proposal recognizes the higher tax expense ratepayers
will pay in future years when the tax timing turns around.
SHOULD READ:
According to Staff, its proposal recognizes the higher tax expense ratepayers
will pay in future years when the tax timing difference turns around.
Page 42, Paragraph 3, line 8
READS:
Dr. Peseau also suggested that investors do not widely share Dr. Avera
doom and gloom" outlook for Idaho Power or the industry, particularly
given that Idaho Power shareholders received a rate of return in excess of
40% in the last year over the 2003 year when including both price
appreciation and dividend yield,
SHOULD READ:
Dr. Peseau also suggested that investors do not widely share Dr. Avera
doom and gloom" outlook for Idaho Power or the industry, particularly
given that Idaho Power shareholders received a rate of return in excess of
40% over the 2003 year when including both price appreciation and dividend
yield.
Amended Appendices for Schedules 19 and 41 are attached.
DATED at Boise, Idaho this 02 "day of June 2004.
1(rilCommission Secretary
blslO:IPCE03 1 3jrnal errata
ERRATA TO
ORDER NO. 29505
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