20040426Post Hearing Brief.pdf

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LISA D. NORDSTROM (Idaho Bar No. 5733)
WELDON B. STUTZMAN (Idaho Bar No. 3283)
DEPUTY ATTORNEYS GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
Telephone: [phone]
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Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorneys for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF)
IDAHO POWER COMPANY FOR AUTHORITY)
TO INCREASE ITS INTERIM AND BASE)
RATES AND CHARGES FOR ELECTRIC)SERVICE. CASE NO. IPC-O3-
STAFF'S POST-HEARING
BRIEF
The Commission Staff, by its counsel of record, Lisa D. Nordstrom and Weldon B.
Stutzman, Deputy Attorneys General, file this Post-Hearing Brief as provided by the Notice of
Scheduling issued November 26 2003 and at the April 5, 2004 technical hearing. Tr. at 3199.
INTRODUCTION
On October 16 2003, Idaho Power Company (Idaho Power, Company) applied to the
Idaho Public Utilities Commission for authority to increase its rates and charges an average of
17.7% for electric service in the state of Idaho. The Commission held technical hearings to
receive evidence in this matter on March 29 - April 5 , 2004. Given the extensive record and
number of complex issues presented, Staff will focus its legal and factual arguments in this Brief
primarily on the Staff-proposed tax, annualized, known and measurable, and pension
adjustments. Staff s failure to address an issue should not be construed as acceptance or
rejection of a particular position. Based on the record in this case and the Commission
experience in such matters, Staff asks that its recommendations be adopted for the reasons
described in greater detail below.
STAFF'S POST-HEARING BRIEF
LEGAL STANDARDS
The Commission is specifically delegated broad authority to regulate and fix the
charges assessed by a public utility for service. Idaho Code ~~ 61-502 , 61-503. The Idaho
Supreme Court has long recognized that the Commission has broad discretion in designing rates
allowing the Commission to rely on its own expertise so long as it refers to matters in the record
to substantiate its conclusions or place such matters in the record itself. Boise Water Corp.
Idaho PUC 97 Idaho 832, 842, 555 P.2d 163, 173 (1976).
In its decision-making, the Commission must consider the public interest and the
justice, fairness and equity of the rates it establishes. This result is mandated by Idaho Code
61-301 , which provides that all charges made by a public utility shall be rendered just and
reasonable. See also, Idaho Power Company v. Idaho PUC 99 Idaho 374, 582 P.2d 720 (1978);
Citizens Utilities Company v. Idaho PUC 99 Idaho 164, 579 P.2d 110 (1978); Idaho State
Homebuilders v. Washington Water Power 107 Idaho 415 690 P.2d 530 (1984).
From a broader perspective, the Commission must also keep in mind "the overall
effect of the rate fixed to determine whether the return to the utility is reasonable and just."
Intermountain Gas Co. v. Idaho PUC 97 Idaho 113 , 120, 540 P.2d 775, 781 (1975). As the
United States Supreme Court stated in Federal Power Commission v. Hope Natural Gas Co.
320 US. 591 64 S.Ct. 281 , 88 LEd. 333 (1944):
It is not theory but the impact of the rate order which counts. If the total effect
of the rate order cannot be said to be unjust and umeasonable, judicial inquiry
under the Act is at an end. The fact that the method employed to reach that
result may contain infirmities . is not then important. Moreover, the
Commission s order does not become suspect by reason of the fact that it is
challenged. It is the product of expert judgment which carries a presumption
of validity. And he who would upset the rate order under the Act carries the
heavy burden of making a convincing showing that it is invalid because it is
unjust and umeasonable in its consequences.
Thus, the minute details of each Commission decision are of less significance than: 1) the overall
effect the ratemaking Order will have on ratepayers; and 2) ensuring that the effect of the Order
will not be umeasonable or unjust to the utility.
STAFF'S POST-HEARING BRIEF
IN CO ME TAX ADJUSTMENTS
A. Background
It almost goes without saying that federal income tax laws are complex and often
opaque to those unfamiliar with them. For that reason, the Idaho Supreme Court included the
following explanation of normalization and flow-through accounting in the Application of Utah
Power Light Company:
Federal income tax laws permit regulated utilities to depreciate their
investments in utility property under accelerated methods rather than straight-
line methods. In the straight-line method of depreciation, the utility deducts
from its taxable income equal annual amounts of depreciation over the life of
the asset, whereas in accelerated methods the utility deducts greater amounts
initially and smaller amounts during the later years of the asset's life. For
ratemaking purposes, regulatory bodies generally allow utilities to charge
ratepayers depreciation expenses for their investment under straight-line
methods. Thus, a public utility may elect the benefits of accelerated
depreciation for income tax purposes but depreciate the property for
ratemaking purposes under the straight-line method. When this occurs
regulators choose one of two methods to account for the difference in
depreciation for federal income tax and regulatory purposes. These two
methods are known as "normalization" and "flow-through" accounting.
Normalization occurs when a utility uses an accelerated depreciation
method for income tax purposes, but calculates its tax expense for
ratemaking purposes as if it had taken straight-line depreciation. Thus
in the early years of an asset's life the utility collects more from its
ratepayers than it actually pays in taxes. This excess amount is usually
credited to a reserve account for deferred taxes.... Th(isJ reserve account
provides a source of funds, for accounting purposes, with which to pay
the utility s increased tax bills during the later years of the asset's life.
This increased tax liability is caused by the fact that, under a
normalization of accounting for ratemaking purposes, a crossover point
is reached when actual taxes paid by the utility begin to exceed
revenues collected for taxes. New England Telephone Telegraph Co.
v. Public Utilities Commission 390 A.2d 8, 18-19 n. 4 (Me. 1978).
Flow-through is a ratemaking technique by which rates are based upon
the actual taxes to be paid in that year by a utility taking accelerated
depreciation. The tax "savings are credited to income, thereby
reducing the utility s revenue requirement. In theory, this results in
lower rates during the early years of an asset's useful life, but in higher
rates after the cross-over point has been reached. 390 A.2d at 19 n. 6.
107 Idaho 446, 449, 690 P.2d 901 903 (1984).
STAFF'S POST-HEARING BRIEF
It should be noted that the issue of depreciation discussed by the Court is not the
same as the tax windfall found in the current Idaho Power rate case. Under the tax methodology
change discussed below, the Internal Revenue Service (IRS) allowed Idaho Power to expense
formerly capitalized assets using either the normalization or flow-through method. The Court'
explanation above is relevant to demonstrate the concept that depreciation expense can be treated
one way for tax purposes and another for ratemaking purposes, as Staff s proposed tax expense
treatment does in this case. Moreover, both issues involve an upfront benefit followed by a
cross-over point" with higher costs later. As explained more fully below, customers will not
receive the upfront benefit with Idaho Power s flow-through method but will pay the resulting
higher costs later. As with the above Court case, lower tax rates in the early years are a
significant part of the reasonableness of the overall tax impact.
B. The Staff's Tax Adjustments
1. Prospective Adjustment for Windfall Refund Effects
In March 2002, Congress enacted the Job Creation and Worker Assistance Act of
2002. The purpose of the Act was to provide tax incentives to stimulate the economy following
the attacks of September 11 , 2001. Pub. Law. 107-147 (2002). One provision of the Act
allowed Idaho Power to change its tax methodology to expense formerly capitalized assets using
either the normalization or flow-through method. This change produces an immediate one-time
tax refund or windfall in the year the taxpayer filed its return. In exchange for this immediate tax
refund, the windfall is recovered on a prospective basis over the remaining lives ofthe assets. In
other words , the tax adjustment is really a timing difference - not a permanent tax benefit. The
immediate windfall will result in an immediate increase in taxable income in future years that
will cause the repayment of the timing difference.
The new tax method allowed Idaho Power to assign a portion of the indirect
overhead expenses 1 that had been capitalized since 1987 to inventorY costs, which are
immediately expensed. The new methodology decreased Idaho Power taxable income by
allowing the Company to report additional expenses for income tax purposes during the prior
years 1987-2000. The tax change was effective in the tax year of change, 2001 , which created a
1 These indirect overhead expenses include items such as supervisor salaries, engineering fees, consultants, building
costs and other items.
2 The only inventory Idaho Power has is electricity.
STAFF'S POST-HEARING BRIEF
significant tax deduction recorded on the Company s books in 2002. Tr. at 2905, 2929. The
practical effects of this voluntary methodology change resulted in Idaho Power overpaying its
previously paid income taxes for 1987 to 2000. Thus, the Company collected a refund on taxes
paid in prior years, creating a $41 million income tax windfall in 2002. The change also means
that income taxes in future years will be higher because there are fewer capitalized assets to
depreciate for tax purposes.
a. An Inequitable Result:
Over the long-term, this methodology change will be dollar-neutral for the Company.
However, because there is a timing difference, ratepayers do not share in the $41 million refund
of taxes already paid in 1987-2000 because the one-time benefit occurred outside the 2003 test
year. Even though ratepayers paid these income taxes through rates between 1987 and 2000, the
Company has made no provision to share this windfall with ratepayers. Adding insult to injury,
ratepayers will ultimately pay higher future taxes once the timing difference reverses. While
Staff believes the methodology change was legal under the IRS Code, the Company s choice to
change its tax methodology and to flow the refund through in a single year outside of the rate
case test year is neither just nor reasonable ratemaking for the future without some sort
adjustment to recognize the additional costs that ratepayers will experience in future years.
Without an adjustment, ratepayers will be disadvantaged twice: once when the Company failed
to share the tax windfall, and once again when tax expense increases in the future.The
Company chose a partially projected 2003 test year in large part to flow the tax benefit through
to earnings in 2002 without sharing it with customers. Moreover, Idaho Power has made no
secret of the fact that IDACORP needed the benefit to increase earnings and pay its dividend to
its shareholders. Tr. at 391-92.
If the Commission allows Idaho Power to keep the $41 million one-time benefit
without recognizing the resulting future cost that ratepayers will bear, other utilities may be
emboldened to disregard the long-term effects that their short-term choices have on ratepayers.
The Company argues that Commission precedent prevents the Commission from taking action to
offset the higher ratepayer costs in the future. Although it was legal to change the tax
methodology for income tax purposes, it was not reasonable, prudent or equitable of Idaho
Power to do so without some sort of sharing to recognize the 14 years of ratepayer contributions
that allowed such a windfall to occur. It is certainly inequitable for Idaho Power to argue that
STAFF'S POST-HEARING BRIEF
ratepayers should pay higher future tax expenses created by the windfall enjoyed by
shareholders.
Idaho Power has known for some time that Staff did not agree with the ratemaking
impact of the flow-through methodology it chose to book the tax methodology change. In its
draft audit of the test year 2001 , Staff stated that it would oppose the Company s treatment of the
tax change and seek a corresponding benefit for customers. At that time, both Staff and Idaho
Power agreed that the earnings boost would be beneficial to Idaho Power but that customer
benefits would need to be addressed in the rate case. Staff s proposed adjustment addresses
those customer benefits.
b. Staff's Proposed Adjustment:
As set out in testimony, Idaho Power used effective rates of 32.795%3 for federal and
9% for state income taxes. Tr. at 580. Staff argued that the Commission should instead use the
year average tax rates of 25.24% for federal and 5.62% for state to calculate tax expense for
ratemaking purposes. Tr. at 1438. Staff believes this adjustment will recognize and make
ratepayers whole for the increased taxes they will be required to pay in the future as a result
the one-time benefit taken by the Company.
Staff s proposed use of an average tax rate is not unusual and is a method frequently
used by the Commission to establish rates when circumstances require a proxy to achieve a just
ratemaking result. For example, rate base accounts are averaged to smooth out the swings
between beginning and ending periods and to provide a better matching of revenues and
expenses. Gas and electricity sales and costs are set using weather-normalized amounts that are
based upon average weather conditions. Expenses that fluctuate from year to year are often set
at levels that are different from actual test year expenses. It has also been a long-standing
Commission practice to average or normalize water-testing expenses for water companies.
Given their fairness and frequency of use, it is not umeasonable under the circumstances
presented in this case to use multi-year averages to set tax rates as well.
c. IRS Normalization Requirement Is Not Violated:
Despite the Company s assertions to the contrary, Staffs adjustment does not violate
the IRS's normalization requirement because it is for ratemaking purposes only. The IRS does
3 The Company s 32.795% effective tax rate is calculated using the statutory rate of 35% less the deductibility of the
9% state income taxes.
STAFF'S POST-HEARING BRIEF
require that certain types of tax changes must be normalized. Those items include accelerated
depreciation, CIAC and investment tax credits. This capitalized overhead tax methodology is
not subject to the normalization requirement. Tr. at 2927. Idaho Power had the discretion to
either normalize the effect of the tax change or to flow it through because neither IRS regulation
nor Commission Order required a specific tax treatment. Even if the Commission were now to
require something different for ratemaking purposes (e., an average rate or normalization),
Idaho Power may continue to use the flow-through methodology for income tax purposes.
normalization violation exists when benefits are flowed to ratepayers faster than allowed by IRS
normalization requirements. This would not occur under Staff s proposal unless Idaho Power
also assumes some other change.
Both PacifiCorp and Avista recognized the complicated ratemaking ramifications
associated with the flow-through methodology and consequently have or will normalize the tax
change. Tr. at 2921. Although Idaho Power referred to Idaho as a "flow-through" state, Idaho
Power normalizes tax adjustments in some instances and flows through adjustment items in
others - just as all other utilities do. The IRS did not require the Company to immediately flow
the windfall through to earnings; Idaho Power could have normalized the tax change.Tr. at
2926. Neither was there an Idaho requirement for flow-through treatment, despite the
Company s claims it was required to do so by past Commission decisions.5 Tr. at 2926. When
Idaho Power decided to seek this tax change with the associated windfall, it did its own analysis
comparing the merits of flow through and normalization.6 Idaho Power did not seek an official
determination from the Commission; it simply made the choice on its own after evaluating the
risks.
4 Temporary non-depreciation differences like this methodology change may be recovered under either of the two
methods. See IRC 9 168(f)(2).
5 As discussed below, Idaho Power relies on prior Commission Orders that do not directly apply to this situation.
Even if such Orders where applicable, the Commission is free to change its policies as events change. Rosebud
Enterprise v. Idaho PUC 128 Idaho 609, 917 P.2d 766 (1996); Intermountain Gas Co. v. Idaho PUC 97 Idaho 113
540 P.2d 775 (1975).
6 As part of its review of the tax change before the rate case, Staff reviewed a confidential Idaho Power management
discussion paper entitled
, "
Final Discussion and Analysis for Management - Tax Accounting Method Change
Project" This document contained a summary of the tax change, a list of risks involved and an analysis of past
Commission Orders relating to tax treatments.
STAFF'S POST-HEARING BRIEF
Regardless of whether Idaho Power s election to use flow-through methodology for
tax purposes is affected by the Commission s effort to offset the corresponding future costs to
ratepayers, the appropriateness of such an adjustment is unchanged. This ratemaking decision
must be based on its own merits, not speculation regarding future IRS actions.
d. Adjustment Is Not Retroactive Ratemaking:
Despite Company arguments to the contrary, Staffs proposed adjustment is not
retroactive ratemaking because it will offset income tax expense customers will have to pay in
the future, not recover amounts taken by Idaho Power in 2002. Idaho Power cites Utah Power
Light v. Idaho Public Utilities Commission 685 P.2d 276, 107 Idaho 47 (1984) for the
proposition that there is a general prohibition against setting rates based on previous periods of
umeasonably high or umeasonably low rates. Idaho Power further argues that it is retroactive
ratemaking to take into account previous extraordinary revenues or expenses that will not
reoccur. Tr. at 2941-42. However, this argument ignores the fact that Staffs proposal
prospectively adjusts for known and measurable tax rate changes that will occur in the future.
Although these tax changes are capable of being measured, Staff has not been able to calculate
the exact timing or amounts of the adjustment. The Staff s adjustment is intended to insure that
ratepayers are not paying income taxes twice: in 1987-2000 before the methodology switch and
again after the timing reversal when the methodology change will cause increased tax expense.
Idaho Power witness Larry Ripley testified that the Commission has ruled in the past
that an adjustment to its rates or revenue requirement is appropriate when taking into account a
change in newly enacted income tax rates that were prospective, not retroactive. Tr. at 2944-45.
Although Idaho Power statutory tax rates have not changed, Staff is asking that the
Commission similarly adjust Idaho Power s rates or revenue requirement to reflect a change in
tax methodology that affects the test year and each future year. Although Staff proposes use of a
year average as a proxy to calculate the future effects of the methodology change, Staff does
not recommend that the $41 million one-time benefit in 2002 be seized - only that ratepayers not
be forced to pay it again in the FUTURE. Thus, the economic impact on both Idaho Power and
ratepayers will be neutral over time.
e. Company-Cited Precedent is Inapplicable:
Order Nos. 25339 and 21364 cited by Mr. Ripley are not analogous to the present
case and refer to an entirely different situation - mandatory tax rate changes that had no effect on
STAFF'S POST-HEARING BRIEF
future deductions. Tr. at 2945. Because this voluntary methodology change will have the effect
of increasing future income taxes by reducing future depreciation deductions, use of the statutory
income tax rate will not incorporate the far-reaching impacts of the methodology change as it
would with a tax rate change. Therefore, the past practice Idaho Power refers to is dissimilar to
the present case and not binding upon the Commission. Because the Company s methodology
change appears to be a case of first impression, the Commission is not required to apply
currently enacted income tax rates that will ignore future tax consequences resulting from Idaho
Power s choice to flow-through the change rather than normalize it. Rosebud Enterprise
Idaho PUC 128 Idaho 609, 917 P.2d 766 (1996); Intermountain Gas Co. v. Idaho PUC
Idaho 113 540 P.2d 775 (1975).
One Order that the Company used to justify the flow-through methodology was Order
No. 20610. In that case, Idaho Power was ordered to flow-through certain capitalized overhead
and repair allowance tax items. The Order states in part:
Capitalized overhead and repair allowances are more like ongoing operating
expenses than long-term capital investments. It is reasonable to flow-thru tax-
book timing differences associated with them.
Order No. 20610 at 37.
In some regards, Idaho Power recent tax methodology change is similar to the
capitalized overhead and repair allowances mentioned above. However, there is a significant
difference - customers were able to receive some of the benefit from the flow-through
methodology before they had to pay increased taxes later. In this case, Idaho Power has taken
the large benefit, withheld it from customers by purposefully selecting 2003 as a test year, and
then fails to recognize the additional expense customers will bear in the future.
Moreover, the Commission has broad latitude to change its orders and policies as
conditions and circumstances change. The current Commission is not obligated to rule a certain
way solely because a prior set of Commissioners made a different decision many years ago.
Departure from past Commission rulings, in and of itself, is not an arbitrary act on the part of the
Commission. According to the Idaho Supreme Court:
(AJn agency must at all times be free to take such steps as may be proper in
the circumstances irrespective of its past decisions. Even when conditions
remain the same, the administrative understanding of those conditions may
change, and the agency must be free to act." So long as the Commission
STAFF'S POST-HEARING BRIEF
enters sufficient findings to show that its action is not arbitrary and
capricious, the Commission can alter its decisions.
Washington Water Power Co. v. Idaho Public Utilities Commission 101 Idaho 567, 579, 617
P.2d 1242, 1254 (1980) (quoting 2 Davis Administrative Law Treatise ~ 18.09 at 610 (1958)).
Cases Supporting Staff's Adjustment:
In a 1982 case, the Commission denied an acquisition adjustment requested by Utah
Power & Light to convert acquired assets from flow-through to normalization accounting. The
Commission determined that the acquisition adjustment was paid merely to recapture accelerated
depreciation and investment tax credit, the benefit of which accrued solely to the acquired
company s former ratepayers. The Commission further found that the limited benefit of the
acquired plant to Idaho ratepayers did not justify adding the acquisition adjustment to Idaho rate
base. Order No. 16702. The Idaho Supreme Court upheld this decision on appeal. Utah Power
Light Co. v. Idaho Public Util. Comm.107 Idaho 446, 690 P.2d 901 (1984). Like Utah
Power s requested acquisition adjustment, Idaho Power s tax methodology change will require
ratepayers to pay higher taxes in the later years of the asset's life for benefits received by others
under the flow-through methodology. Recognizing this injustice, this Commission should adopt
Staff s proposed adjustment or craft one of its own.
Two years later in Case No. U-I000-, the converse situation occurred: Mountain
Bell transferred assets to other companies after using normalization for ratemaking purposes and
after collecting revenues for future tax liabilities connected with those assets. To balance this
inequity between Mountain Bell and its ratepayers, the Commission directed Mountain Bell to
adopt an accounting adjustment to amortize over 10 years an amount equal to the deferred tax
accumulations collected from intrastate rates and associated with assets that had been transferred
to AT&T. Order No. 18872. The Commission reasoned that such an adjustment was necessary
because Mountain Bell retained the benefits of funds provided it by ratepayers after the transfer
with no obligation to return those funds to ratepayers. The Commission found:
The fact is that charges to the ratepayers should have decreased as a result of
the election of accelerated depreciation but because of the implementation of
normalization, the ratepayers did not see a decrease. They, in fact, have paid
more tax expense to the company than the company has had to pay the federal
government. The company readily admits that this is a source of capital to it.
The commission tried to maintain a balance of fairness by subtracting the
amount of the deferred taxes from rate base so that at least the ratepayers were
STAFF'S POST-HEARING BRIEF
not required to pay the company a return on ratepayer-provided funds. We
find that the ratepayers paid in and the company had the use of, and still retain
the benefit from money that was to pay tax expense that, in actuality, was not
paid.
Order No. 18872 at 33-34.
The Commission and Mountain Bell subsequently negotiated a settlement to the state
Court appeal issues in 1988 in order to avoid further litigation. Order No. 21774. A similar
adjustment, be it Staff s proposal or another, must be adopted in the present case as well. If the
Commission chooses to disregard the proposals of Idaho Power and Staff, the Commission can
rely on its own expertise to craft fair, just, and reasonable rates in its ratemaking capacity. See
Boise Water Corp. v. Idaho PUC 97 Idaho 832, 842, 555 P.2d 163 , 173 (1976).
2. Gross-Up Multiplier
The gross-up multiplier is used to calculate income taxes on the projected revenue
deficiency that results when newly authorized earnings exceed actual earnings.Staff
recommended the Commission reduce the Company s gross-up factor from 1.642 to 1.446 so
that the gross-up rate will be the same as the effective rate. Although there was some confusion
regarding the use of Idaho Power s "effective tax rate " Idaho Power is proposing to use the
statutory rate of 35% in the gross-up factor, even though it used the effective rate of 32.60% to
calculate the income tax expense for 2003. Tr. at 2951-52. Idaho Power argues that Staffs use
of a net-to-gross tax multiplier based upon a five-year hybrid tax ratio will not adequately
reimburse Idaho Power for the income taxes it will pay on revenues that result from this case or
from new customers.
As Staff witness Alden Holm stated in his testimony, Staff believes that it is more
appropriate to use Idaho Power s actual effective tax rate for the gross-up factor than the strict
statutory rate because it is a more accurate method for calculating income tax. Tr. at 1439-1440.
In the recent past, the Company has not paid the strict statutory rate of 35% for taxes and will not
pay the statutory rate in the future because of many tax deductions and additions. Tr. at 2924-
25. In the event the Commission decides to use the statutory rate as adjusted by Idaho Power to
calculate income tax expense, it would still be appropriate to use the actual effective tax rate
adjusted for the deductibility of the state taxes for the gross-up factor because the effective rate
STAFF'S POST-HEARING BRIEF
(32.60%) is more reflective of expected income tax expense in the near future than the statutory
rate.
3. Deferred Taxes in Rate Base
When it receives accelerated tax benefits, the Company records deferred tax liabilities
to acknowledge the existence of future tax liabilities that result. Until the deferred taxes are
absorbed by future tax payments, these deferred taxes are considered to be "cost free" financing
and are used to reduce rate base.In other words, deferred taxes are booked because the
Company took tax benefits early that will have to be paid back later.Staff proposed the
Commission reduce deferred taxes by $352,405 after computing the deferred income tax using
Staffs five-year averaged effective income tax. Supra at 3-10. On rebuttal Idaho Power argued
that application of Staffs five-year hybrid tax ratio to deferred income taxes will cause the
current year change for accelerated depreciation to be valued at something other than the
statutory rate - thus violating the IRS's normalization requirement. Tr. at 2915-17. However
Staff proposals do not violate the IRS's normalization requirement as discussed above at pages
6- 7. This is an area where Staff encouraged the Company to provide additional information or
suggest an alternate adjustment to ensure that a violation does not occur. Tr. at 1484, 1847.
Although the Company claims the recomputed reserve for deferred income taxes
would increase the Company s rate base by approximately $53 million as the net deferred tax
liability balance would drop due to the application of the lower rate, the Company offered no
documentation or evidence to support this claim. Tr. at 2917. Staff does not accept this number.
Consequently, the Staff stands by its calculation using the Company s primary worksheet in this
case until presented with other convincing evidence to the contrary.
4. Additional Tax Assessments
When the IRS periodically audits the Company s income taxes, the IRS may assess a
tax deficiency for underpaid income tax during the three-year period. The IRS audits usually
occur every three years. When there is a deficiency, this is recovered in the rates paid by
ratepayers.
Although it plans to keep the income tax benefits from 2002, Idaho Power wants
ratepayers to pay $2.9 million in base rates for additional taxes owed for 1998-2000. While Staff
7 Staffs proposed 1.577 gross up rate uses the actual 2003 effective tax rate of 32.60% as compared to the
Company-requested 1.642 gross up that uses the statutory rate of 35%.
STAFF'S POST-HEARING BRIEF
recognizes that these assessments are legitimate expenses, there are two problems with the
Company s proposal: one is a timing issue and the other flows from the Company s 2002
windfall. As a timing issue, Staff believes that ratepayers should pay these expenses just once
over the Company s three-year audit cycle - not each and every year. Therefore, Staff
recommends that the Commission should instead use the three-year average of additional tax
payments to reduce $1 960 529 from federal and add $55 846 to state tax test year expense. Tr.
at 1440-43. As Staff explained above, it is common for the Commission to use an averaging
approach to include expenses in revenue requirement when the test year results are skewed.
On rebuttal, Idaho Power noted that the Commission previously ordered in Order No.
17499 that any income tax deficiencies actually paid the test year be included in the regulatory
tax expense. Tr. at 2915 , 2917-48. Staff would note that our proposal does not exclude tax
deficiencies from recovery in the revenue requirement - it merely allows for the Company s fair
recovery of these three-year deficiencies once rather than each and every year until the next rate
case.
The second problem is related to the windfall tax refund the Company received in
2002. When the IRS conducts its audit for the Company s 2001 tax year, the Service may assess
a deficiency for calculation of the windfall. If this were to occur, Idaho Power ought not be
allowed to recover the deficiency from ratepayers. Ratepayers have already paid the taxes for
1987-2000, they did not share in the 2002 windfall refund, and they will (unless adjusted) pay
higher rates in the future due to this new tax methodology change that causes less deductions and
higher taxable income in future years. The Commission s Order in this case should prohibit this
inequity as it relates to the Company s decision to change its tax methodology.
ANNUALIZING AND
KNOWN AND MEASURABLE ADJUSTMENTS
There are two kinds of test year adjustments. First
, "
annualizing" adjustments are
made to reflect changes that occur within the test year and adjust account balances as if the
changes were in effect for the full test year. Second
, "
known and measurable" adjustments are
made to reflect changes that occur after the test year and adjust account balances as if the
changes were in effect for the full test year. In this case, both types of adjustments effectively
treat plant additions to rate base as if the plant were in service during all the months of the
averaging period. As discussed below, the Commission has adopted these types of adjustments
STAFF'S POST-HEARING BRIEF
in prior cases as it determined the appropriateness of using average-year value or end-of-year
value for establishing rate base.
1. Company-Proposed Adjustments
a. Annualizing:
Idaho Power seeks a net annualizing adjustment to average rate base to account for
major production and transmission plant additions placed into service during the last trimester of
the 2003 test year. The requested adjustments would increase rate base by $19 779 389 and
expenses by $873 129. Tr. at 528. On rebuttal, the Company argued that it should be allowed to
include the total cost of the plant additions in rate base because customers will receive the benefit
of these assets being in service on a going forward basis. Idaho Power claims these plant assets
are non-revenue producing and non-expense reducing. Tr. at 2786-, 3153-56.
b. Known and Measurable:
Idaho Power also asked that average rate base be increased for a known and
measurable adjustment in the amount of $18 388 690 for major plant additions of transmission
assets placed into service after the end ofthe test year, but before the issuance of an Order by the
Commission on the rate case. Tr. at 530. On rebuttal, Idaho Power argued that it is consistent
with past Commission actions to include the total cost of the plant if they come into service
within a short period of time after the rate case. According to the Company, Valmy I and Swan
Falls were examples of prior known and measurable adjustments to the test year. Moreover
Idaho Power argued this is equitable because customers receive investment benefits now even
though the plant additions may not produce revenues. Tr. at 2786-3153-56.
2. Staff-Proposed Adjustments
a. Annualizing:
Staff recommends denial of both Company-proposed annualizing adjustments - the
addition to rate base and the increase to expenses. The Commission has consistently ordered the
use of the "average" rate base rather than other methods because it provides a better matching
between rate base, revenues and expenses. The Company-proposed annualization adjustment
treats the plant additions as if in service for the full 13 months of the average. However, the
revenue and expenses associated with the plant additions are not included in the Company-
proposed end-of-year rate base, thus creating a mismatch between investment and test year
expenseslbenefits.
STAFF'S POST-HEARING BRIEF
For example, the newly rewound Bridger generator #3 will generate power more
efficiently and cost less to repair and maintain in the future. Tr. at 1585-86. Although the
Company claims that the efficiencies and benefits are reflected in the power supply cost model
(Tr. at 2802), the matching is still incomplete for two reasons. First, this model does not show a
separate adjustment was made. Second, the availability input data and generation output data
for Bridger Unit #3 remained the same as for the other Bridger units. Consequently, there is a
mismatch between rate base and expenses/benefits.
Another transmission plant example is ratebasing the Brownlee-Oxbow transmission
line. While including the cost of the line in rate base, the Company has not factored in: 1)
additional wheeling revenues from third parties, 2) reduced delivery costs of purchased energy,
or 3) minimized the cost to deliver Company-generated energy. Maintenance and repair
expense for transmission lines will also decrease. Tr. at 1585-88. Use of the Staff-proposed
average rate base methodology would avoid determinations of whether plant was "revenue
producing" or "expense saving," and consequently remove both the $19 779 389 increase in rate
base and the $623 915 increase in expenses8 proposed by Idaho Power. Tr. at 1552.
Micron witness Dennis Peseau agreed with Staff that the Company-proposed
annualization adjustment created a clear mismatch of revenues and expenses.Rather than
recommending disallowance of the Company s proposed adjustments as Staff did, Dr. Peseau
argued that this mismatch occurred because revenues are centered on June 30, 2003 due to
hybrid test year while rate base and expenses are centered on December 31 , 2003. Tr. at 2426 -
2428. Dr. Peseau s solution to this mismatch is to assume a 4.06% revenue growth rate and
annualize revenues to year-end levels. Micron s annualizing adjustment would add $9 731 765
to IPC test year revenues. Tr. at 2428 - 2430.
b. Known and Measurable:
Staff argued that Idaho Power should not increase rate base for the full amount of the
plant additions placed in service after the test year. Staff proposes that these additions be
included in rate base by reflecting the cost of the additions in the 13-month averaging
methodology. As a result, the cost of the additions would be included in the December 2003
8 $623 915 is the sum of the following disallowed expenses: depreciation of $498 427; property taxes of$120 654;
and insurance expense of $4 834.
STAFF'S POST-HEARING BRIEF
monthly rate base. This methodology provides a better matching of revenues and expenses for
these rate base additions than if they were included at the full value expected when placed in
servIce.
For example, 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 stations. Tr 1589 - 1593. However, these revenue
producing and expense saving benefits are currently unaccounted for in the Company-proposed
test year adjustments. If adopted, Staffs proposed adjustment to value these plant additions at
average-year amounts would remove $16 974 175 from the Company s proposed rate base
increase of $18 388 690 (i., Staff would limit the increase in rate base to $1,414 515). Tr. at
1556.
Like Staff, Micron witness Dr. Peseau disagreed with the Company s proposed
known and measurable adjustments for major plant additions.He 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 IPC has made no effort to quantify
offsetting revenue benefits like the embedded cost of long-term debt. Tr. at 2436. Micron
proposed adjustment would reduce Idaho revenue requirement by $11 768 222. Tr. at 2438.
3. The Commission s Average Rate Base Standard
The Commission has generally held that all major utilities should determine rate base
for a rate case on an average rate base value as opposed to determining rate base on an end-of-
year value. In most cases, the averaging methodology is an average of the monthly rate base
amounts for a 13-month period spanning the test year. The Commission articulated its
preference for this averaging standard in Washington Water Power Case No. U-I008-234
decided February 1986:
The earlier justifications for the year-end rate base no longer exist. Periods of
high inflation and intense construction are over. Further, the average rate base
provides a better matching of revenues and expenses with fewer chances for
error or omission. Therefore, we find it is fair, just and reasonable to require
Water Power to utilize an average rate base, the same as every other major
utility that we regulate in Idaho.
Order No. 20267 at 5.
STAFF'S POST-HEARING BRIEF
The Commission s use of average-year rate base has been upheld by the Idaho
Supreme Court as being permissible and within the discretion of the Commission. See Citizens
Uti!. Co. v. Idaho Public Util. Comm.99 Idaho at 171-172, 579 P.2d at 117-118 (1978); Utah
Power Light Co. v. Idaho Public Util. Comm.105 Idaho 822, 673 P.2d 422 (1983). Staffs
proposal to use average-year rate base should not surprise Idaho Power.The Commission has
consistently used average-year rate base in the last three Idaho Power rate cases. See Order No.
17499 at 31 (Case No. U-I006-185 decided August 1982), Order No. 20610 at 49 (Case No. U-
1006-265 decided July 1986), and Order No. 25880 at 5 (Case No. IPC-94-5 decided January
1995).
Although it has consistently approved the average-year rate base with the few notable
exceptions discussed below, the Commission has heard arguments for year-end rate base before.
In Boise Water Case No. U-I025-51 decided in June 1986, Boise Water Corporation indicated it
would support the use of an average rate base only if "non-revenue producing or non-expense
reducing plant" is included at year-end levels. The Commission noted that:
In terms of cash flow all depreciable investments are revenue producing.
addition, the difficulty and subjective decision-making process in determining
what classes of property are or are not "revenue producing" or "expense
saving" presents a quagmire into which we decline to step.
Order No. 20592 at 7.Quoting from Order No. 19902 issued a year earlier in 1985 , the
Commission went on to find that the following rationale still applied to support use of an average
rate base:
The Company is not experiencing the explosive growth that it experienced in
the 1970s and is not suffering the effects of the double-digit inflation of the
early 1980s. Moreover, Boise Water does not ordinarily increase its rate base
through very large, discrete construction projects, as do electric utilities.
When it did make such an addition - such as the Ranney collector put into
service approximately at the time of its most recent rate case - the arguments
in favor of the end-of-year rate base were stronger. But in this case Boise
Water s plant additions were not so large as to umeasonably distort the
matching of its revenues, expenses, and rate base. For these reasons, it is most
appropriate to apply the average-year rate base.
Order No. 19902 at 14. Thus, in adopting an average-year rate base the Commission also
identified exceptions that would be considered for including some or all plant at end-of-year
values. Those exceptions are: explosive growth, double-digit inflation, and very large discrete
STAFF'S POST-HEARING BRIEF
construction projects. Because explosive growth and double digit inflation do not apply to this
case and the projects Idaho Power proposed for year-end rate base inclusion do not fall within
the definition of "very large, discrete construction projects " the rate base projects proposed by
Idaho Power should be averaged in the test year like other unexceptional projects.
4. Exceptional Deviations from Average Rate Base
Idaho Power makes reference to exceptional adjustments allowed in previous rate
cases to adjust average rate base by year-end values for specific plant. However, as explained
above, special treatment of these adjustments were necessitated due to explosive growth, double-
digit inflation, or because they were very large, discrete construction projects. Order No. 19902.
For example, the Company cited an exception made for the $116 844 000 annualizing
adjustment for Valmy 1. Tr. at 2787. In Case No. U-I006-185 decided in August 1982, the
Commission allowed the addition of Valmy I and conservation investments9 at year-end rather
than average rate base value. Order No. 17499 at 31. Although this is the same rate base
valuation treatment the Company presently seeks for its annualizing adjustments, Idaho Power
did the very thing in the 1982 case that Staff and Micron desire in this case: it included
additional revenues and cost-reducing expenses in the adjustment to present a fair representation
of what revenues and expenses would be if the plant was in service the entire year. The
Commission explained:
We accept both of these adjustments to the average-year rate base and base
our findings upon them. We accept the Valmy related adjustments to rate base
because the Company adjusted revenues and expenses to simulate what they
would have been had Valmy been in operation for the entire year.We find
that this gives a proper matching of rate base, revenues and expenses that
permits inclusion of Valmy in rate base as though it had been in operation for
the entire year.
Order No. 17499 at 32 (emphasis added). It is Staffs and Micron s assertion that the Company
has not presented fairly all the additional revenues and expenses associated with the plant the
Company wants to include in rate base. Consequently, the Company s proposed adjustments are
unfair and should be denied.
Idaho Power also noted that it was allowed to annualize the $23 038 500 cost to
reconstruct the hydroelectric facility at Cascade. Tr. at 2787. In Case No. U-I006-265 decided
9 While Staff would agree that conservation investments have consistently been adjusted to year-end values, the
plant the Company is seeking to annualize is not a conservation investment.
STAFF'S POST-HEARING BRIEF
in July 1986, the Commission included the total cost of the reconstruction in rate base because
on the whole, the balance of factors favoring inclusion of Cascade in rate base strongly
outweighs those favoring its partial or total exclusion.Order No. 20610 at 65.Several
important distinctions exist between the Cascade plant and the projects the Company presently
wants to annualize. The Cascade rebuild was one distinct proj ect, had prior approval from the
Commission, was a generating facility, and large in cost. In this present rate case, the Company
is asking to annualize projects that have no prior Commission approval, are relatively small in
cost, and are an aggregation of projects that are not all generating facilities. Although the
Bridger rewind project could be similar to Cascade in that it is a rebuild of a generating facility,
the Bridger rewind project without the aggregation10 of other umelated projects is relatively
small at only $2 292 326. Tr. at 2808-09.
A third exception cited by Idaho Power is the $54 542 500 rebuild of the Swan Falls
In Case No. IPC-94-5 decided January 1995, the Commission authorized Idahofacility.
Power to increase rate base by the actual expenditures for the rebuilding of the Swan Falls
facility completed in November 1994. Order No. 25880 at 12. Like the Valmy I and Cascade
facilities, the Swan Falls facility was exceptional in that the Commission pre-approved the
rebuild, it was a power generating facility, it was a large expenditure, and it was a single distinct
proj ect.
Idaho Power s requested average-year rate base adjustments, be they annualizing or
known and measurable, are simply not in the same league with the adjustments previously
approved by the Commission. Moreover, it is umeasonable to include these adjustments without
inclusion of the increased revenues or reduced expenses that should flow from these projects.
10 The Company s $19 779 389 annualizing adjustment for "Bridger rewind project" is actually an aggregation of
four umelated projects. Tr. at 1582, 2808. While Company testimony attributes $6 621 907 of this total adjustment
to the project it calls "Bridger Rewind " Smith Exhibit No. 18 and Staff Exhibit No. 146 show that only $2 292 326
of the $6 621 907 was actually spent on the rewind of Bridger generator #3. The balance of the $6 621 907
proposed adjustment is for a dragline replacement ($1 385 193), controls replacement ($1 676 680), and spent liquor
ponds ($1 796 706) at the Bridger power plant. Tr. at 2808- 09.
STAFF'S POST-HEARING BRIEF
PENSION ADJUSTMENTS
1. Annual Pension Expense
Idaho Power initially proposed a $7 018 000 test year pension expense and sought a
170 163 increase to 2003 service costs to make it "more reflective of pension costs going
forward.Tr. 529, 1253. Citing our disagreement with three Company methodologies to
calculate pension expense, Staff believes the Company should ultimately receive $0 for pension
expense in this case. First, Staff recommended denial of the $2 170 163 adjustment that would
increase pension expense from Net Periodic Pension Cost to the Service Cost. Tr. at 1496.
Second, Staff proposed reducing test year pension expense by an additional $1 379 149 to offset
Idaho Power s projected return on assets using a newly revised assumption for its future
expected return on plan assets.Tr. at 1500-04. Staff disagreed with the Company s actuarial
assumption changes because the plan has earned an average 12.97% return over the past 15 years
and there were no extraordinary circumstances or changes in investment policy to prompt the
revisions. Finally, Staff proposed a pension expense adjustment to reconcile the $5 638 851
difference between cash and accrual accounting to recognize that Idaho Power paid nothing into
the plan in 2003. Staff witness Donn English further testified that Idaho Power was not required
or even able to pay anything into this plan since 1995 and is unlikely to contribute to the pension
plan for several more years. Tr. at 1509. These three adjustments taken cumulatively would
reduce the Company s proposed pension expense from $9 188 163 to $0.
On rebuttal, Idaho Power accepted Staffs first adjustment of $2 170 163 to Idaho
Power s proposed pension expense (now collecting only $7 018 000) and Staffs use of Net
Periodic Pension Cost. Tr. at 3181 , 2856-58. The Company did not endorse Staffs
recommendation to offset Idaho Power s projected return on assets by $1 379 149 by continuing
to use the 9% return assumption utilized since 1986 rather than the Company s newly proposed
5%, even though Mr. Fowler testified that the plan has historically earned 12.97% and is one of
the best performing plans he reviews. Tr. at 2871 , 2885, 2887. Although Staff disagrees with
the Company s changed actuarial assumptions, this point of contention becomes a non-issue in
terms of the revenue requirement if the Commission agrees with Staff that $0 pension expense is
necessary at this time given that the Company has not made cash contributions since 1995 , did
not make a contribution in the test year, and is unlikely to do so in the near future.
STAFF'S POST-HEARING BRIEF
Company witness Bradley Fowler argued that Statement of Financial Accounting
Standards No. 87 (FAS 87) is the best measure of pension costs because it is a publicly disclosed
and audited value, controlled by a well-defined and consistent accounting standard. Tr. at 2856.
Mr. Fowler further states that F AS 87 was specifically developed to create consistency of
measurement from period to period, and to facilitate comparison of pension costs on a consistent
basis from one company to another. Tr. at 2857. Though Staff agrees that FAS 87 is the basis
for measuring pension costs for financial reporting purposes, the Company agrees that F AS 87
makes no mention of regulatory recovery or regulatory accounting. Tr. at 2884.
Staff does not contest that F AS 87 is the accounting standard for pensions for
financial reporting purposes. The argument against using F AS 87 net periodic pension expenses
for regulatory recovery has probably never been more compelling than in this case. Idaho Power
has collected $19 million more in rates for pension expense than it has contributed to the pension
plan since its last rate case in 1994-95. If the Commission were to approve the Company-
requested net periodic pension expense in this case, Idaho Power will collect another $28 million
from ratepayers between now and 2007, the earliest the Company expects to contribute to the
plan. Tr. at 2879. It is extremely unfair for ratepayers to pay pension expense in rates when no
cash contributions are actually paid. Accordingly, it is appropriate for the Commission to grant
Idaho Power recovery of only the amount it has paid: $0.
2. Prepaid Pension Expense in Rate Base
Idaho Power s base rates established by Order No. 25880 in 1995 included pension
expense of more than $3 million annually. In its Application, Idaho Power seeks to include
$17 800,4 77 in rate base to earn a rate of return on prepaid pension assets. In the test year the
Company contributed nothing, but due to market gains and a negative net periodic pension cost
under F ASB 87, it expensed negative amounts that significantly increased the prepaid pension
asset. Although this phenomenon appears in the Company s financial books for financial
reporting purposes to denote the extent to which the pension plan is exceeding its actuarial
assumptions, Idaho Power s actual cash contribution in 2003 was $0. As previously stated, the
cash contributions have been zero since 1995 and will continue to be zero for several years. Tr.
at 1509.
Staff recommends denial of this addition because the underlying trust asset was not
paid by Company or shareholder investment. Prepaid pension assets are the result of investment
STAFF'S POST-HEARING BRIEF
return on invested payroll benefits funded by ratepayers. Accordingly, prepaid pension expense
is not an asset that provides electric service on which the Company and shareholders are entitled
to earn a return on investment.
According to the Company, inclusion of a prepaid pension amount in the rate base
recognizes the investment and carrying costs the Company has incurred over the years, both in
cash contributions and the value added through proper oversight, portfolio management
techniques and asset allocation policies. Tr. at 1509. However, the Company has not incurred
any carrying costs or made cash contributions since 1995, while ratepayers funded contributions
through base rates that included pension expense. Tr. at 1512. Staff also argues that there is no
reason to compensate the Company for its proper oversight of the pension plan because the
Company must comply with its fiduciary and legal responsibilities set forth in the Employee
Retirement Income Securities Act (ERISA) of 1974. It is illogical to reward the Company for
actions that are required by law.
Recovery of prepaid pension expense in rates would also defy regulatory logic. As
discussed previously, a prepaid pension asset is created when the cash contributions to a pension
plan exceed the amounts the Company has recorded on its books. Conversely, a pension
liability occurs when a Company contributes less cash to the plan than it records on its books.
the prepaid pension asset were to be included as an addition to rate base, it would also be
necessary to reduce rate base when a pension liability occurs.
The issue of not including prepaid pension assets in rate base has been previously
addressed by other state Commissions. The Nevada Public Service Commission denied Central
Telephone Company-Nevada s request to include over $10 million in prepaid pension asset in
base rates, stating: "The Commission believes it is illogical to conclude that investors should
receive a return on a book entry that reduces expense. Investors are entitled to a return only on
funds that are actually provided and not on assets that accrue as a result of accounting
procedures." Docket Nos. 91-5054 and 91-7026, 1992 WL 402072 (Nev. P.c.). In adopting
the OCA'II recommendation to deny the Company s request, the Nevada Commission noted
the proposed adjustment to (decrease) rate base properly reflects the fact that the (utility) has
11 The OCA is more formally known as Nevada Attorney General's Office of Advocate for Customers of Public
Utilities, but the acronym is used for simplicity.
STAFF'S POST-HEARING BRIEF
made no contributions and, therefore, should earn no return on rate base relating to pensions.
Id.
The Texas Public Utility Commission also addressed this pension asset issue when
Central Telephone Company of Texas (CENTEL) asked to include over $2 million in prepaid
pension assets in rate base. In rejecting CENTEL's request, the Texas Commission used
rationale that also applies to the similar facts presented in this Idaho Power case. It found that:
CENTEL collected, through its rates, enough money from ratepayers to fund
its pension plan. Because CENTEL did not accurately predict that its pension
fund would experience favorable investment results and that there would be
reductions in benefit levels, the pension fund was subsequently overfunded.
If CENTEL had predicted these events in advance, CENTEL's revenue
requirement would have been reduced, the ratepayers would not have paid in
as much, and CENTEL' s pension plan would not be overfunded as it
presently is. Therefore, CENTEL's argument that the Company or investors
would have had use of the additional money in the pension fund is without
merit.
Docket No. 9981 , 1993 WL 595464 (Tex. P.UC.
Finally, Staff addresses the Company s inference during the hearing that adopting
Staff s recommendation to remove prepaid pension expense from rate base is a departure from
the last rate case Order. Tr. at 1528. Although Order No. 25880 authorized approximately $2.
million of pre-paid pension expense in the last rate case, the Order does not suggest that the
relatively small amount approved was contested or scrutinized in any detail.Because
circumstances have changed such that Idaho Power: 1) did not make cash contributions since
1995; 2) could not contribute to its pension plan during the test year; and 3) is unlikely to do so
until at least 2007, the Commission s review and denial of these amounts are justified. Simply
put, the recovery of pension costs not incurred is unjust and umeasonable. As noted above, the
Commission is free to change its policies given changing circumstances. Rosebud 128 Idaho at
609 917 P.2d at 776 (1996); Intermountain Gas 97 Idaho at 113, 540 P.2d at 775.
CONCLUSION
In light of the record and the need to balance the interests of both Idaho Power and its
ratepayers, the Commission should adopt the Staffs adjustments discussed above.
STAFF'S POST-HEARING BRIEF
Respectfully submitted this 26th day of April 2004.
Weldon B. Stutzman
Deputy Attorney General
M:IPCEO3 1 3 Post-Hearing BrieUn
STAFF'S POST-HEARING BRIEF
CERTIFICA TE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 26TH DAY OF APRIL 2004
SERVED THE FOREGOING STAFF'S POST-HEARING BRIEF, IN CASE NO. IPC-
03-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
MONICA MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE, ID 83707-0070
JOHN R GALE
VICE PRESIDENT - REG AFFAIRS
IDAHO POWER COMPANY
PO BOX 70
BOISE, ID 83707-0070
PETER J RICHARDSON ESQ
RICHARDSON & O'LEARY
PO BOX 1849
EAGLE ID 83616
DON READING
BEN JOHNSON ASSOCIATES
6070 HILL ROAD
BOISE ID 83703
RANDALL C BUDGE
RACINE OLSON NYE BUDGE BAILEY
CHARTERED
PO BOX 1391
POCATELLO ID 83204-1391
ANTHONY Y ANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
LAWRENCE A GOLLOMP
ASSIST ANT GENERAL COUNSEL
US. DEPARTMENT OF ENERGY
1000 INDEPENDENCE AVE SW
WASHINGTON DC 20585
DENNIS GOINS
POTOMAC MANAGEMENT GROUP
5801 WESTCHESTER ST
ALEXANDRIA VA 22310-1149
DEAN J MILLER
McDEVITT & MILLER LLP
PO BOX 2564
BOISE ID 83701
JEREMIAH J HEALY
UNITED WATER IDAHO INC
PO BOX 190420
BOISE ID 83719-0420
WILLIAM M EDDIE
ADVOCATES OF THE WEST
PO BOX 1612
BOISE ID 83701
NANCY HIRSH
NW ENERGY COALITION
219 FIRST AVE SOUTH SUITE 100
SEATTLE WA 98104
CONLEY E WARD
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
DENNIS E PESEAU PH.
UTILITY RESOURCES INC.
SUITE 250
1500 LIBERTY STREET SE
SALEM OR 97302
CERTIFICATE OF SERVICE
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH STREET
BOISE ID 83702
MICHAEL KARP
147 APPALOOSA LANE
BELLINGHAM W A 98229
MICHAEL L KURTZ, ESQ
KURT J BOEHM ESQ
BOEHM KURTZ & LOWRY
36 E. SEVENTH ST SUITE 2110
CINCINNATI OH 45202
THOMAS M POWER
ECONOMICS DEPARTMENT
LIBERAL ARTS BLDG. 407
UNIVERSITY OF MONTANA
32 CAMPUS DR
MISSOULAMT 59812
~\:0~-/,
SECRETARY
CERTIFICATE OF SERVICE