20120531Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
202 MAY 30 PM 4: 46
irt ri WnV ri- UTILiTIES COMMISSION
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-12-14
AUTHORITY TO INCREASE ITS RATES )
AND ITS RATE BASE TO RECOVER ITS )
INVESTMENT IN THE LANGLEY GULCH ) COMMENTS OF THE
POWER PLANT. ) COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of Record, Donald L. Howell II, Deputy Attorney General, and submits the following
comments in response to Order No. 32523 issued on April 17, 2012.
BACKGROUND
On March 2, 2012, Idaho Power Company filed an Application requesting that it be
allowed to increase its rate base and rates upon completion of the Langley Gulch power plant.
Langley Gulch is a 330 MW natural gas-fired, combined-cycle combustion turbine currently under
construction near New Plymouth, Idaho. Certificate No. 486. The Company proposes that the rate
base additions and the resulting rate increases become effective July 1, 2012.
STAFF COMMENTS 1 MAY 30, 2012
THE 2009 CPCN CASE
On March 6, 2009, Idaho Power Company filed an Application for a Certificate of Public
Convenience and Necessity (CPCN) authorizing construction of the Langley Gulch power
plant and the ability to ultimately include the costs of the completed Project in the Company's rate
base. Under Idaho Code § 61-526, an electrical corporation is prohibited from beginning the
construction of a generating plant without having first obtained from the Commission a certificate
that the present or future public convenience and necessity requires or will require such
construction. In its Application, the Company requested that the Commission issue a certificate
and authorize cost recovery and ratemaking assurances.
In Order No. 30892 the Commission authorized Idaho Power to construct and operate the
Langley Gulch plant. See also CPCN No. 486. In its Order, the Commission also provided Idaho
Power with the authorization and binding commitment to provide rate base treatment for the
Company's capital investment in the Langley Gulch plant and related facilities. At such time as
the plant is placed in commercial operation, the Commission authorized an increase in rate base in
an amount up to $396,618,473. The Company expects the plant to be placed in commercial
operation on July 1, 2012.
OVERVIEW OF THE CURRENT APPLICATION
In the current Application, the Company states that the investment in the Langley Gulch
plant for purposes of determining the Company's additional revenue requirement is $390,942,172.
Using the Company's overall rate of return of 7.86%, as authorized by the Commission in the
Company's last general rate case (Order No. 32426), and including depreciation and the applicable
tax rates, the Company calculates an additional annual revenue requirement of $59,869,823 for the
Idaho jurisdiction. Included in this revenue calculation are certain expenses related to the
investment in the Langley Gulch plant including generation and transmission investments, as well
as labor and non-labor operation and maintenance (O&M) expenses, depreciation expenses, ad
valorem tax expenses, and income tax expenses.
The Company has proposed a uniform percentage increase in rates of 7.18% to all existing
customer classes as measured from current base rate revenues, or a 7.10% increase in total current
billed revenues, effective July 1, 2012.
In the most recent Idaho Power general rate case (Case No. IPC-E-1 1-08), $7,191,606 of
Langley Gulch investment has already been included in rate base. These expenditures were
STAFF COMMENTS 2 MAY 30, 2012
included in the Company's original Commitment Estimate of $427,366,769 and were included in
the Company's plant balances as of December 31, 2010. These expenditures included the costs
associated with: 1) site procurement; 2) water rights; and 3) land for the water line. Because the
Company used plant balances through December 31, 2010 as the base year amounts in the last
general rate case, the $7.2 million amount is already included in the Company's current rates.
Since this Application was filed, a settlement in Idaho Power's most recent depreciation
case (Case No. IPC-E-12-08) has been reached, including a change in depreciation rates for the
Langley Gulch plant. Therefore, the depreciation expenses for the Langley Gulch plant will be
different than the expenses originally proposed in this Application. The decrease in depreciation
expenses will affect the additional revenue requirement and rate increase percentage accordingly.
STAFF REVIEW
To establish costs associated with the construction, transmission and facilities attributable
to Langley Gulch, Staff performed a detailed analysis of the Company's Application and
workpapers. This analysis included a comprehensive project specific review of actual and
estimated transmission and plant expenditures. Staff reviewed major contracts, change orders,
invoices and financial transactions of the project to insure reasonableness and accuracy.
PLANT INVESTMENT
Idaho Power received its CPCN authorizing the construction of the Langley Gulch plant in
Order No. 30892.1 In Order No. 30892 Idaho Power was granted "assurance" pursuant to Idaho
Code § 61-541 that it would be allowed to place $396,618,473 in rate base and to recover the
corresponding revenue requirement.
In this Application, Idaho Power is seeking rate recovery for $390,942,172 in capital
expenditures related to investment in the Langley Gulch project. This is the amount the Company
projects it will spend through June 30, net of $7.2 million in site procurement, water rights, and
water line land costs already spent and currently included in base rates. However, the Company
expects to spend an additional $3,282,796 after June 30 that it will likely seek for recovery in a
future rate case. Thus, the total estimated cost of the project is $401,416,574 ($390,942,172 +
$7,191,606 + $3,282,796).
'See Case No. IPC-E-09-03.
STAFF COMMENTS 3 MAY 30, 2012
Staff has focused its review in three primary areas. First, because the pre-approved
Commitment Estimate is for the cost of the entire project, any review of budget-to-actual
expenditures required an analysis of the total project costs. The Company has projected that the
total project investment will be $401,416,574, thereby exceeding the Commission-approved
Commitment Estimate by approximately $4.8 million. Staff reviewed the Company's budget
spending performance and the prudency of expenditures for the total project, not just the amount
the Company is seeking in this case. Second, Staff reviewed estimates for spending through the
end of the project. This was to ensure that the total project expenses were accurate and that
evaluation of budget performance was reasonable and realistic. Third, Staff reviewed the certainty
of estimates used to project total spending through June 30, 2012. This was done to ensure that the
amount of capital expenditure sought in this case would be accurate so that ratepayers would not
be compensating the Company for expenses not realized during the test period.
As noted above, the Company did not receive full approval for its proposed $427 million 2
Commitment Estimate in the CPCN case. Even with a Commission-approved Commitment
Estimate of approximately $397 million (about $30 million lower than the Company's proposed
amount), the Company has been able to finish the project within 2.0 percent of the Commission-
approved Commitment Estimate.
As expected in a project of this magnitude, there was a mix of cost categories above and
below budget based on the pre-approved Commitment Estimate. Although Staff reviewed
expenditures in all cost categories, Staff conducted additional review of cost categories that were
over budget. In addition, prudency of expenditures was evaluated for any item that did not appear
to be part of the pre-authorized Commitment Estimate. As illustrated in Attachment A, Staff
concentrated on several cost categories that exceeded their Commitment Estimates: site
procurement; NEPA permitting; air permitting; water line construction; gas line construction;
miscellaneous equipment; Idaho Power engineering and oversight; RFP pricing components; and
transmission.
In its review below, Staff has high-lighted four areas. Details for these and other findings
in each cost category (except AFUDC which will be discussed in the Rate Base section) can be
found in the sub-sections following the summarized highlights and in Attachment A.
2 See IPC Application at 11 (Case No. IPC-E-09-03).
STAFF COMMENTS 4 MAY 30, 2012
• Contingency Reserve: The Company created an approximately $300,000 reserve as a
contingency to resolve potential issues after June 30, 2012 for final acceptance of the gas
and steam turbine not based on any contractual obligation. This reserve has been included
in the Company's estimate of total project costs. If incurred, these costs should be
scrutinized before recovery in a future case.
• Development Cost: There is $251,894 related to the cost to develop the Company's
benchmark resource proposal that Staff believes should not be allowed. Including this cost
in the Commitment Estimate after not including it in the Company's winning bid would
unfairly bias or undercut the bidding process.
. Transmission: Upgrading the Langley to Wagoner transmission line from a 138 kV line to
a 230 kV line is not necessary for the operation of the Langley Gulch project and is not
relevant to this single-issue rate case. The approximately $1.2 million incremental cost of
the upgrade should be placed in plant held for future use to be recovered in a future general
rate case.
• Fiber Cable: There was $75,000 in cost to perform splicing for the fiber communication
line between the Langley Gulch plant and the Caldwell substation that won't be incurred
until after June 30, 2012. This cost does not occur in the test period and should not be
included for recovery in this single-issue rate case.
Given the sum of the adjustments above, Staff believes the total estimated project costs should be
reduced from $401,416,574 to $399,966,742 and the total amount allowed for recovery in this case
be reduced from $390,942,172 to $389,417,340.
Gas Turbine
Gas turbine expenditures should finish less than one percent under the Commitment
Estimate. The remaining expenditure through June 2012 is based on the last payment to the
equipment vendor for contractual obligations to meet equipment performance criteria and facilitate
final acceptance by Idaho Power. The Company has reserved $150,000 past June 30, 2012
included in the total project costs for any additional change orders that may be needed for final
acceptance. If the Company takes title to the equipment by the end of June, there is a good
probability that not all of the $150,000 contingency reserve will be needed.
STAFF COMMENTS 5 MAY 30, 2012
Steam Turbine
The Company expects steam turbine expenditures to be less than one percent over the
authorized Commitment Estimate. Staff reviewed the contract, all of the change orders, and cost
estimates that make up the Company's expected project expenditure. All future expenses, except
$150,000, are covered by the contract and change orders. The original contract was written for a
standard steam turbine. Change orders were required to customize the turbine specific to Langley
requirements. Staff believes the turbine change orders reflected in the modifications were
reasonable and necessary. The remaining expenses through June are based on last payment to
the equipment vendor for contractual obligations to meet equipment performance criteria and to
facilitate final acceptance by the Company. The Company has reserved an additional $150,000
past June 30, 2012 included in the total project costs for any additional change orders that may be
needed for final acceptance. If the Company takes title to the equipment by the end of June, it is
likely not all of the $150,000 contingency reserve will be needed, thereby allowing the steam
turbine expenses to finish under the Commission-approved Commitment Estimate.
EPC Contract
Based on the Company's total project estimate, the engineering, procurement, and
construction (EPC) contract is projected to be below the Commitment Estimate budget by 2.57
percent or $5,698,263. Estimates for the remaining expenses through June and for the remaining
project was based on a projection of monthly cash flow which totals the difference between the
contract amount (with change orders) of $215,655,283 and current actual expenditures of
$203,287,526 (through end of January 2012). After reviewing the contract, current change orders,
and anticipated change orders, Staff determined these estimates to be reasonable given that
anticipated change orders include both additional expenses and credits that net to approximately
zero. Staff also believes that the scope of work and cost for both current and anticipated change
orders are reasonable and necessary for the completion of the project.
Site Procurement
Idaho Power anticipates the total project costs of $2 million for site procurement to be over
the Commitment Estimate by $50,000. Staff reviewed all of the actual expenditures and believes
them to be reasonable. The entire budget is targeted to be expended by the end of June 2012.
STAFF COMMENTS 6 MAY 30, 2012
Landscaping and fencing at an estimated cost of $42,678 is the only expenditure the Company
anticipates after construction of the facility is complete.
Water Rights
Water rights necessary for the operation of the facility have been obtained. There is no
additional spending required. The total project costs were less than a tenth of a percent over the
Commitment Estimate of $2,081,269.
National Environmental Policy Act (NEPA) Permitting
The $150,000 budget for the NEPA permitting costs only applies to permitting related to
the power plant site, the gas line, and water line on federal lands. Additional NEPA permitting
cost for the transmission line was included in the transmission line budget category. All land use
permits have been obtained for the Langley facility and spending related to NEPA environmental
permitting has been fully expended. The Company went over the $150,000 original Commitment
Estimate by $64,431. Most of this was due to unforeseen incremental cultural and biological
assessments, a wetland delineation study, new BLM requirements, and changes to water line routes
as a result of initial assessment findings. Given the difficulty in trying to predict the amount of
unforeseen constraints found during NEPA permitting, Staff believes that additional expenditures
were within a reasonable range of costs.
Air Permitting
The Company anticipates the total project costs for air permitting to be over the
Commitment Estimate of $320,000 by 22 percent. Staff reviewed all of the actual expenditures
and believes them to be reasonable. There were several unforeseen expenditures that caused the
overage related to the construction and operation of the meteorological station, legal support costs,
and changes required for air modeling. The Company estimates an additional $14,000 prior to
June 30 and $25,000 after June 30 will be needed to obtain final Tier I operating permits. These
amounts were an estimate based on work conducted for air shed modeling conducted by the
contractor earlier in the project. Staff believes that these figures are reasonable although somewhat
conservative.
STAFF COMMENTS 7 MAY 30, 2012
Water Line Construction
Idaho Power anticipates the total project costs for water line construction to be over the
Commitment Estimate of $4.425 million by 3.5 percent. The Company predicts an additional
$20,000 in total expenditures with all spending completed by June 30, 2012. The cost will be for
labor and material for developing maintenance and operation manuals for the water system and to
install security alarms. Staff reviewed all actual expenditures and believes them to be reasonable
and needed for the completion of the project.
Gas Line Construction
The gas line is frilly constructed and the Company anticipates all payments to be completed
by June 30, 2012. The Company has projected that the total project costs will be $1,620,000 over
the Commitment Estimate of $1.55 million. Because the original estimate the Company submitted
as part of the CPCN case was based on estimates rather than competitive bids, the Commission
only allowed 50 percent of the estimated. However, the total project cost is anticipated to be very
close to the Company's original estimates which were based on an estimate from Williams
Pipeline for the pipeline tap and meter; and an estimate from an engineering cost study for
construction of the pipeline. Actual cost for construction of the pipeline came under the original
estimate, but cost for the tap and meter was approximately $500,000 over William's original
estimate. After reviewing the contract, change orders, and actual costs, Staff believes that the cost
to construct the gas pipeline was reasonable.
Miscellaneous Equipment (Idaho Power Supplied)
The miscellaneous equipment cost category includes Company-owned vehicles, office
furniture and equipment, and any other piece of equipment directly sourced by the Company.
Idaho Power projects the total project costs to be $2.57 million over the authorized Commitment
Estimate of $331,150. Although only 50 percent of the costs were authorized in the CPCN case
for several of the items that were included in the Company's original budget submission, most of
the budget overage is due to unforeseen but necessary purchases. Staff reviewed the prudency of
all past and projected purchases and believes them to be reasonable and necessary for the operation
of the facility. The Company anticipates that all remaining spending should occur before June 30,
2012. Staff believes the Company's estimate for the remaining amount to be reasonably accurate.
STAFF COMMENTS 8 MAY 30, 2012
Idaho Power Engineering and Oversight
The Company anticipates the cost of engineering and oversight to be 48 percent over the
Commitment Estimate budget of $1.9 million. Staff reviewed actual expenditures of
approximately $220,000 for materials and approximately $1.73 million for payroll related
expenses. Staff also reviewed the remaining expenditures of approximately $330,000 until the end
of June and $81,000 from July 1 until project closeout. Staff believes that these estimates have a
sound basis and that the total expenses over the life of the project are reasonable for completion of
the project. Staff believes that the original Commitment Estimate was low due to unforeseen
circumstances that occurred during project construction, especially given the large overall project
scope.
RFP Pricing Components (Including Startup Fuels)
The two main costs included in the RFP pricing cost category were: (1) the cost of all
Langley Gulch request for proposal (RFP) development activities ($399,000) including the
development of the Company's benchmark resource proposal; and (2) the net cost of fuel and
energy used and sold, respectively, for facility startup, and performance and acceptance testing at
the facility ($4.7 million). The Company estimates that the total project costs for this category will
be $5.074 million over the Commitment Estimate of $500,000.
Staff reviewed all actual and estimated costs and found the main reason for the deviation
from budget was due to net fuel cost. The initial Commitment Estimates developed during the
CPCN case used a rough estimate of four times the net fuel costs needed for the startup of the
Company's Danskin simple-cycle combustion turbine (SCCT) power plant. Although Danskin is a
natural gas plant, the characteristics of the plant are much different than Langley and the cost of
fuel and energy at that time were much different from current prices. A CCCT plant, such as
Langley, is an order of magnitude more complex than an SCCT plant and to use a multiplier
related to the capacity of the plant to determine net fuel cost was too simplistic. Staff reviewed the
basis used to determine the net fuel cost, including actual and estimated fuel/energy usage and
their unit costs, and determined that although the costs are over budget, they were reasonable.
The Company estimates that there will be approximately $500,000 in additional net fuel
cost that may be needed for acceptance testing past June 30, 2012. Staff expects that these costs
may no longer need to be capitalized and any cost of fuel and energy sold will be rolled into
normal operations and maintenance expense and revenue.
STAFF COMMENTS 9 MAY 30, 2012
Staff believes that the costs associated with the development of the Company's benchmark
resource proposal should not be allowed for recovery. First, Order No. 30892 establishes that
Staff's methodology be used to determine the Commission-approved Commitment Estimate
specifically referencing Confidential Exhibit No. 109 of Staff witness Rick Sterling's direct
testimony in the CPCN case. None of the RFP team expenses originally proposed by the Company
were included in the Commitment Estimate. Furthermore, the reasons for excluding them are
stated in Mr. Sterling's testimony 3 :
.this is a cost that should not be included in either the Soft Cap or
the Hard Cap. Other bidders would have had to include these costs in
their bid amount, so it would be unfair for Idaho Power to exclude
them from the Benchmark Resource bid during the evaluation process,
but add the costs to its Commitment Estimate after it determined that
the Benchmark Resource was the winning bid.
Consequently, Staff recommends that $251,894 in employee-related payroll and benefit
costs be excluded for rate recovery that is associated with the development of Idaho Power's
benchmark resource proposal. However, Staff believes the Commission should allow for
consultant costs to be included, as the bulk of its services were used to oversee the overall bidding
process.
Transmission Line
The Company anticipates the cost of constructing the two transmission lines necessary for
Langley operation to be 24 percent over the Commitment Estimate budget of $17.86 million. Staff
reviewed actual spending, contracts and change orders, and all estimates for the total project costs
related to the engineering and construction of two transmission line projects and distribution lines
supporting Langley Gulch. Staff also compared all costs against estimates and plans included in
the CPCN case. Through this analysis, Staff uncovered two issues.
First, Staff believes that a portion of the transmission upgrades included in the project is
not necessary for the operation of Langley in its current configuration. According to the
Company's response to Staff's discovery requests, this includes all incremental costs (estimated at
$1,197,938) related to upgrading the Langley to Wagner transmission line from 138 kV to 230 kV.
These costs were excluded in the authorized CPCN commitment budget because it was
acknowledged that upgrade of this transmission line was not required for operation of the Langley
See R. Sterling, Di, p. 69, Case No. IPC-E-09-03.
STAFF COMMENTS 10 MAY 30, 2012
Gulch plant. Staff has confirmed with Idaho Power that these conditions have not changed and
that the line will only be energized at 138 W. Staff recommends that these costs of $1,197,938 be
excluded from the current project and placed in the plant held for future use account.
Second, the Company anticipates that all expenditures related to transmission will be
completed by June 30, 2012 with one exception. Idaho Power believes that $75,000 of cost for
splicing a fiber communication cable currently included for recovery in this case will not be spent
until after July 2012. Staff recommends that this cost of $75,000 be deferred for recovery in this
case because it does not occur during the corresponding test period.
DEPRECIATION CASE
On February 16, 2012, Idaho Power Company filed an Application with the Idaho
Public Utilities Commission for revised depreciation rates for electric plant in service, Case No.
IPC-E-12-08. The Company's Application proposed a 30-year life span for the Langley Gulch
plant. However, parties agreed to use a 35-year estimated depreciable life as part of the Settlement
Stipulation in the depreciation case. As noted above, the case is scheduled to be decided on the
same day these comments are due. Given that all parties have agreed to the Settlement, Staff has
chosen to incorporate the Settlement depreciation rates for Langley Gulch as well as additional
modifications to the depreciable rates of certain transmission and distribution accounts affecting
this case. The effect of the depreciation adjustment is a revenue requirement reduction of
$1,561,305.
RATE BASE
Rate base is the capital investment to which a fair rate of return is applied to arrive at the
net operating income requirement. In this case, rate base is comprised of electric plant in service
(EPIS) less accumulated depreciation and less accumulated deferred income taxes. The Company
proposed a total system rate base addition for Langley of $351,994,174. Staff recommends, after
adjustments for the depreciation case, plant held for future use, disallowance of RFP costs, and an
out-of-period item, a system rate base addition of $351,166,786. The depreciation case (see
discussions above and below in these comments) results in an increase in rate base of $522,937
due to the reduction in accumulated depreciation. Because accumulated depreciation is subtracted
from plant in service, a reduction in accumulated depreciation increases rate base. The plant held
for future use (see plant investment section discussion regarding transmission overbuild above)
STAFF COMMENTS 11 MAY 30, 2012
reduces rate base by $1,033,152. Disallowance of RFP costs (see discussion above) also reduces
rate base by $216,268. Finally, the out-of-period adjustment reduces rate base by $64,639.
Plant in Service
Plant in Service is the largest component of the Company's Application. The Company
included in its Application $390,942,172 of plant on a system basis. Staff proposes to reduce plant
on a system basis by the following adjustments (see plant investment section for further
information). One, remove $1,197,938 associated with the overbuilt transmission and place it in
plant held for future use. Two, remove $251,894 of RFP costs disallowed by Staff. Three, remove
$75,000 of costs that will not be incurred in the test period of the filing (out-of-period adjustment).
These adjustments reduce total plant to $389,417,340 on a system basis. The rate base section of
these comments identifies the net effect of these adjustments on rate base that includes the
accumulated depreciation and accumulated deferred income tax. Each adjustment also changes
operating expenses in the following areas: depreciation expense, taxes other than income
(property tax), deferred income tax expense, investment tax credit, and federal and state income
taxes as discussed in the revenue requirement section of these comments.
Allowance for Funds Used During Construction (AFUDC)
Staff recommends that the Company cease accruing AFUDC on all costs in this case that
are allowed for recovery in customer rates to prevent over recovery of costs. AFUDC is an
accounting mechanism which recognizes capital costs associated with financing construction.
Generally, the capital costs recognized by AFUDC include interest charges on borrowed funds and
the cost of equity funds used by a utility for purpose of construction. The main purposes of
AFUDC are to capitalize with each project the costs of financing that construction; separate the
effects of the construction program from current operations; and to allocate current capital costs to
future periods when these capital facilities are in service, useful and producing revenue. AFUDC
represents the cost of funds used during the construction period before plant goes into service.
When plant is placed in service, the entire cost of the plant, including AFUDC, is added to
rate base, where it earns a rate of return and is depreciated over the life of the plant. Staff
reviewed the Company's calculations and process to apply AFUDC to construction work orders.
Idaho Power calculates and applies AFUDC to Construction Work In Progress (CWIP) qualifying
work orders. When the work order is placed in service, the charges to CWIP are moved to
STAFF COMMENTS 12 MAY 30, 2012
Account 101 - Electric Plant in Service (EPIS). Costs moved to EPIS are not subject to AFUDC.
However, because costs are still being incurred on various work orders after the effective date of
the rates in this case, to the extent work orders have not been closed to EPIS the Company would
be over recovering costs by earning a rate of return through rates and applying AFUDC to those
same costs. Therefore, Staff recommends that AFUDC ceases on all costs that are allowed for
recovery in rates and therefore includes a return.
Accumulated Depreciation and Accumulated Deferred Income Taxes
Accumulated depreciation requested by the Company is 50 percent of annual depreciation
expense. The Company has used the half-year convention to record accumulated depreciation for
Langley Gulch. This convention has historically been accepted by the Commission. Accumulated
deferred income taxes requested by the Company is also 50 percent of annual deferred income tax
expense due to the half-year convention.
REVENUE REQUIREMENT
The revenue requirement for the Langley Gulch plant is calculated by comparing the return
on the Langley Gulch rate base (investment in plant and associated adjustments) to the revenue and
expenses attributed to the addition of the Langley Gulch plant. Because the overall operating
income (revenue less expenses) for Langley Gulch is negative, this amount is considered with the
return on rate base to calculate the revenue deficiency. Revenues must be increased sufficiently so
that the net income, after income taxes, is equal to the return on the rate base. The annual revenue
increase required to make the Company whole, as calculated with Staff adjustments, is
$58,105,578 on an Idaho jurisdictional basis, as shown on Staff Attachment B (Column H,
line 39).
Incorporated in Staff's depreciation adjustment, as shown in Column C on Staff
Attachment B, is a fine tuning in the calculation of current and deferred income taxes. In an
update to Staffs Production Request 35, the Company provided Staff with a Jurisdictional
Separation Study (JSS) that incorporated the new depreciation rates agreed to in the Settlement
Stipulation in the depreciation case, IPC-E-12-08. Staff, in its review, found that this Company
spreadsheet not only updated the depreciation rates, but also fine tuned the income tax and
deferred tax calculations. The spreadsheets that calculate federal income tax, state income tax,
deferred income tax, and the adjustment to the investment tax credit amortization also include
STAFF COMMENTS 13 MAY 30, 2012
some fine tuning to the spreadsheet that calculates current and deferred income tax. In previous
versions of the JSS, the Company spreadsheet calculated bonus depreciation on transmission
easements, where there otherwise would be no bonus depreciation on this particular plant account.
Staff agrees with this fine tuning in the calculation of current and deferred income tax.
The three Staff plant adjustments discussed above are shown in Attachment B. These
adjustments include Column D, the transmission overbuild adjustment; Column E, the out-of-
period adjustment; Column F, the RFP cost disallowance.
Staff used the most current JSS with the stipulated depreciation rates, and the fine tuning to
the spreadsheet that calculated the current and deferred income tax, to calculate the revenue
requirement incorporating all Staff adjustments as shown in Column G and Column H on Staff
Attachment B.
The following components contribute to the operating revenues and operating expenses for
the Langley Gulch plant:
1.Net Power Supply Expense
2.Labor Operations and Maintenance (O&M) Expense
3.Non-Labor O&M Expense
4.Insurance Expense
5.Depreciation Expense
6.Taxes Other than Income Tax or Ad valorem tax expenses (property tax);
7.Deferred Income Tax Expense
8.Investment Tax Credit
9.Federal Income Taxes
10.State Income Taxes
These revenue and expense components are discussed in greater detail below.
1. Net Power Supply Expenses, which includes System Opportunity Sales Revenues were
calculated by the Company using the "AURORA" model and represent the changes to power
supply expenses as a result of adding the Langley Gulch plant to the model. Staff agrees with the
Company's calculation reducing total net power supply expenses by $8,107,160 on a system basis.
The calculation of net power supply expenses includes an increase in revenue of $32,274,040 on a
system basis for power sales into the wholesale market. In addition, fuel expenses for coal will
decrease due to increased generation from Langley and reduced operation of existing coal plants.
The decrease in coal expenses is $525,340 on a system basis. Conversely, fuel expenses for
STAFF COMMENTS 14 MAY 30, 2012
natural gas will increase as Langley Gulch serves a larger percentage of system load. Natural gas
expenses are expected to increase by $45,871,730 on a system basis. Non-firm purchases of
electricity in the wholesale market will decrease as a result of adding Langley Gulch to the
generation fleet. Because Langley Gulch will be available to serve system load, less power
purchases will be required. Power purchases will decrease by $21,179,510 on a system basis.
2.Labor Operation and Maintenance (O&M) Expense included in the Application totals
$2,120,436 on a system basis. This amount includes annual payroll, with all the payroll loading
for items such as payroll taxes and benefits, for 17 full-time employees. These employees have
been hired and are currently working for the Company. Staff reviewed the supporting
documentation and finds this amount to be reasonable.
3.Non-Labor Operation and Maintenance Expense included in the Application totals
$2,681,152 on a system basis. These expenses include amounts for lubricants, fasteners, filters,
paints, safety equipment, testing services, cleaning services, chemicals for water treatment,
calibration gases, oil testing, vehicle expenses, training and other miscellaneous charges. The
Plant Manager for Langley Gulch provided the estimate for the non-labor O&M expenses, using
his expertise at a previous plant to arrive at the normal and routine items and expenses necessary
for the normal and ongoing O&M of a CCCT power plant. These estimates do not include
expenses other than routine O&M costs, and no expenses for major maintenance are included.
Staff reviewed the supporting documentation and finds this amount to be reasonable.
4.Insurance Expense included in the Application totals $229,876 on a system basis. This
expense is for property insurance for Langley Gulch and associated transmission and substation
property. Staff reviewed the supporting documentation and finds this amount to be reasonable.
5.Depreciation Expense included in the Application totals $13,662,682 on a system basis.
Depreciation represents the return of capital to the investor over the life of the investment. Staff
has made an adjustment to depreciation expense and a corresponding adjustment to accumulated
depreciation in rate base, for the change in depreciation rates as a result of the depreciation
settlement discussed earlier. To the extent that Staff has made adjustments to plant in service,
Staff has also made a corresponding adjustment to depreciation expense (and the accompanying
adjustment to accumulated depreciation in rate base). Staff's adjustments reduce depreciation
expense by $1,590,636 for a Staff adjusted total depreciation expense of $12,072,046 on a system
basis.
STAFF COMMENTS 15 MAY 30, 2012
6.Taxes Other than Income Tax included in the Application totals $1,432,047 on a system
basis. Ad Valorem taxes, or property taxes, on Langley Gulch have been calculated by the
Company based on current property tax rates assessed and the value of the Langley Gulch plant as
of January 1, 2012. Staff has reviewed the supporting documentation and finds the calculation to
be reasonable. To the extent that Staff has made adjustments to plant in service, Staff also made a
corresponding adjustment to the property tax. Staff's adjustments reduce property tax by $5,756
for a Staff-adjusted property tax expense of $1,426,291 on a system basis.
7.Deferred Income Tax Expense included in the Application total $64,251,378 on a
system basis. Deferred income taxes arise when income tax amounts provided for book or
regulatory purposes differ from the amount of taxes currently due and payable. This tax difference
is primary caused by the difference between the straight-line depreciation rates used for rate
making purposes versus the accelerated depreciation rates used for federal and state income tax
purposes. Under this method, there is higher depreciation expense for tax purposes than for
regulatory book purposes, causing the taxes computed for regulatory books (and thus, included in
revenue requirement) to be more than the taxes actually payable to the Internal Revenue Service
and state taxing entities, in the early years of the asset's life. In later years, the situation reverses
itself, such that the revenue requirement will reflect a lesser amount of income tax than that which
is actually due and payable. To the extent that Staff has made adjustments to plant in service, Staff
also made a corresponding adjustment to the provision for deferred income taxes. Staff's
adjustment to deferred income tax expense is $195,748 for a Staff adjusted deferred income tax
expense of $64,447,126 on a system basis.
8.The Investment Tax Credit Adjustment included in the Application totals $11,140,104
on a system basis. The investment tax credits are tax benefits the Company has received based on
the level of plant investment in various years. The tax credit is normally amortized over the life of
the associated plant investment. The amount amortized is based on the amount of the plant
investment. To the extent that Staff has made adjustments to plant in service, Staff also made a
corresponding adjustment to the investment tax credit adjustment. Staff's adjustments reduce
investment tax credit adjustment proposed by the Company by $66,558, resulting in a Staff
adjusted investment tax credit adjustment of $11,073,546 on a system basis.
9 and 10. Federal Income Taxes of ($64,153,899) and State Income Taxes of
($12,963,928) are included in the Application. Any adjustment to plant in service will change the
amount of federal and state income tax owed due to changes in depreciation expense associated
STAFF COMMENTS 16 MAY 30, 2012
with the various plant accounts. Staff has proposed changes to plant in service as well as to
depreciation rates. All the plant in service adjustments and the change in depreciation rates have
an effect on income taxes. To the extent that Staff has made adjustments to plant in service and
depreciation expenses, Staff has also made a corresponding adjustment to the federal and state
income taxes. Staff's adjustment to federal income taxes is $353,156 resulting in adjusted federal
income taxes of ($63,800,743) on a system basis. Staff's adjustment to state income taxes is
$55,989 for Staff adjusted state income taxes of ($12,907,939) on a system basis.
The Company has proposed using the overall rate of return of 7.86% currently in effect, as
authorized by the Commission in the Company's most recent rate case, Order No. 32426,
IPC-E-11-08. Although the Langley Gulch CPCN Order stated that the Company was to use the
current Return on Equity in effect, Order No. 32426 did not specify a return on equity. The
Company believes that the use of the approved overall rate of return is consistent with the spirit of
Order No. 30892 in the CPCN case, Staff concurs with using the overall rate of return of 7.86%
currently in effect.
The Net Income (Operating Revenues less Operating Expenses) for the Langley Gulch
plant on a system basis is shown on Staff Attachment B, (Column G, line 27) as negative
$9,609,762. The return on rate base, calculated by multiplying the dollar amount of the rate base
by the Company's authorized rate of return, is $27,585,994 on a system basis. The total earnings
deficiency on a system basis is $37,195,756. After applying the net to gross factor, the revenue
deficiency or increase needed, as proposed by Commission Staff, is $61,075,432 on a system basis,
and $58,105,578 on an Idaho jurisdictional basis.
POWER SUPPLY AND PCA LOAD CHANGE ADJUSTMENT
Idaho Power updated power supply costs by running the AURORA power supply model.
The Company added Langley Gulch as a resource to the model most recently accepted by the
Commission. No other changes were made in the model. Staff believes that this is the correct way
to determine changes in power supply costs in this single-issue rate case. The revised AURORA
model run produced a reduction in net power supply expense of $7,732,030 on an Idaho
jurisdictional basis. This amount was used in the calculation of the Langley Gulch incremental
revenue requirement and in a calculation to update the Load Change Adjustment Rate (LCAR) that
is part of Idaho Power's PCA calculations. This update reduced the LCAR from $18.1 6/MWh to
STAFF COMMENTS 17 MAY 30, 2012
$1 7.64/MWh as shown on Company Exhibit No. 4. Staff has reviewed these calculations and
accepts them.
REVENUE ALLOCATION AND RATE DESIGN
Idaho Power proposes to allocate the incremental revenue requirement and design rates
using forecasted billing determinants for the period June 1, 2012 through May 31, 2013. These
billing determinants are the most current information available for revenue allocation/rate design.
However, they have not been thoroughly reviewed in a general rate case and approved by the
Commission. Staff nevertheless accepts and recommends the use of the Company's proposed
billing determinants, just as it has done in its comments to all of the Company's other 2012 rate
Applications.
The Company's Application requested that $59,869,823 be spread to customer classes on
an equal percent of base revenue basis. The Company further proposed that within each class, all
rates except customer service charges be increased on a uniform percentage basis to recover the
class revenue requirement. The Company's proposal results in an average increase of 7.10% of
billed revenue.
Staff accepts the methodology proposed by the Company for revenue allocation and rate
design. For revenue allocation purposes, Staff proposes the use of June 1, 2012 base revenues.
The Application of this methodology to the incremental revenue requirement proposed by Staff of
$58,105,578 produces an equal percent increase in base revenues to all customer classes of 7.05%
as shown on Attachment C, page 1 to these comments. The same increase in incremental revenue
requirement produces a near equal percent increase in class revenue requirements that averages
6.97% as shown on Staff Attachment C, page 2.
STAFF RECOMMENDATIONS
. Staff recommends the total plant cost to be included for recovery in this case be reduced
from $390,942,172 to $389,417,340.
• Staff recommends that the Commission approve an Idaho incremental revenue
requirement associated with adding Idaho Power's Langley Gulch plant to base rates of
$58,105,578.
STAFF COMMENTS 18 MAY 30, 2012
. Staff recommends that the increase be spread to each customer class as an equal percent
increase based on June 1, 2012 base revenue and that within each class all rates (other than
customer charges) be increased on a uniform percentage basis as proposed by the Company.
• Staff recommends that the new rates become effective July 1, 2012 if the facility is in
commercial operation at that time or when the facility begins commercial operation if that date is
after July 1, 2012.
• Staff recommends that the Company cease accruing AFUDC on all plant costs that are
included in rates to prevent double recovery.
• Staff recommends that the LCAR be updated to $17.64/MWh when new rates become
effective.
Respectfully submitted this 56 day of May 2012.
Donald L. H 11,11
Deputy Attorney General
Technical Staff: Keith Hessing
Kathy Stockton
Patricia Harms
Shelby Hendrickson
Mike Louis
i:umisc:comments/ipce 12. I4dhkhphklssbmlrps comments.doc
STAFF COMMENTS 19 MAY 30, 2012
Langley Gulch Project Budget Performance Summary
Approved Estimated Amount over
Commitment Project Commitment
Estimate Spend Estimate
Gas Turbine $56,281,662 $56,243,839 ($37,823)
Steam Turbine $35,710,905 $35,862,359 $151,454
EPC Contract $221,421,431 $215,723,168 ($5,698,263)
Site Procurement $1,950,000 $2,000,000 $50,000
Water Rights $2,081,269 $2,083,419 $2,150
NEPA Permitting $150,000 $214,431 $64,431
Air Permitting $320,000 $390,000 $70,000
Water Line Construction $4,425,000 $4,580,000 $155,000
Gas Line Construction $1,550,000 $3,170,000 $1,620,000
Misc. Equipment (Idaho Power Supplied) $331,150 $2,570,632 $2,239,482
Capitalized Property Taxes $2,881,277 $1,444,431 ($1,436,846)
Idaho Power Engineering and Oversight $1,900,000 $2,820,000 $920,000
RFP Pricing Components (including startup $500,000 $5,574,298 $5,074,298
Transmission*
$17,856,400 $22,170,060 $4,313,660
AFUDC $49,259,379 $46,569,937 ($2,689,442)
Totals $396,618,473 $401,416,574 $4,798,101
*AFUDC is included in the Estimated Project Spend but is not included in the Commitment Estimate, AFUDC is approximately $1 million.
Attachment A
Case No. IPC-E-12-14
Staff Comments
5/30/12
IDAHO POWER COMPANY
JURISDICTIONAL SEPARATION STUDY
LANGLEY REVENUE REQUIREMENT
IDAHO PUBLIC UTILITIES COMMISSION STAFF
A D : F G H ______
STAFF ADJUSTMENT STAFF ADJUSTMENT STAFF ADJUSTMENT STAFF ADJUSTMENT
COMPANY
____
COMPANY - DEPRECIATION TRANSMISSION - OUT-OF-PERIOD - RFP COST L - STAFF STAFF
TOTAL - IDAHO TAX FINE TUNING - OVERBUILD - COST - DISALLOWANCE 4. - TOTAL IDAHO
DESCRIPTION jYSTEM - IDAHO RETAIL IDAHO RETAIL IDAHO RETAIL - - IDAHO RETAIL 4.
4 S.JMMARYOFRESULTS S RATE OF RETURNUNDER PRESENT RATES
6 TOTAL COMBINED RATE BASE 351,994,174 336,701,102 522.937 (1,033,15 (64,639) (216,269) . 351,166,786 335,909,569
7 -
OPERATING REVENUES _______
FIRM JURISDICTIONAL SALES - 0 -- 0 - 0 0
10 HOKU1STBLOCK ENERGY SALES 0 -- - 0 0 0
SYSTEM OPPORTUNITY SALES 32274040 30,780,672 - 0 32,274,040 30,780,672
OTHER OPERATING REVENUES 0 0 - - 0 - 0 0
TOTAL OPERATINGREVENUES 32,274,040 30,780,672 - - - - - --32,274040 30,780,672
14L OPERATING EXPENSES - - - 0 0
OPERATION & MAINTENANCE EXPENSES 28,080,105 27,854,301 0 0 28.080,105 27,854,301
14. DEPRECIATION EXPENSE 13,662,682 13,069,788 - (1,492,644)' (20,736) (1_)1 (8169) 12,072,046 -11_548_056
17L AMORTIZATION OF LIMITED TERM PLANT - 0 i 0 0 0 - 01 0 0
TAXES OTHER THAN INCOME 1,432,047 1 1,369,989 0 (435 - (273) (878) 1,426,291 1,364,482
REGULATORY DEBITS/CREDITS - 0 - - 0 C) 0 - 0 0 0 0
pj PROVISION FOR DEFERRED INCOME TAXES 64,251,378 61,475,612 448.770 1 (205.011) (12,787) (41,251) 64,447,126 61,662,903
21J INVESTMENT TAX CREDIT ADJUSTMENT 11140,104 10,658,833 (20,402) (34,075) (2,133) (7,130) 11,073,546 10,595,151
FEDERAL INCOME TAXES
STATE INCOME TAXES
- (64,153,899): (81.268,951) 74,342
-
207,380
42,237
12,983 1 2,644 j
41,155
8,319
(63,800,743) (60,931,115)
TOTAL OPERATING EXPENSES
(12963928
41,448,4901
(12382082) (24)
- - (1,000)[
(12907939)
40.390,434
(12328524)
39.765.255
25f OPERATING INCOME (10,667,818)1 40,777490
- (9.996,818)
(991,959)
991,959
(14.559)
- 14.559 1,000
(7,954)
7.954 (9,609,762) (8,984.583)
26j
27
ADD: IERCO OPERATING INCOME
CONSOLIDATED OPERATING INCOME
Oj
(10,667,8i
0
- (9,996,818) - 991.959
0
- 14,559
0
1,000
0_
7,954
-
0
(9,809,762)
0
(8,984,583)
28 1 RATE OF RETURN UNDER PRESENT RATES -303% -2.97% - -3.03%
-
-2.74% -2.67% 1 30 DEVELOPMENT OF REVENUE REQUIREMENTS
- 7.860%1 7.860%
- -
7860%
-
7.860% - 7860%] 7860% 7860% 7860% 311 RATE OF RETURN Q 10.5% ROE -
RETURN 27,650.990 26464,707 -- 41,103 i - - (81,206) (16,999) 27,585,994 - - 26,402,492
-34] EARNINGS DEFICIENCY - -. 38318,808 36461,525 - (950,856) (95,765) - (6,081)' (24,952) - 37,195,756 35,387,075
35_}ADDCWIP (HELLS CANYON REUCENSING) 0 - 0 0 0 0 4 0 0 0
:DEFICIENCY WITH CWP 38,318,808 - 36,461,525 - (950856) (95,765) - (6.081)4 (24,952) - 37.195,756 35.387.075
------------------------------------
1.642 --
1.642
- -------4------ 1.642 1.642 1.642 ---.-----
1.642 1.642 1.642 38 NET-TO-GROSS TAX MULTIPLIER
391 j REVENUE DEFICIENCY - 62,919,4831 59.889,823 - - (1,561,305) (157,245) (9.98S)t (40,972> - 61,075,432 58,105,578
CD
CD
CD
Idaho Power Company
Calculation of Revenue Impact
State of Idaho
June 1, 2012 Rates to Staff Proposed Langley Increase
Effective July 1, 2012
Summary of Revenue Impact
Current Base Revenue to Proposed Base Revenue
Total Percent
Rate Average Normalized Current Adjustments Proposed Change
Line Sch. Number of Energy Base to Base Base Cents Base to Base
No Tariff Description No. Customers (1) (kWh) Revenue Revenue Revenue Per kWh Revenue
Uniform Tariff Rates:
I Residential Service 1 399,329 4,896,272,827 $382,557,620 26,989,202 $409,546,822 8.36 7.05%
2 Master Metered Mobile Home Park 3 23 4,942,681 $365,934 25,816 $391,751 7.93 7.05%
3 Residential Service Energy Watch 4 0 0 $0 - $0 0.00 0.00
4 Residential Service Time-of-Day 5 0 0 $0 - $0 0.00 0.00
5 Small General Service 7 28,165 144,888,296 $14,438,119 1,018,600 $15,456,720 10.67 7.05%
6 Large General Service 9 31,614 3,480,101,459 $193,609,530 13,659,032 $207,268,561 5.96 7.05%
7 Dusk to Dawn Lighting 15 0 6,481,376 $1,165,133 82,199 $1,247,332 19.24 7.05%
8 Large Power Service 19 116 1,978,623,647 $84,056,432 5,930,129 $89,986,561 4.55 7.05%
9 Agricultural Irrigation Service 24 16,642 1,720,204,410 $107,859,524 7,609,422 $115,468,947 6.71 7.05%
10 Unmetered General Service 40 2,030 15,807,753 $1,094,576 77,222 $1,171,798 7.41 7.05%
11 Street Lighting 41 361 23,165,568 $2,939,669 207,392 $3,147,061 13.59 7.05%
12 Traffic Control Lighting 42 397 2,981,282 $140,093 9,883 $149,976 5.03 7.05%
13 Total Uniform Tariffs 478,677 12,273,469,299 $788,226,630 55,608,898 843,835,528 6.88 7.05%
14 SDecial Contracts:
15 Micron 26 1 451,138,622 $17,298,128 1,220,372 $18,518,500 4.10 7.05%
16 J R Simplot 29 1 203,558,197 $6,787,889 478,881 $7,266,771 3.57 7.05%
17 DOE 30 1 244,266,665 $8,466,979 597,340 $9,064,319 3.71 7.05%
18 Hoku - Retail 32 1 0 $2,836,120 200,087 $3,036,207 0.00 7.05%
19 Total Special Contracts 4 898,963,484 $35,389,117 2,496,680 $37,885,797 4.21 7.05%
20 Total Idaho Retail Sales 478,681 13,172,432,783 $823,615,747 $58,105,578 $881,721,325 6.69 7.05%
Attachment C
Case No. IPC-E-12-14
Staff Comments
5/30/12 Page 1 of 2
Line
No Tariff Description
Uniform Tariff Rates:
1 Residential Service
2 Master Metered Mobile Home Park
3 Residential Service Energy Watch
4 Residential Service Time-of-Day
5 Small General Service
6 Large General Service
7 Dusk to Dawn Lighting
8 Large Power Service
9 Agricultural Irrigation Service
10 Unmetered General Service
11 Street Lighting
12 Traffic Control Lighting
13 Total Uniform Tariffs
14 Special Contracts:
15 Micron
16 JRSimplot
17 DOE
18 Hoku - Retail
19 Total Special Contracts
20 Total Idaho Retail Sales
Attachment C
Case No. IPC-E-12-14
Staff Comments
5/30/12 Page 2 of 2
Idaho Power Company
Calculation of Revenue Impact
State of Idaho
June 1, 2012 Rates to July 1, 2012 Rates (Langley Gulch Increase)
Effective July 1, 2012
Summary of Revenue Impact
Current Billed Revenue to Proposed Billed Revenue
Total Percent
Rate Average Normalized Current Adjustments Proposed Change
Sch. Number of Energy Billed to Billed Total Billed Cents Billed to Billed
No. Customers (1) (kWh)(1) Revenue Revenue Revenue Per kWh Revenue
w/4 Base Langley
399,329 4,896,272,827 $392,790,830 $26,989,202 $419,780,032 8.57 6.87%
3 23 4,942,681 $376,264 $25,816 $402,081 8.13 6.86%
4 0 0 $0 $0 $0 0 0
5 0 0 $0 $0 $0 0 0
7 28,165 144,888,296 $14,845,545 $1,018,600 $15,864,146 10.95 6.86%
9 31,614 3,480,101,459 $193,701,774 $13,659,032 $207,360,806 5.96 7.05%
15 0 6,481,376 $1,174,563 $82,199 $1,256,763 19.39 7.00%
19 116 1,978,623,647 $83,784,476 $5,930,129 $89,714,605 4.53 7.08%
24 16,642 1,720,204,410 $108,055,628 $7,609,422 $115,665,050 6.72 7.04%
40 2,030 15,807,753 $1,097,343 $77,222 $1,174,564 7.43 7.04%
41 361 23,165,568 $2,959,058 $207,392 $3,166,450 13.67 7.01%
42 397 2,981,282 $139,878 $9,883 $149,761 5.02 7.07%
478,677 12,273,469,299 $798,925,359 $55,608,898 $854,534,257 6.96 6.96%
26 1 451,138,622 $17,204,291 $1,220,372 $18,424,664 4.08 7.09%
29 1 203,558,197 $6,740,257 $478,881 $7,219,138 3.55 7.10%
30 1 244,266,665 $8,408,844 $597,340 $9,006,184 3.69 7.10%
32 1 0 $2,836,120 $200,087 $3,036,207 0 7.05%
4 898,963,484 $35,189,512 $2,496,680 $37,686,192 4.19 7.09%
478,681 13,172,432,783 $834,114,871 $58,105,578 $892,220,449 6.77 6.97%
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 30TH DAY OF MAY 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-12-14, BY E-MAILING AND MAILING A COPY THEREOF, POSTAGE
PREPAID, TO THE FOLLOWING:
LISA D NORDSTROM COURTNEY WAITES
JULIA A HILTON GREG SAID
IDAHO POWER COMPANY TIM TATUM
P.O. BOX 70 IDAHO POWER COMPANY
BOISE IDAHO 83707 P0 BOX 70
[e-mail] BOISE ID 83707-0070
[e-mail] gsaid(idahopower.com
PETER J RICHARDSON DR DON READING
GREGORY M ADAMS 6070 HILL ROAD
RICHARDSON & O'LEARY BOISE ID 83703
P0 BOX 7218 dreadingc2imindspring.com
BOISE ID 83702
[e-mail]
greg(richardsonando1eary.com
RICHARD E MALMGREN THORVALD A NELSON
MICRON TECHNOLOGY INC FREDERICK J SCHMIDT! ET AL
8005 FEDERAL WAY HOLLAND & HART
BOISE ID 83716 63805 FIDDLERS GREEN CIRCLE
rema1mgrenmicron.com STE 500
GREENWOOD VILLAGE CO 80111
[e-mail]
[e-mail]
ERIC L OLSEN ANTHONY YANKEL
RACINE OLSON NYE ET AL 29814 LAKE ROAD
P0 BOX 1391 BAY VILLAGE OH 44140
POCATELLO ID 83204 [e-mail]
[e-mail]
S CRETARY
CERTIFICATE OF SERVICE