20090417Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6618
R'"",',"" '-lH:Gt!
2009 APR I 7 Pl1 3: 4 I
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY)
TO MODIFY ITS RULE H LINE EXTENSION )
TARIFF RELATED TO NEW SERVICE )
ATTACHMENTS AND DISTRIBUTION LINE )INSTALLATIONS. )
)
CASE NO. IPC-E-08.22
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilties Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notice of
Modified Procedure and Notice of Scheduling issued in Order No. 30719 on Januar 21, 2009, in
Case No. IPC-E.08-22, submits the following comments.
BACKGROUND
On October 30, 2008, Idaho Power Company fied an Application with the Commission
seeking authority to modify its Rule H tariff relating to new service attachments and distribution
line installations and alterations. Specifically, the Company wishes to update line installation
charges and allowances, thereby shifting more of the cost burden for new service attchments and
distribution line installations or alterations from general ratepayers to new customers requesting
construction for these services. The tariff has also been extensively reworded and
STAFF COMMENTS APRIL 17, 2009
formatted to make it easier to read and understand. Idaho Power also proposes to update its
charges and credits in its Rule H tarff on an annual basis.
STAFF ANALYSIS
Before beginning further discussion, Staff believes it would be helpful to define
terminology used in discussing line extension policies. Several important and frequently used
terms are defined below.
Distribution system or distribution refers to that portion of the delivery system
closest to the customer with voltages under 44 kV. The distribution system
includes line extensions and terminal facilties.
Line extension is any installation of new distribution facilities (excluding
relocations) or alteration of existing distribution facilties owned by the
Company other than terminal facilities.
Terminal facilities include transformer, meter and service cable.
Service, services, or service cable refers to the conductor providing usable
voltage to the customer meter from, typically, the Company's last pole,
junction box or transformer. The service cable may be overhead or
underground.
Staff believes it may also be helpful before continuing further to discuss some general
policies and practices related to distribution plant cost recovery since it differs somewhat from
generation and transmission plant. The capital cost of installng new generation and transmission
plant has always generally been recovered through rates paid by all customers. Hook-up fees,
impact fees, or other charges at the time a new customer begins taking service have never been
charged for the purpose of recovering the costs of building new generation and transmission
facilties. In fact, in accordance with prior decisions of the Idaho Supreme Cour, such fees
canot be charged for new plant that cannot be attributed specifically to serving new customers. i
In the case of distribution plant, however, it is possible to associate specific facilties with
specific customers who use them. For example, meters are physically attached to customers'
buildings, service lines run directly to each customer's premises, and transformers serve a specific
customer or group of customers. Even most distribution lines can be associated with serving
i Building Contractors Association v. IPUC and Boise Water Corporation. 128 Idaho 534, 916 P.2d 1259 (1996);
Idaho State Homebuilders vs. Washington Water Power. 107 Idaho 4 i 5,690 P.2d 350 (1984).
STAFF COMMENTS 2 APRIL 17, 2009
specific subdivisions, businesses along a street or specific neighborhoods. Because of this, the
costs of new distribution plant have, throughout most of Idaho Power's history, been recovered in
two ways - partially through up-front capital contributions from new customers, and partially
through electric rates charged to all customers. Up-front charges are either based on estimates
prepared by Idaho Power for each line extension job (work order costs), or are specified in the
Rule H tariff for standard tasks or materials. The portion collected through electric rates
represents the investment in new facilities made by Idaho Power. It is often referred to as an
"allowance. "
Allowances
Idaho Power proposes to reduce line extension allowances for nearly all customer classes.
The underlying rationale behind the Company's proposal is that growth should pay for itself, and
that by reducing allowances and refunds, one cause of upward pressure on electric rates will be
relieved. Although Staff agrees in principle with the Company's rationale, Idaho Power has done
no analysis to prove that growth is not paying for itself, nor has the Company done any analysis to
determine specifically what amounts of allowances and refunds can alleviate upward pressure on
rates. Idaho Power's position seems to be that because it has fied four general rate cases within
the past six years and has added two gas-fired peaking plants in the same timeframe, that new
customer growth is causing upward pressure on rates. The Company concludes that a reduction
in Company investment in new distribution plant is necessary and proposes a reduction in
allowances based strictly on policy without supporting analysis.
Staff agrees with Idaho Power that new customer growth, combined with the effects of
inflation, do indeed cause upward pressure on rates. Staff also supports a policy to reduce upward
pressure on rates, justified by sound analysis. A much more complete discussion and analysis of
the effects of new customer growth and inflation is presented in Attchment NO.1.
Staff believes that the goal in setting allowance and refund amounts for distribution line
extensions should be to eliminate the impact on existing electric rates. More specifically, Staff
believes the line extension rules should provide a new customer allowance (Company investment)
that can be supported by electric rates paid by that customer over time. If the line extension costs
exceed the allowance, then the new customer would pay an up-front contribution for the
difference rather than including the excess costs in electric rates paid by all customers. In order to
STAFF COMMENTS 3 APRIL 17, 2009
properly establish an allowance, a refund and the potential for additional customer contribution, a
detailed analysis of distribution investment embedded in existing electric rates must be conducted.
Stafls Approach to Computing Allowances
The Company's investment has traditionally been provided as an allowance towards the
cost of new facilities. Staffs approach to determining a Company-provided allowance for service
connections and line extensions was to determine what equivalent investment the Company can
make that wil be supported by the revenue stream embedded in the Company's current rates.
Attachment NO.2 details the approximate size of that investment for residential, small
commercial, large commercial, irrigation and industrial classes. All calculations assume average
consumption levels for customers within each class. Staff used the Commission's last rate Order
in Case No. IPC-E-08-10 as the basis of the calculations. Assumptions used in making the
calculations are provided in Attachment 3. Staff also used the cost of service study accepted by
the Commission in Case IPC.E-08-10 as a basis for calculations. A summary of the cost of
service figures used in the analysis is included as Attachment 4.
The equivalent investment per residential customer is calculated using the cost of service
study and capital structure accepted by the Commission. Attachment 5 summarizes the
calculation of the investment for the residential class. The net distribution plant and terminal
facility value of $11 04. 1 2 per customer (plant in service less accumulated depreciation and
amortization) is used to calculate the revenue requirement associated with the return on common
equity grossed up to recognize the income taxes associated with the retu ($1104.12 x (0.05173 x
1.642) = $94.36). Debt service costs (0.03007 x $1104.12 = $33.20) are added to the equity
retur and tax calculation to produce the total revenue requirement associated with the cost of
capital and associated income taxes of$127.56. Depreciation expense of $45.26 (actual
distribution plant and terminal facilties depreciation expense per customer) is added to the capital
and tax cost to produce a total revenue requirement related to distribution plant and terminal
facilties of $172.25.
This revenue stream is embedded in the Company's curent sales rate structure. Staff used
this revenue stream to calculate the new Company investment that can be supported by current
rates without applying either upward or downward pressure on the Company's rate structure. The
revenue stream represents the total cost of capital, with associated taxes, plus depreciation
STAFF COMMENTS 4 APRIL 17, 2009
expenses associated with the Company's distribution plant and terminal facilties. Because the
actual depreciation expense is based upon a gross investment greater than the net plant investment
built into rates, it follows that the new investment can be an amount larger than the current
embedded net investment. The composite of the total cost of capital and associated taxes
expressed as a percentage of rate base is 11.501 percent. The composite depreciation rate for
distribution and terminal facilities is 2.47 percent. The combined total of these two percentages
(13.971 percent) represents the relationship of the current revenue stream to new gross investment.
Dividing the revenue stream of $172.25 by 13.971 percent produces the revenue neutral
investment of $1232.44, which Idaho Power can make to provide service to new residential
customers.
Attachment NO.6 summarizes similar calculations for other customer classes.
Even though the Company's embedded investment is split between investment in
distribution plant and terminal facilties, Staff recommends that all of the recommended Company
investment be applied to the cost of providing terminal facilties. Staff maintains that it is only
important that the total value of the Company's investment be equal to the total embedded cost-
not that the Company's investment be applied to both terminal facilties and distribution facilties
in the exact proportion as are their embedded costs. Terminal facilties are defined as a
transformer, meter, and service drop. Staffs estimates of the cost of terminal facilties are shown
in Attachment NO.7.
Stafls Recommended Allowances
Residential
Staff recommends an allowance of terminal facilities for the residential customer class.
Because the average investment for existing customers ($1,232) is fairly close to Staffs estimate
of the cost of overhead terminal facilties ($1,444), Staff believes terminal facilties should be
provided at no cost to the residential customer. Even though the allowance cost of terminal
facilities is slightly more than the average investment, Staff believes that simplicity, both to the
Company and the customer, is important1 Moreover, within the residential class (and all other
classes too) there is wide variation between customers. Obviously, some customers wil generate
much less revenue than the class average and others wil generate much more. Consequently,
instead of precisely matching the recommended allowance with the average embedded investment
STAFF COMMENTS 5 APRIL 17, 2009
for the class, Staff believes good judgment and simplicity support an allowance of terminal
facilties.
Under the present tariff, the allowance is equal to terminal facilities plus an amount
ranging from $800 to $1,300 depending on whether the customer is in a subdivision and whether
the home is all-electric or gas.heated. In this case, Staff does not recommend that any amount
beyond the cost of terminal facilties be included as an allowance. Staff also does not recommend
a different allowance amount based on whether a customer has gas or electric heat. Gas has
become the predominant heating choice where it is available because it is generally cheaper and
more efficient. Staff does not wish to encourage electric heat by offering a higher allowance.
For new residential homes outside of subdivisions, Idaho Power proposes an allowance of
$1,780 per customer, which it calculates to be the cost of standard overhead terminal facilities.
Staffs proposed allowance is similar, but expressed as the cost of terminal facilties rather than a
fixed dollar amount. Staff has no objection to stating the allowance in the tariff as a fixed dollar
amount, however, as long as the amount is updated through an annual filing.
Because terminal facilities costs in residential subdivisions are different than for
individual residences and because of other factors unique to subdivisions, Staffs proposed
allowances for subdivisions wil be addressed separately.
Subdivisions
Staff believes that homeowners or individual builders who request new service within
subdivisions are entitled to the same allowances for terminal facilties as are other customers not
located in subdivisions. Staffs proposed allowance for all residential customers is the cost of
overhead terminal facilities.
However, transformers, one component of the proposed terminal fåcilties allowance, are
generally installed prior to building within the subdivision, at the same time as line extensions are
completed. On the other hand, installation of the other components of terminal facilties, a
service attachment and a meter, is generally requested by the homeowner or builder at the time of
building construction, not by the subdivider at the time the subdivision is developed.
Consequently, in order to be consistent and provide all residential customers comparable
allowances, Staff proposes that subdividers pay all line extension costs, including transformer
costs, but that transformer costs be subject to refund to the subdivider as new homes are built and
STAFF COMMENTS 6 APRIL 17, 2009
customers are connected. Homeowners and builders would receive standard service attchments
and meters at no cost. Making transformer costs subject to refund as individual lots are developed
insures that all residential customers receive equal allowances, but relieves the Company of the
risk of bearing the cost of transformers should lots not be developed. If transformer costs are not
subject to refund, there is a possibilty that the Company wil have invested in facilities intended
to be paid through rates, but have no customers generating revenue through rates. This refud
method puts the risk of development on the subdivision developer rather than on Idaho Power's
ratepayers. Because of the curent economic situation, Staff believes that the risk of subdivisions
progressing as planned is now greater than ever. Staff believes it would be inappropriate for
ratepayers to bear any investment risk in new facilties installed to serve speculative
developments.
Refuds for transformers would be made to subdividers as each new customer is
connected. The amount of the refund should represent the installed cost of the transformer needed
to serve the new customer. Where single transformers serve multiple customers, the amount of
the refund should be equal to the total cost of the transformers installed in the subdivision divided
by the total number of lots in the subdivision.
Transformer refunds under Staffs proposal would not replace the $800 residential
subdivision refud which is curently offered under the present policy. Transformer refunds are
not intended to be a substitute for the curent refund amount, nor are they intended to have
equivalent value. They are a portion of the terminal facilties allowance paid when a new
customer takes service and are simply a means of relieving Idaho Power and its ratepayers of
investment risk.
Small Commercial
The small commercial class (Schedule 7) is very similar to the residential class in terms of
required distribution and terminal facilties. In fact, Staff assumes that the cost of terminal
facilties is only slightly higher than for residential customers, since commercial customers are
demand metered. However, on average, small commercial customers' energy usage is less than
the residential customer class. Consequently, Idaho Power's embedded investment per customer
is less for small commercial customers than for residential customers. As a result, Staff
recommends that the allowance for Schedule 7 customers be set at 60 percent of the cost of
STAFF COMMENTS 7 APRIL 17,2009
overhead terminal facilties for single phase service. Staff proposes that small commercial
customers who require three phase service be required to pay all additional costs above the
allowance amount for single phase customers.
Large Commercial, Irrigation
For the large commercial and irrigation classes (Schedules 9 and 24 respectively), the
embedded Company investment per customer exceeds Staffs estimated cost of terminal facilties
in all cases. Consequently, for all customers in both of these classes, Staff recommends that an
allowance equal to the cost of overhead terminal facilities be provided by the Company and that
no allowance be offered toward line extension costs.
Staff recommends an allowance equivalent to the cost of overhead terminal facilties for
all large commercial and irrigation customers whether they require single or three phase service.
Most of these customers typically require three phase service, and the embedded investment can
support the cost of three phase facilities. Single phase large commercial and irrigation customers
generate less revenue and have a lower embedded investment, but they also require less expensive
terminal facilties. Therefore, Staff believes an allowance of terminal facilities is reasonable for
both single and three phase service.
Industrial
Under the current Rule H, allowances for industrial (Schedule 19) customers are
determined on a case-by-case basis due to the wide diversity in both customer usage and needed
distribution facilities. Both Idaho Power and Staff propose to continue to determine allowances
for industrial customers on a case-by-case basis.
Staffs proposed allowances for all customer classes are summarized in Attachment NO.8.
Underground Service
Staffs proposed allowances are based on the cost to provide an overhead service
attachment. For residential (Schedule 1) and small commercial (Schedule 7) customers, the
Company should provide underground service at no additional charge if the customer supplies the
trench, backfill, conduit and compaction per Company specifications. Otherwise, customers
requesting underground service should be required to pay the difference between the cost of
STAFF COMMENTS 8 APRIL 17, 2009
providing underground service and the cost of providing overhead service. The overhead-
underground differential should not be subject to refund. Line extension costs associated with
Company betterments should continue to be the Company's responsibilty and not chargeable to
the customer.
Examples
Staff prepared several examples of hypothetical cases to compare the existing Rule H to
the Company's proposal and to Staffs proposal. These examples are included as Attachment No.
9. None of the examples are intended to be representative of all cases for an entire customer class.
Their purpose is simply to ilustrate how the proposed allowances and refunds would affect
customers and to give a general indication of how costs would be shifted. In each of the examples,
all customers would receive an allowance of terminal facilities, but none of the customers would
receive an allowance for line extension work upstream of the customer's transformer.
The first example is for a residential line extension not located in a subdivision. Under the
proposed new Rule H, the net payment by the customer would be greater than under the existing
rule, but the entire payment is stil subject to refud. The difference in the net payment is due
entirely to the reduction of the allowance offered under the current rule. The size of the
allowance under the current rule is overhead terminal facilties plus $1000 for residences without
electric space or water heating and $ 1 300 for residences with electric space and water heating.
The second example compares costs under both the existing and proposed rules for five
actual subdivisions which were completed in recent years. In each of the five cases, costs are
higher under the proposed rule than under the existing rule due to reduced allowances. Note that
the only difference between Idaho Power's and Staffs proposals is that Idaho Power proposes that
an allowance for transformers be applied against the work order cost initially, whereas Staff
proposes that refunds for transformers be given at the time service is provided to each lot. This
example also ilustrates how much work order costs can vary from one subdivision to the next.
The third and fourth examples are for commercial and irrigation line extensions,
respectively. In the irrigation example, Idaho Power's proposal would result in a higher overall
cost for this customer because the customer requires terminal facilties that are more expensive
than the standard three-phase overhead terminal facilties allowance proposed by the Company.
Under Staffs proposal, there would be no change from the current Rule H.
STAFF COMMENTS 9 APRIL 17, 2009
In the commercial example, the customer would pay more under Idaho Power's proposal,
again because this customer's terminal facilties are more costly than "standard" three-phase
overhead terminal facilties. Under Staffs proposal, allowances for the large commercial class
would be greater than they currently are under the existing rule; consequently, most customers
would likely see a reduction in the overall cost of line extensions.
Because Staffs proposed allowances for the residential, large commercial and irrigation
customer classes are in terms of terminal facilties rather than in terms of dollar amounts as
proposed by Idaho Power, the allowances wil change over time as costs increase due to inflation.
If the Commission chooses to accept Staffs proposal for allowances, Staff recommends that Idaho
Power be required to anually submit "standard" terminal facilities costs to the Commission so
that Staff can track changes in costs and address complaints and inquiries it receives regarding
Rule H.
Work Order Cost Method and Controls
Currently under Rule H, the Company charges line extension costs to the customer based
on work order cost estimates. Work order cost estimates are prepared by the Company before
construction. It is Staffs understanding that Idaho Power does not, except in the case of unusual
conditions, adjust work order costs after construction has been completed to reflect actual
installation costs, and modify the customer's bil accordingly.
Based on a study of 2008 line extension work orders2, the Company's own analysis
indicates that 43 percent of work order cost estimates differed from actual costs by at least 15
percent and more than $800. In other words, estimated costs significantly differed from actual
costs much of the time. Staff obtained a confidential Sarbannes-Oxley report, covering work
order controls for work orders involving contributions in aid of construction. On page 3 of the
report this statement appears, "...there is not a work order review process that validates the
estimated cost is appropriate at the time the estimate is developed." When the Company bils
customers for estimated costs rather than actual costs, some customers may be either overbiled or
underbiled substantially. For 2008, the total actual costs exceeded the amounts collected from
customers by $5.6 milion (12.2%). It should be pointed out, however, that some of this
2 Control #6 Work Order Estimated Costs Versus Actual Costs, January 21,2009; Memo frm Ben Hendry to Rick
Schweitzer and Waren Kline; report prepared to satisfy Sarbannes-Oxley requirements.
STAFF COMMENTS 10 APRIL 17, 2009
difference is due to work order estimates that were prepared but never built and also because
customer cost quotes only include general overheads at 1.5 percent while the actual overhead
incurred by Idaho Power is 15.75 percent. Nevertheless, Staff is concerned that not enough
contributions in aid of construction were collected for 2008, and that this significant under-
collection may have been made up by other ratepayers. Staff recommends that a more thorough
audit be conducted to better quantify and define this problem, and that Staff and the Company
work jointly to propose improvements in the process if significant problems are identified.
Purchasing Procedures
Staff interviewed employees of Idaho Power representing the purchasing deparment. Its
purchasing procedure is called "Strategic Sourcing Process" and has five steps. According to
these employees, the design of and controls over this process are intended to comply with
Sarbannes-Oxley requirements. These controls are tested by internal and external auditors. Staff
believes these procedures appear to be well considered and appropriate.
Staff reviewed current RFPs and a purchase contract for several items involved in the
current request for tariff changes. These items included meters, several sizes of transformers and
350 cable. A review of the quoted and contracted prices for these items demonstrates wide
variances in practices among suppliers. In addition, quoted prices for some items are
contractually tied to external commodity indexes. In the case of 350 cable those indexes are an
aluminum index and a copper index. These pricing strategies are designed to protect suppliers
from losses resulting from volatile or increasing commodity prices. During periods of increasing
commodity prices, cumulative increases can occur. This can result in prices changes, which are
seen as "spikey" or unusually large.
The amounts seen in work order charges may be additive combinations of quoted prices,
delivery charges and inventory costs. For inventory items such as meters or transformers, Idaho
Power uses a cost averaging method which averages costs of current inventory with costs of new
purchases.
General Overhead Rate
Staff reviewed the cost allocation formula for curent rates. Staff believes Rule H
overhead costs are in current electric rates to the extent they exceed the 1.5 percent limitation.
STAFF COMMENTS 11 APRIL 17, 2009
Including the entire overhead rate in Rule H work orders would result in Idaho Power collecting
the difference of 13.5 percent in both work orders and in current electricity rates. Staff believes
this is a timing problem, which can be resolved in the next rate case. The case would set rates
based on costs which do not include that portion of construction overhead belonging to Rule H
work orders. Simultaneously, the overhead rate for Rule H could include the 15 percent, effective
on the same day as the new rates. This would shift costs from general rates to those requesting
Rule H line extensions.
Vested Interest Refund Period
Idaho Power proposes to reduce the time limitation to receive vested interest refunds from
five years to four years. In support of its position, the Company cites a reduction in
administrative burden and points out that less than two percent of customers eligible for vested
interest refunds receive them in the fifth year.
Staff does not believe Idaho Power has made a convincing case for reducing the refud
period, and, in fact, Staff believes the Company's rationale is somewhat contradictory. Ifvery
few refunds are actually made in the fifth year as Idaho Power contends, it does not seem
reasonable that tracking these refunds would present a significant administrative burden.
Moreover, in the future, Staff believes that more refunds wil be made in the fifth year now that
building activity has slowed from the rapid pace of the past several years and subdivisions are
slower to fiL.
Idaho Power also proposes that subdividers be eligible for vested interest refunds inside
subdivisions for additional line installations that were not part of the initial line installation. Staff
does not object to this proposed change.
Updated Charges
Idaho Power proposes to update several charges in Rule H including engineering charges,
underground service attachment charges, overhead and underground temporary service
attachment charges, and overhead and underground temporar service return trip charges. Staff
has reviewed the proposed updated charges and believes they are reasonable based on changes in
labor rates, different installation procedures and changes in calculation methodology.
STAFF COMMENTS 12 APRIL 17, 2009
Formatting Changes
Idaho Power proposes to make formatting changes to Rule H to make the tariff easier to
read and administer. Staff supports the proposed formatting changes.
Changes to Definitions and General Provisions
Idaho Power proposes to add several definitions to clarify discrepancies and identify terms
missing from the curent tariff. Staff supports the addition of all of the proposed definitions, with
the exception of the removal of the 1.5 percent limitation for recovery of general overheads as
discussed earlier in these Staff comments.
For clarification puroses, the Company also proposes several modifications to the
General Provisions section of the tariff. Staff has no objection to these proposed modifications.
Staff does recommend two changes to the tariff provisions related to unusual conditions.
The current definition of "Unusual Conditions" has caused some confusion, which resulted in
complaints being fied with the Commission. The confusion stems in part from the reference to
"construction conditions not normally encountered."
For example, if construction is to take place in an area that is commonly known to be
rocky, a customer requesting service would consider rock digging to be a normally encountered
condition. To that customer, an unusual condition would be something above and beyond the
normal rocky condition one would expect to encounter in that location. The customer then
anticipates receiving a refund of the amount paid for unusual conditions when no out-of-the
ordinary conditions are encountered. However, the Company's cost estimating process excludes
the cost for rock digging and other "unusual conditions" when average Company-wide costs are
calculated. From the Company's perspective, any cost associated with rock digging is project-
specific ("not normally encountered") and wil always be considered an unusual condition. A
refund would be provided only if no rocky conditions are encountered.
Staff does not disagree with the Company's policy with respect to charging customers for
unusual conditions. However, Staff recommends that the definition be revised as follows to
clarify that policy and avoid customer confusion:
Unusual Conditions are construction conditions not normally encountered,
but which the Company may encounter during construction which impose
additional, project-specifc costs. These conditions may include, but are not
limited to: frost, landscape replacement, road compaction, pavement replacement,
STAFF COMMENTS 13 APRIL 17, 2009
chip-sealing, rock digging/trenching, boring, non-standard facilities or construction
practices, and other than available voltage requirements. Costs associated with
unusual conditions are separately stated and are subject to refund.
Another issue raised by customers is delayed payment of refuds by the Company when
the anticipated unusual conditions are not encountered. There is no provision in the existing or
proposed Rule H tariff identifying the time frame for providing refunds. Staff proposes that a
statement be added to Subsection 6.h., Unusual Conditions Charge, of Rule H to specify that if
unusual conditions are not encountered, the Company wil issue the appropriate refund within 30
days of completion of the project.
Elimination of Line Installation Agreements
Idaho Power proposes elimination of existing language describing Line Installation
Agreements for Line Installation Allowances paid in excess $75,000. The Company does not
believe such agreements are necessary. Staff does not object to the Company's proposal to
remove the existing language.
Relocations in Public Road Rights-of-Way
The Company proposes to add a new section to address funding of roadway relocations
required under Idaho Code § 62-705. This section identifies when and to what extent the
Company wil fund roadway relocations. Specifically, the section outlines Road Improvements
for General Public Benefit, Roadway Improvements for Third-Par Beneficiary and Road
Improvements for Joint Benefit.
Staff concurs with Idaho Power that clarification of the existing Rule H language is
needed to address third-pary requests affecting utilty facilities in public rights-of-way. In
keeping with the goal of having new growth pay its fair share of costs, and to insure consistency
and fairness, Staff believes that inappropriate cost shifting from developers to Idaho Power
customers should be prevented whenever possible. Staff supports the tariff language proposed by
Idaho Power, but recognizes that its effectiveness wil be tested over time and that additional
modifications to the language may be required in the future.
STAFF COMMENTS 14 APRIL 17, 2009
Annual Updates to Charges and Allowances
With regard to annual updates to allowances, Staff supports annual updates if the
allowances as proposed by Idaho Power are accepted by the Commission (i. e., specific dollar
amounts for customers in each class). However, if the Commission accepts Staffs proposed
allowances (or allowances described as the cost of terminal facilties), then anual updates to the
tariff are not necessary in the case of allowances because the cost of terminal facilties wil
automatically change as costs of transformers, meters and services increase. However, Staff does
recommend that a set of "standard" terminal facilities costs be submitted anually to the
Commission for informational puroses to permit Staff to track changes in costs.
Press Release and Letter to Builders
The Notice to Builders and Press Release were included in Idaho Power's Application
received on October 30,2008. Notice was direct mailed to the 400 builders and developers in the
Company's service territory. Staff reviewed the Notice to Builders and Press Release and
determined they were in compliance with the requirements of IDAPA 31.21.02.102.
RECOMMENDATIONS
Staff believes that the cost of new terminal facilties and line extensions needed to serve
new customers should be paid by the customers who cause those costs to be incured. Staff
proposes that Idaho Power reduce its share of the investment in new distribution and terminal
facilities to recover actual customer connection costs not currently recovered through rates,
thereby relieving the upward pressure on rates that is caused by allowances and refunds included
in the curent line extension policy. Staff recommends that the Company's investment in facilities
for each new customer be equal to the embedded costs of the same facilties used to calculate
rates, and that costs in excess of embedded costs be borne by the customers requesting service
through a one-time capital contribution.
Staff calculates that an investment of $1 ,232 would be revenue neutral for the residential
customer class (Schedule 1) based on average annual consumption. Because this amount is nearly
equal to the cost of terminal facilities for a typical residential customer, Staff recommends free
overhead terminal facilties be provided by the Company for residential customers, and that no
allowance be offered toward line extension costs.
STAFF COMMENTS 15 APRIL 17,2009
STAFF COMMENTS 16 APRIL 17, 2009
recognizes that its effectiveness wil be tested over time and that additional modifications to the
language may be required in the future.
Idaho Power has requested an effective date 120 days after receiving an order approving
modifications to Rule H in order to update and test computer systems, train employees, and
update internal documents related to administration of Rule H. Staff supports this request even
though the effective date wil likely be during the height of the annual construction season. Due
to the downturn in the economy, there is very little new construction going on in Idaho Power's
service territory. Consequently, any inconvenience to builders and developers is likely to be
minor.
Respectfully submitted this '1-1'1-I - day of April 2009.
df~û. ~tA,Kr' tine A. Sasser
Deputy Attorney General
Technical Staff:Rick Sterling
John Nobbs
Daniel Klein
i: umisc:commentslipce08.22jnrpsdk
STAFF COMMENTS 17 APRIL 17, 2009
The Effects of Growth and Inflation on Electric Rates
Idaho Power's investment in distrbution plant varies each year from less than $10 milion
to nearly $80 milion. Distribution plant is a significant par of the Company's anual
requirement for new investment dollars. Not surrisingly, the investment in distribution plant
has generally increased through time, paricularly since the mid-80s as shown in the graph
below. New distribution plant investment over time has generally followed a similar pattern to
the addition of new customers over time. Logically, as more new customers have been added,
more new distribution plant has been added to serve them.
90
80
"0 70o."0 60"0c:Y\SO..i:i:~I'40a:~3:30
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10
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Distribution Plant Increase from Prior Year
18,000
16,000 "0o.14,000 "0;i12,000 y\..10,000 o.
8,000 I
6,000 a
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t""1 ,.0 /'I.C\N /'I.C\N II,.I"I"00 00 00 00 C\C\C\C\0 0C\C\C\C\C\C"C\C"C"C\C\0 0t"t"...-..t"t"t"t"t"t"N N
lI New Plant Added - New Customers
Not all new distribution plant that is added is for the purose of serving new customers.
Clearly, meters are periodically replaced, transformers fail, poles must be replaced or relocated,
and other distribution plant must be added or replaced in order to continue to provide service to
existing customers. Although Idaho Power does not track whether new distribution plant is
added for the purpose of serving new customers or to continue to serve existing customers, the
strong apparent correlation shown in the above graph between the addition of new plant and the
addition of new customers would indicate that most new plant is added to serve new customers.
On a per customer basis, Idaho Power's investment in distribution plant has also
increased over time. The graph below ilustrates the Company's investment on a per customer
basis from 1993 to 2007. A similar pattern existed before 1993. It is important to note that these
figures do not reflect the actual cost of distribution facilities, but rather the Company's
i Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 1 of 6
investment in those facilities. The level of Company investment in distribution facilities has
been heavily influenced by changes in line extension policies over the years, as wil be further
discussed in more detail later.
Distribution Plant per Customer
$2,600
$2,400
$2,ZOO
$2,000
$1,800
$1,600
$1,400
$1,00
$1,000
93 94 95 96 97 98 99 00 01 02 03 04 05 06 07
Year
Staff believes that the primary cause of the upward pressure on rates is adding new
customers at higher levels of investment per customer than current rates can support. The
combined effects of inflation on facilties costs, the rate of new customer growth and changes in
line extension policies over time have all been factors. Staff also believes that changes in
construction standards and a trend toward more underground installations have also contributed.
All of these factors affecting the investment required to connect new customers cause
rates to increase. Each new customer that is added requires an investment in distribution plant
and terminal facilties. The new investment is undepreciated, while the investment upon which
the Company's revenue requirement (and rates) is calculated was both lower on a per customer
basis when originally made and is now parially depreciated. Therefore, when the new plant
investment is booked by the Company, the resulting revenue requirement is higher per customer
than it was before the new customers were connected. The Company then has two alternatives:
increase rates to all customers to cover the increased revenue requirement, or decrease the
revenue requirement by shifting more of the investment in new distribution/terminal facilities to
the customer for whose benefit those facilities are built. Staff believes it is more appropriate to
shift more of the costs to new customers.
2 Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 2 of 6
Attachment 1 A shows two simple examples to ilustrate the effects of customer growth
and inflation on a utilty's revenue requirement per customer - one assumes no inflation and the
other assumes a 10 percent anual rate of inflation. When no inflation is assumed, the anual
revenue requirement per customer declines each year because rate base decreases as more plant
is depreciated. If only one customer were present on the system, the anual revenue requirement
- at least the portion represented by depreciation and return on rate base - would decline to
zero after four years. In this example, with the addition of a new customer each year and
replacement of plant after it becomes fully depreciated, the annual revenue requirement per
customer eventually becomes constant. The effect of growth is to cause the annual revenue
requirement per customer to decline less rapidly than it otherwise would with no growth. If
actual numbers for Idaho Power were used instead of simplified hypothetical ones, the effect of
growth is the same, although much less pronounced because of approximately 30-year
depreciation lives and growth rates of less than about five percent.
In the second example, when a 10 percent annual inflation is assumed, the effects on
anual revenue requirement are greatly magnified. Based on the hypothetical numbers in this
example, the anual revenue requirement per customer clearly increases at a faster rate each
year. The graph at the bottom of Attachment 1A shows the difference in revenue requirement
per customer with and without inflation.
Again, in reality, the results for Idaho Power are similar, although much less pronounced
but on a much larger scale. It may also be worth noting from this example that with inflation but
no growth, the annual revenue requirement per customer increases at the same rate of inflation,
but in a sort of stair step fashion. When averaged over several years, inflation compounds the
effects of growth.
Both growth and inflation are causes of higher annual revenue requirement per customer,
but it is not critical to determine how much of the cause is attributable to growth and how much
is attributable to inflation. In fact, even if much of the upward pressure on rates is caused by
inflation, most of the additions to distribution plant are made to serve new customers, not old;
therefore, the new customers should be responsible for the inflationary effects. If not for new
customers, the amount of new distribution plant subject to inflationar pressure would be far
less. To the extent new distribution investment is for replacement of existing facilities, all
customers are responsible for inflationary effects.
3 Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 3 of 6
Staffs proposal in this case does not remove the impact of past inflation from existing
customers. They, along with new customers, are subject to the effects of inflation through
eventual replacement of their facilities. These effects are eventually felt through general rate
increases, since no customer is biled directly for replacement of facilities. Furthermore, under
Rule H as currently structured, new customers pay only the increment above embedded cost
through line extension fees, and in effect, pay the remainder of the cost through rates equal to
what all other customers pay.
Besides new customer growth and inflation, Idaho Power's distribution investment per
customer has also changed as a result of policy changes. Over the past 35 years the line
extension policy for Idaho Power has changed many times, and there does not appear to have
been any consistent basis for these policies. In fact, it appears that the level of Company
investment in the past has been set depending upon how promotional the Company wanted to be
in attracting new customers, depending upon economic conditions at the time or upon other
factors. For example, in 1937 for residential customers, the Company limited its investment to
three times the customer's guaranteed annual minimum biling. Between 1939 and 1945, the
Company increased its investment limit to four and one-halftimes anual revenue. In 1945, the
Company financed the entire cost of serving new customers. In 1948, the investment limit was
10 times anual revenue for residential and farm customers and five times revenue for
commercial and industrial customers. Since 1955, the investment limit has continued to decline,
until presently when the investment limit is approximately three times anual revenue for
residential customers. With these facts in mind, it is apparent that the level of embedded
Company investment per customer has been influenced as much or more by the line extension
policy in effect at the time, as by inflation, rate of customer growth, construction standards or
other factors.
Staffs line extension proposal in this case is based on the calculated embedded costs for
existing customers, which are used to calculate rates. This is exactly the same approach as was
taken in Idaho Power's last major line extension case in 1995. Staff believes this is a more
appropriate method than policies in effect prior to that time.
Despite just completing a recent rate case in which rates were increased, the Company's
current rates are insufficient to cover all of the current average investment per new customer for
required distribution plant and terminal facilties common to each new customer. Rates as set in
4 Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 4 of 6
Idaho Power's recently completed general rate case were established based upon the average
embedded investment per existing customer and are not sufficient to cover all of the current
average investment per new customer. Rates wil, however, support a significant portion of the
required distribution/terminal facilties investment common to each new customer. If the
Company continues to add new customers at costs higher than the average rate base used to
calculate rates, upward pressure on rates wil continue. Eventually another rate increase wil be
necessary. A rate increase may temporarily relieve the revenue deficiency problem caused by
new customer investment, but it wil not eliminate the upward pressure on rates.
Staff believes that the Company's investment in facilities for each new customer should
be equal to the embedded costs of the same facilities used to calculate rates. Costs in excess of
embedded costs should be paid through one-time capital contributions by the new customers.
Staff fuher believes that those costs over and above the costs for standard overhead service with
pole-mounted transformers and overhead distribution lines should be paid entirely by the
customer requesting the new facilities.
By using the approach outlined here, Staff believes that the combined effect of new
customers and inflation has been minimized, at least for distribution plant. The graph below
shows the Company's distribution plant investment per customer both in nominal and real terms
(2008$). As discussed previously, distribution plant investment per customer has increased
steadily over time in nominal terms, but in real terms (when the effects of inflation are removed)
distribution plant investment per customer has been very stable. Staff believes this is a good
indication that the approach used to establish the current allowances is sound, and that it should
continue to be used in the future.
Distribution Plant per Customer
52,600
$2,400
$2,200
$2,000
$1,800
51.600
$1,400
$1,200
$1.000
93 94 95 96 97 98 99 00 01 02 03 04 05 06 07
Year
- Nominal $ -Real (2008$)
5
Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/1 7/09 Page 5 of 6
Based on its analysis, Staff believes that adding new customers at higher required levels
of investment needed to serve them puts upward pressure on rates. Staff agrees with Idaho
Power that absent ongoing rate increases for all customers, the level of Company investment in
new distribution facilties must be reduced in order to relieve upward pressure on rates.
6 Attachment 1
Staff Comments
Case No. IPC-E-08-22
04/1 7/09 Page 6 of 6
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Net Plant and Allowable Investment by Customer Class
Net Plant per Customer*
Allowable Investment per Customer
Distribution
$677
$750
Terminal
Facilities
$427
$482
Total
$1,104
$1,232
Net Plant per Customer*
Allowable Investment per Customer
Distribution
$445
$498
Terminal
Facilities
$415
$499
Total
$860
$997
Net Plant per kW*
Allowable Investment per kW
Distribution
$125
$136
Terminal
Facilities
$64
$74
Total
$189
$210
Net Plant per kW*
Allowable Investment per kW
Distribution
$105
$114
Terminal
Facilities
$58
$64
Total
$163
$178
Net Plant per kW*
Allowable Investment per kW
Distribution
$100
$109
Terminal
Facilities
$11
$12
Total
$111
$122
* Net plant figures are from the cost of service study accepted by the Commission in IPC-E-08-10.
Attachment 2
Staff Comments
Case No. IPC-E-08-22
04/17/09
Assumptions Used in Calculating Allowable Investments
Cost of Capital
Capital Capital Component Weighted
Component Structure Cost Cost
Long Term Debt 50.730%5.927%3.007%
Preferred Equity 0.000%0.000%0.000%
Common Equity 49.270%10.500%5.173%
Total 100.000%8.180%
Grossed-up Rate of Return
Tax Gross-up Factor 1.642
Weighted ROE * Tax Gross-up 5.173 * 1.642 8.495%
Long Term Debt 3.007%
Preferred Equity 0.000%
Grossed-up Rate of Return 11.501%
Depreciation Distribution Terminal Composite
Rates Plant Facilities Rate
2.49%2.45%2.47%
Source for Cost of Capital is Order No. 30722, Case No. IPC+08-10
Attachment 3
Staff Comments
Case No. IPC-E-08.22
04/17/09
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Attachment 4
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 1 of2
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Return on Common Equity (Grossed-up)
Debt Service Costs
Subtotal
Depreciation Expense
Total Revenue Requirement
Return on Allowable Investment
Allowable Investment (Grossed-up ROR)
Allowable Investment (11.501%)
$1104.12 * (.05173 * 1.642)
$1104.12 * 0.03007
+ Annual Depreciation
+ Allowable Investment x Composite
Depreciation Rate
+ Allowable Investment (2.47%)
Allowable Investment (0.13769)
Allowable Investment
Allowable Investment
= $94.36
= $33.20
= $127.56
= $45.26
= $172.25
= Total Revenue Requirement
= Total Revenue Requirement
= $172.25
= $172.25
= $172.25 / 0.13971
= $1232.44
Attachment 5
Staff Comments
Case No. IPC-E-08-22
04/17/09
Allowable Investment by Customer Class
# Customers 391,525
Rate of Return 11.501%
Distribution Terminal
2008 Cost of Service Stud Plant Facilities Total
Net Plant 265,143,772 167,146,200 432,289,972
Return on Net Plant 30,495,267 19,224,166 49,719,433
Depreciation Expense 10,598,812 7,121,780 17,720,592
Total 41,094,079 26,345,946 67,440,024
Distribution Terminal
Per Customer Expenses Plant Facilities Total
Net Plant 677.21 426.91 1104.12
Return on Net Plant 7789 49.10 126.99
Depreciation Expense 27.07 18.19 45.26
Total 104.96 67.29 17225
Allowable Investment $750 $482 $1,232
# Customers 31,171
Rate of Return 11501%
Distribution Terminal
2008 Cost of Service Stud Plant Facilities Total
Net Plant 13,876,327 12,936,185 26,812,512
Return on Net Plant 1,595,973 1,487,843 3,083,816
Depreciation Expense 576,577 681,443 1,258,020
Total 2,172,550 2,169,286 4,341,836
Distribution Terminal
Per Customer Expenses Plant Facilities Total
Net Plant 445.17 415.01 860.17
Return on Net Plant 51.0 47.73 98.93
Depreciation Expense 18.50 21.86 40.36
Total 69.70 69.59 139.29
Allowable Investment $498 $499 $997
Attachment 6
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 1 of 2
Allowable Investment by Customer Class
# Connected kW 820,387
Rate of Return 11.501%
Distribution Terminal
2008 Cost of Service Stud Plant Facilities Total
Net Plant 102,407,286 52,764,022 155,ln,308
Return on Net Plant 11,778,280 6,068,605 17,846,885
Depreciation Expense 3,838,295 2,388,485 6,226,780
Total 15,616,575 8,457,091 24,073,665
Distribution Terminal
Per kW Expenses Plant Facilities Total
Net Plant 124.83 64.32 189.14
Return on Net Plant 14.36 7.40 21.75
Depreciation Expense 4.68 2.91 7.59
Total 19.04 10.31 29.34
Allowable Investment $136 $74 $210
# Connected kW n1,497
Rate of Return 11.501%
Distribution Terminal
2008 Cost of Service Stud Plant Facilities Total
Net Plant 74,543,310 41,177,777 115,721,087
Return on Net Plant 8,573,530 4,736,024 13,309,554
Depreciation Expense 2,781,702 1,619,622 4,401,324
Total 11,355,232 6,355,646 17,nO,879
Distribution Terminal
Per kW Expenses Plant Facilities Total
Net Plant 104.77 57.87 162.64
Return on Net Plant 12.05 6.66 18.71
Depreciation Expense 3.91 2.28 6.19
Total 15.96 8.93 24.89
Allowable Investment $114 $64 $178
Attachment 6
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 2 of 2
StaWs Estimates of the Cost of Terminal Facilties
Overhead
Underground $1,377 $2,586
Pad-Mounted $1,127 $213 Underground $958 $2,395
Overhead
$1,377 $2,766Underground
Pad-Mounted $1,127 $213 Underground $958 $2,575
Three Phase
Overhead $40.2/kW
$1,859
$832 $735
$5033 + $40.2/kWUnderground$1,607
Pad-Mounted $13.4/kW
$7,149 $832 Underground $1,193 $735 $9909 + $13.4/kW
Attachment 7
Staff Comments
Case No. IPC-E-08-22
04/17/09
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Comparison of Costs
Residential Example
Example is for a single phase, residential lot with a 1 DO' underground
extension from an underground system. No electric space or water heating
Design Number
Work Order Cost
Unusual Conditions
Subtotal
Overhead Transformer
37196 vs2
$7,284
$1,000
$8,284
($922)
Less Allowance OH Terminal Facilities + $1000 ($1,922)
Net Payment $6,362
Amount Subject to Refund $6,362
Design Number
Work Order Cost
Unusual Conditions
Subtotal
37196 vs 4
$7,284
$1,000
$8,284
Less Allowance OH Terminal Facilities ($1,780)
Net Payment $6,504 Cost
Difference
$142Amount Subject to Refund $6,504
Design Number
Work Order Cost
Unusual Conditions
Subtotal
37196 vs 4
$7,284
$1,000
$8,284
Less Allowance OH Terminal Facilities ($1,780)
Net Payment $6,504
$6,504
Cost
Difference
$142Amount Subject to Refund
Attachment 9
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 1 of 4
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Comparison of Costs
Irrigation Example
Example is for an irrigation customer with 3-phase overhead service and a connected
load of 150 hp pump.
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
OH 3-phase Terminal Facilities
76428 vs1
$17,385
($7,709)
$500
$10,176
Line Extension Costs - Engineering Fees $9,676
76428 vs 2
$17,385
Standard 3-phase Terminal Facilities ($3,803)
$500
$14,082
Line Extension Costs - Engineering Fees $13,582
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
76428 vs 2
$17,385
Actual 3-phase Terminal Facilities ($7,709)
$500
$10,176
Line Extension Costs - Engineering Fees $9,676
Attachment 9
Staff Comments
Case No. IPC-E-08-22
04/17/09 Page 3 of 4
Cost
Difference
$3,906
Cost
Difference
$0
Comparison of Costs
Commercial Example
Example is for a large commercial customer with 3-phase overhead service and a
connected load of 125 kW
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
80% of OH Terminal Facilities
53545 vs2
$14,646
($5,656)
$300
$9,290
$8,990Line Extension Costs - Engineering Fees
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
53545 vs 3
$14,646
Standard 3-phase Terminal Facilities ($3,803)
$300
$11,143
Line Extension Costs - Engineering Fees $10,843
Design Number
Work Order Cost
Less Allowance
Engineering Fees
Net Payment
Amount Subject to Refund
53545 vs 3
$14,646
ActualOH 3-phase Terminal Facilities ($7,070)
$300
Line Extension Costs - Engineering Fees
$7,876
$7,576
Attachment 9
Staff Comments
Case No. IPC-E-08-22
04/1 7/09 Page 4 of 4
Cost
Difference
$1,853
Cost
Difference
($1,414)
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17TH DAY OF APRIL 2009,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-08-22, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
LISA D NORDSTROM
BARTON L KLINE
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: lnordstromaYidahopower.com
bklineaYidahopower.com
SCOTT SPARKS
GREGORY SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: ssparksaYidahopower.com
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GIVENS PURSLEY LLP
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DAVIS F VANDERVELDE
WHITE PETERSON GIGRA Y ROSSMAN
NYE & NICHOLS P.A.
SUITE 200
5700 E FRANKLIN RD
NAMPA ID 83687
E-MAIL: mjohnsonaYwhitepeterson.com
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BOEHM KURTZ & LOWRY
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CINCINATI OH 45202
E-MAIL: mkurtzaYBKLlawfrm.com
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ENERGY STRATEGIES LLC
PARKSIDE TOWERS
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E-MAIL: khigginsaYenergystrat.com
.\((h
SECRETARY
CERTIFICATE OF SERVICE