20241210Exhibit 209.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION CASE NO. IPC-E-24-07
OF IDAHO POWER COMPANY TO
INCREASE RATES FOR ELECTRIC EXHIBIT 209
SERVICE TO RECOVER COSTS
ASSOCIATED WITH
INCREMENTAL CAPITAL
INVESTMENTS AND CERTAIN
ONGOING OPERATIONS AND
MAINTENANCE EXPENSES
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
EXHIBIT 209 EXCERPTS OF IPC-E-03-13 FINAL ORDER NO. 29505 AND
EXCERPTS OF PARTIES' FINAL REPORT IN IPC-E-04-23

Office of the Secretary
Service Date
May 25,2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY ) CASE NO. IPC-E-03-13
TO INCREASE ITS INTERIM AND BASE )
RATES AND CHARGES FOR ELECTRIC ) ORDER NO. 29505
SERVICE. )
ISSUED MAY 25,2004
BOISE,IDAHO

TABLE OF CONTENTS
SUMAL&RY................................................................................................................................... I
APPEARANCES...........................................................................................................................1
PROCEDURAL HISTORY.........................................................................................................2
TESTYEAR.................... .........................................................................................................3
ADJUSTMENTSTO RATE BASE............................................................................................4
1. Update to Actuals................................................................................................................4
2. Annualizing Plant Adjustments. ......................................................................................... 5
3. IERCO Investment-Unused Equipment Adjustment....................................................... 8
4. Biological Opinion Adjustment.......................................................................................... 9
5. Brownlee Woodhead Park Adjustment............................................................................. 10
6. Known and Measurable Physical Plant Irnprovements. ................................................... 11
7. Document Management System....................................................................................... 13
8. Prepaid Pension Expense.................................................................................................. 14
9. Capitalized Incentive Pay Adjustment.............................................................................. 15
10. Depreciation Expense and Accumulated Depreciation Adjustment................................. 16
11. Cloud Seeding................................................................................................................... 16
12. Danskin Power Plant......................................................................................................... 17
ADJUSTMENTS TO TEST YEAR REVENUE AND EXPENSES......................................19
1. Total Operating Pension Expense Adjustments................................................................ 19
2. Memberships and Contributions Adjustment. ..................................................................21
3. Interest on American Falls Bonds and Pollution Control Bonds......................................22
4. Operating Payroll Adjustments.........................................................................................23
5. Incentive Pay Operating Expense Adjustment. ................................................................25
6. Amortization of Unusual Cases........................................................................................26
7. Adjustments to Legal Expenses........................................................................................27
8. Adjustments to Property and Liability Insurance Expenses.............................................28
9. Adjustments to Management Expenses............................................................................29
10. Intervenor Funding Amortization.....................................................................................29
11. Additional Income Tax Assessment. ................................................................................30
12. Low Income Weatherization Assistance...........................................................................31
13. Income Tax Expense.........................................................................................................33
14. Summary of Adjustments to Rate Base and Test Year Revenues and Expenses. ............35
CAPITAL STRUCTURE AND RATE OF RETURN.............................................................36
1. Capital Structure...............................................................................................................36
2. Cost of Debt......................................................................................................................36
3. Cost of Preferred Stock.....................................................................................................37
4. Cost of Common Equity Capital.......................................................................................37
CALCULATION OF REVENUE DEFICIENCY...................................................................43
JURISDICTIONAL SEPARATIONS......................................................................................44
COST OF SERVICE METHODOLOGY................................................................................44
CLASS REVENUE ALLOCATIONS.......................................................................................47
RATE DESIGN AND TARIFF ISSUES...................................................................................51
1. The Service Charge...........................................................................................................51
2. Residential Customers(Schedule 1).................................................................................54
ORDER NO. 29505 i
€i

3. Small General Service Customers (Schedule 7)............
4. Large General Service Customers(Schedule 9)...............................................................57
5. Large Power Service Customers(Schedule 19)................................................................60
6. Irrigation Customers (Schedule 24 and Schedule 25).......................................................63
7. Other Rate Design Issues (Schedules 15,40,41, 42 and Schedules 26,29, 30)..............65
ADJUSTMENTSTO THE PCA...............................................................................................66
INTERVENOR FUNDING........................................................................................................66
NEW CASES AND OTHER ISSUES.......................................................................................68
ULTIMATE FINDINGS OF FACT..........................................................................................69
CONCLUSIONSOF LAW........................................................................................................70
ORDER....................................................................................................................................70
ORDER NO. 29505 ii

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY ) CASE NO. IPC-E-03-13
TO INCREASE ITS INTERIM AND BASE )
RATES AND CHARGES FOR ELECTRIC ) ORDER NO. 29505
SERVICE. )
SUMMARY
This is a final Order establishing the revenue requirement and rates for Idaho Power
Company's (Idaho Power; Company) electric services in the State of Idaho. Idaho Power filed
an Application on October 16, 2003 for authority to increase revenues by $85,561,910, an
increase of 17.68%, effective November 15, 2003. The Company also requested that, if the
Commission suspended the proposed effective date pursuant to Idaho Code § 61-622, interim
rates be set effective November 15, 2003. In Order No. 29369 issued October 28, 2003, the
Commission did suspend the proposed effective date of Idaho Power's new rates and charges,
and subsequently considered the appropriateness of interim rates. In Order No. 29403 issued
December 22, 2003, the Commission denied the Company's request for interim rates pending
resolution of this case. By this Order, we authorize Idaho Power to increase its Idaho revenues
by $25,327,533, or approximately 5.2%. As a result, electric base rates for specific classes will
be increased on average by the following percentages: Residential 5.98%; Small General
Service 5.97%;Large General Service 1.98%; Industrial 2.41%; and Irrigation 13.95%.
APPEARANCES
Following the filing of Idaho Power's Application, the Commission issued a Notice
of Application and provided an opportunity for interested parties to file petitions to intervene.
The Commission approved all petitions to intervene, resulting in the parties and their attorneys
identified below:
Idaho Power Company: Barton L. Kline
Monica B. Moen
Commission Staff: Lisa Nordstrom
Weldon B. Stutzman
Deputy Attorneys General
ORDER NO. 29505 1

Industrial Customers of Idaho Power: Peter J. Richardson
Richardson& O'Leary
Idaho Irrigation Pumpers Association,Inc.: Randall C. Budge
Eric L. Olsen
Racine,Olson,Nye,Budge
Bailey,Chartered
The United States Department of Energy: Lawrence A. Gollomp
Assistant General Counsel
United Water Idaho Inc.: Dean J. Miller
McDevitt&Miller LLP
NW Energy Coalition: William M.Eddie
Advocates for the West
Micron Technology,Inc.: Conley E. Ward
Givens Pursley LLP
Community Action Partnership Brad M. Purdy
Association of Idaho: Attorney at Law
AARP: Brad M. Purdy
Attorney at Law
Kroger Company: Michael L. Kurtz
Kurt J.Boehm
Boehm,Kurtz&Lowry
PROCEDURAL HISTORY
Idaho Power included in its Application a request for a uniform percentage increase
of 4.16% on all existing rates contained in the Company's tariffs pending a hearing on its
Application and a final Order. The Commission convened a hearing on November 13, 2003, to
consider Idaho Power's request for interim rate relief. The proposed interim rates were based on
the Company's assertion that it should be permitted to immediately add to rate base its
investment in the Danskin Power Plant, investments it has made in the relicensing of hydro
projects, adjustments to the Company's annual depreciation accounts, and an annual revenue
requirement amount attributable to wholesale power supply contracts that have expired. The
Commission determined that Idaho Power had not demonstrated the existence of a financial
emergency to justify interim rate relief, and denied the Company's request for temporary rates in
ORDER NO. 29505 2

Order No. 29403 issued December 22, 2003. The Commission convened a technical hearing on
Idaho Power's Application commencing March 29,2004 and concluding on April 5,2004.
Prior to the filing of testimony,the Commission Staff in January 2004 conducted four
workshops for interested customers to discuss the Company's Application and to answer
questions. Formal hearings were held in Pocatello, Jerome, McCall,Payette and Boise in March
2004 to hear from members of the public on the issues presented in this case. Approximately 50
people attended the workshops and about 300 people attended the five hearings. Of those who
attended, 88 people testified at the hearings. In Order No. 29436,the Commission also solicited
written public comments regarding the Application to be filed on or before April 30, 2004. The
Commission received more than 500 timely written comments from the public.
The Commission greatly appreciates the efforts ratepayers made to express their
opinions regarding their electric rates and the proper regulatory oversight necessary to keep
unreasonable expenses out of rates. We heard from many residential customers, the majority of
whom opposed the Company's proposed increase in the service charge. Irrigation customers
also contributed in large numbers to the record and expressed concern about the impact Idaho
Power's proposed 25% increase would have on individual farms and the agricultural community.
The Commission also heard from a large number of low-income and senior citizens, who asked
us to consider current economic conditions before granting any rate increase. Numerous
customers expressed concern about the lapse of a decade between rate cases, resulting in a large
rate increase request and possible rate shock,rather than smaller incremental changes that would
occur with more frequent rate cases.
With this background in mind,we now discuss the test year and revenue requirement
issues presented in this case.
TEST YEAR
Idaho Power proposed a 2003 test year and initially provided actual account
information for the first six months of 2003, and proposed to use projected account information
for the second half of 2003. Tr. at 515, 1247. Because actual data would be available at the time
of hearing; Staff and others argued that actual year-end figures should be used because they are
more accurate than projected figures and better align costs and revenues. Tr. at 542, 1404-05,
1451-54, 2426-28. Idaho Power did provide actual numbers for the test year accounts showing
year-end balances.
ORDER NO. 29505 3

extremely difficult to allocate a fixed monetary amount over reasonable requests that far exceed
that allowed by statute. However, we believe this allocation best satisfies the considerations set
forth in Idaho Code § 61-617A
NEW CASES AND OTHER ISSUES
Several issues arose in the testimony that the Commission has determined should be
addressed in separate proceedings, although each may be handled in a workshop setting that does
not require a formal hearing. As previously mentioned, the Commission at the hearing granted
Staffs motion for a separate proceeding to address Expense Adjustment Rate for Growth
component of the PCA formula. Idaho Power and Staff are directed to determine a schedule for
one or more workshops and initiate a docket to address this piece of the PCA.
A proposal for a second workshop proceeding was sponsored by NW Energy
Coalition, which argued that financial disincentives hinder Idaho Power's investments in cost-
effective energy efficiency and clean distributed generation. NW Energy Post Hearing Brief at
1. NW Energy filed with its brief an agreement signed by representatives of NW Energy, Idaho
Power, Staff and Industrial Customers committing them, should the Commission determine that
removing the disincentives is in the public interest, to "work together to investigate specific
mechanisms for achieving this objective, to identify areas of consensus, and to clarify
alternatives where consensus is not possible." NW Energy Joint Proposal at 1. The Commission
has determined that a proceeding to assess financial disincentives inherent in Company-
sponsored conservation programs is appropriate and should proceed by informal workshops.
The Commission specifically directs the parties to address possible revenue adjustment when
annual energy consumption is both above and below normal. The parties should also consider
how much adjustment is necessary to remove DSM investment disincentives and whether(and to
what extent) performance-based incentives such as revenue sharing could or should be
incorporated into the resolution of this issue. The Commission is interested in proposals that
could provide Idaho Power the opportunity to share and retain benefits gained from efficiencies,
especially where efficiencies are derived from innovation and the use of new technologies. For
example, a proposal might include a way to average expense reductions that result in efficiencies
on the system that benefit the Company and its shareholders while maintaining or improving
service quality standards. The parties may also consider including service quality standards or
benchmarks as a component of an incentive mechanism. In short, the Commission believes
ORDER NO. 29505 68

opportunities exist for improvements in operating efficiency that would benefit the Company.
shareholders and its customers, and we encourage the parties to creatively consider the options
for a performance based mechanism to present to the Commission. The parties to the agreement
are directed to propose a workshop schedule and initiate a proceeding.
As previously stated, the Commission has also determined to initiate a proceeding to
consider and evaluate cost of service issues raised in this case. Witnesses for the Industrial
Customers,Micron,DOE and the Irrigators all identified problems with the cost of service study
components. These issues should be further investigated before the next Idaho Power general
rate case. The Commission also received testimony from irrigation customers and other
ratepayers who were concerned with how investments necessitated by customer growth should
be paid. Tr. at 65-7, 2036. These witnesses suggested that a revised line extension policy could
appropriately align cost recovery with the customers who create the need for system
improvements. Consequently, the Commission has specifically directed the parties to address
load growth issues in the cost of service proceeding to determine if line extension modifications
are necessary. Staff is directed to determine a workshop schedule and initiate a proceeding for
that purpose.
Finally, the Commission's Consumer Division Staff presented in testimony specific
recommendations for Idaho Power to improve customer service issues. To its credit, the
Company responded in a positive way to Staffs recommendations, agreeing to implement the
recommendations or, in one case, by making suggestions that improved the recommendations.
These issues do not require a separate proceeding, but Staff should review the Company's
implementation of the changes it agreed to and report to the Commission should any significant
issues arise in the implementation process.
ULTIMATE FINDINGS OF FACT
Idaho Power Company is an electrical corporation subject to the Commission's
regulation under the Idaho Public Utilities Law. The rates of all its tariff customers in the State
of Idaho and of its contract customers are subject to this Commission's regulation under the
Public Utilities Law.
The Company's present rates do not provide it with an opportunity to earn a fair and
reasonable return on its investment. Allowing the Company to increase its rates and charges by
ORDER NO. 29505 69

$25,329,438 will provide it with the opportunity to earn a fair and reasonable return. The
average 2003 test year is the appropriate test year period for use in this proceeding.
The adjusted test year net operating income for Idaho of $103,918,528 is just and
reasonable for setting rates. The test year adjusted rate base for Idaho of$1,519,924,799 is just
and reasonable for setting rates. Idaho Power's actual capital structure at December 31, 2003 is
the appropriate one for this case and an overall rate of return of 7.852%, to be applied to all rate
base,is a fair and reasonable rate of return for the Company.
The revenue allocation shown in Appendix 3 is a just, reasonable and non-
discriminatory allocation of the Company's revenue requirement among the various customer
classes. It is also fair, just and reasonable to design the customer class rates according to the
directives contained in the text of this Order.
The awards of intervenor funding in the amounts of$10,000 to NW Energy Coalition,
$15,000 to Idaho Irrigation Pumpers Association, Inc., and $15,000 to Community Action
Partnership Association of Idaho are reasonable.
CONCLUSIONS OF LAW
This Commission has jurisdiction and authority to authorize and require Idaho Power
Company to re-allocate its revenues among the customer classes, to change its rate components
within the customer classes, to address the other issues and to award intervenor funding in the
manner set forth in the text of this Order.
ORDER
IT IS HEREBY ORDERED that Idaho Power Company file tariffs in conformance
with this Order to be effective on June 1, 2004,for service rendered on and after that date.
IT IS FURTHER ORDERED that Idaho Power Company comply with all other
directives of the text of this Order.
IT IS FURTHER ORDERED that the Community Action Partnership Association of
Idaho comply with the conditions and reporting requirements associated with the Low Income
Weatherization Assistance funding authorized by this Order.
IT IS FURTHER ORDERED that the parties determine a workshop schedule and
initiate separate proceedings to resolve issues regarding the Expense Adjustment Rate for
Growth, financial disincentives in Company-sponsored conservation programs, and cost of
ORDER NO. 29505 70

service study components (including whether load growth is properly recovering its cost) as
discussed in this Order.
IT IS FURTHER ORDERED that NW Energy Coalition is awarded intervenor
funding in the amount of $10,000, the Idaho Irrigation Pumpers Association, Inc. is awarded
intervenor funding in the amount of$15,000, and Community Action Partnership Association of
Idaho is awarded intervenor funding in the amount of$15,000. Idaho Power is directed to pay
these amounts within 28 days of the date of this Order.
THIS IS A FINAL ORDER. Any person interested in this Order(or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this Case No. IPC-E-03-13
may petition for reconsideration within twenty-one (21) days of the service date of this Order
with regard to any matter decided in this Order or in interlocutory Orders previously issued in
this Case No. IPC-E-03-13. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. See Idaho Code § 61-
626.
ORDER NO. 29505 71

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this ,26fh
day of May 2004.
PAUL KJELLANUER,PRESIDENT
j
MARSHA H. SMITH, COMMISSIONER
ENNIS S.H SE ,C MMISSIONER
ATTEST:
Je D. Jewell
Commission Secretary
b1s/0:IPCE0313 ws final
ORDER NO. 29505 72

E tECEIWED
FILED
2005 JUN 29 Ate 10: 23
IDAHO
STATE OF IDAHO
UTILITIES COt MIISSION
OFFICE OF THE ATTORNEY GENERAL
LAWRENCE G.WASDEN
June 29,2005
VIA HAND DELIVERY
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
PO Box 83720
Boise,ID 83720-0074
RE: The Parties' Final Report in Case No. IPC-E-04-23
Dear Ms. Jewell:
On behalf of the parties in the above referenced case, the Staff is filing an original and seven
copies of the Final Report to the Commission. In Order No. 29505 the Commission initiated a
proceeding following Idaho Power Company's 2004 rate case to allow interested parties to
examine the Company's cost-of-service model. The attached Final Report outlines the issues
examined by the parties and lists those cost-of-service issues where the parties reached
consensus.
Please contact me if you have any questions.
Since ely,
Donald L. Howell, II
Deputy Attorney General
Enclosures
cc: Parties of Record(Electronic)
bls/L Jewell IPCE0423 A
Contracts&Administrative Law Division,Idaho Public Utilities Commission
P.O.Box 83720,Boise,Idaho 83720-0074,Telephone:[phone],FAX:[phone],E-mail:[e-mail]
Located at 472 West Washington St.,Boise,Idaho 83702

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION )
CONCERNING ISSUES RELATED TO IDAHO ) CASE NO. IPC-E-04-23
POWER COMPANY'S COST OF SERVICE )
STUDY. ) THE PARTIES'
FINAL REPORT
On May 25, 2004, the Commission issued Order No. 29505 addressing substantive
cost of service issues raised in Idaho Power Company's (Idaho Power; Company) 2004 general
rate case, No. IPC-E-03-13. While the Commission found that Idaho Power's cost of service
study was appropriate for allocating costs in that case, the Commission noted that several parties
raised legitimate questions regarding the cost of service components that deserve additional
investigation before Idaho Power's next general rate case. Order No. 29505 at 47. Therefore,
the Commission opened docket IPC-E-04-23 for the purpose of evaluating cost of service issues
raised in the general rate proceeding. In Order No. 29505 the Commission wrote:
Specifically, we direct Staff and interested parties to evaluate appropriate
issues through a series of workshops (as needed), including: (1) how best to
determine and weigh monthly generation and transmission allocators, (2)
how to most accurately capture coincident peak demand responsibility,
and (3) whether new growth is properly covering its cost of service. We
expect consensus investigation results and recommendations to be
documented in final report and submitted to the Commission no later than
[June 30, 2005].1 With respect to the issue of new growth and how its cost
flows through the cost of service study, we also expect the parties to submit
recommendations regarding any needed changes in Idaho Power's line
extension rules that are identified by the investigation. Once the cost of
service investigative report is received, the Commission can then determine
how best to proceed addressing any recommended line extension tariff
changes.
THE INVESTIGATION
The parties have held three workshops on November 3, 2004, December 14, 2004
and on February 25,2005. The minutes from those three workshops are attached to this report.
' In Order No. 29744 the Commission extended the deadline for the report to April 29,2005, and in Staff Motion
dated April 29,2005,Staff requested an additional extension of the deadline to June 30,2005,
THE PARTIES' FINAL REPORT 1
ti

1. The first workshop began with a discussion of the scope of issues to be covered in
the workshops. It was agreed that the workshop should be confined to the issues defined in the
Commission Order and to making the cost of service model and model inputs (load research
data) more transparent. Idaho Power then provided an overview of their cost of service model
along with a description of the Company's load research methodology to determine coincident
peak responsibility. A summary of the legal constraints related to allocating incremental
investment costs to new load growth was also given.
2. At the second workshop IPC distributed a spreadsheet showing "2003
Contribution in Aid of Construction (CIAC) Analysis". The analysis pointed out that the
Schedule 19 CIAC percentage of investment was larger than the other schedules (64%). This is
partly because there is a smaller allowance for that rate schedule. Irrigators (Schedule 24) and
Small Commercial(Schedule 7)had the lowest CIAC amount at 28%.
As an example of a marginal cost of service approach, the Company distributed and
explained a two-page spreadsheet showing the marginal cost methodology used in Oregon to
determine class specific revenue requirement and rate design. Additionally, the Company
explained that maintenance of numerous thermal plants in the region occurs in March in order to
take advantage of typically lower loads. The larger number of plants down for maintenance
tends to drive the marginal cost of generation up in the month of March. Even though loads are
down in that month,supply is down sufficiently to drive the price up.
The Irrigators distributed a 39-page document titled, "Irrigator Comments". Their
first point was that energy and revenue are normalized and demand should also be"normalized".
Using the average of five or ten years of monthly peak demand numbers may reduce the effect of
any anomalies that exist in a test year due to extreme conditions. The Irrigators presented their
proposal for normalization of the monthly demand in the final workshop. Although the parties
did not come to consensus on a demand normalization methodology during the workshop,further
discussion between the Irrigators and Idaho Power following the final workshop has resulted in a
proposal to which the parties agree. The proposal agreed upon by the parties would simply use
the median demand ratios over the most recent five-year period to determine normalized
demands for allocation purposes.
Irrigators then discussed growth issues, which they believe are principally driven by
a 200% increase in distribution plant over the last 23 years. They suggested that distribution
THE PARTIES' FINAL REPORT 2

plant, which is related to growth by other customers, not be allocated to the Irrigation class. At
the final workshop the Irrigators made a growth allocation proposal for distribution plant, which
distinguished between new/growth and old/non-growth. New/growth costs would be defined as
the increase in distribution plant over the last 20 years and would be allocated on the basis of the
percentage of new energy consumption by class over the last 20 years. Old/non-growth costs
would be allocated on energy usage 20 years ago. In the discussion that followed it was
suggested that the number of customers or the non-coincident peak might be better than energy
for allocation of distribution plant. There was also concern that this methodology might not
comply with Supreme Court precedent. This proposal was not accepted by all the parties.
3. In the final workshop, the Company provided a report on the experience of other
utilities in dealing with growth issues. It reported that Con-Edison had a similar issue but no
solution and other utilities had no experience in dealing with this specific growth issue. Staff
reported that several utilities referenced line extension contributions,hookup fees and rate design
as tools to deal with increasing costs associated with growth.
Allocation of underground distribution plant was the next point of discussion. The
Irrigator's presentation showed that underground plant had increased 600% in the last 23 years.
It proposed that underground plant not be allocated to Schedule 19 or to the Irrigation Schedule
24, because they use no significant amount of it. They also suggested charging customers that
use underground facilities more for that service. In the discussion it was asserted that most of the
additional cost of underground plant is contributed through the over-head/underground
differential. It was also suggested by others that if underground distribution plant was not
allocated to Irrigators perhaps they should have a greater portion of overhead distribution plant
allocated to them because typically irrigators are more spread-out than other customer classes
and typically have more distribution per customer. There was no consensus reached on this
issue.
The Irrigator's presentation discussed weighting factors for generation and
transmission related demand and energy costs. At present, the Company develops these
weighting factors based upon its latest Integrated Resource Plan. The Irrigators proposed that a
cost-based method be developed for weighting these costs. The method could be based on actual
wholesale transactions. There was little discussion on this issue and no agreement.
THE PARTIES' FINAL REPORT 3

At the second workshop, the Irrigators suggested that the Company should develop a
procedure by which the basic load research data is incorporated into an Excel or Access format.
They also recommended that the conversion of billing cycle data should employ a formula that
separates base and temperature sensitive load. The temperature sensitive load would then be
adjusted by heating degree days (HDD) or cooling degree days (CDD) and assigned to the
appropriate month. At the final workshop, Idaho Power made a proposal to capture the effects of
weather on energy consumption by using actual load research data to develop daily usage
patterns rather than using simple linear interpolation to spread billed energy evenly across each
billing cycle. This proposal was acceptable to all the parties. The Company also stated that they
could provide load research data used in a rate case, but needed to protect the identity of the
individual customers.
CONCLUSIONS
The responses from the workshop parties to each of the questions asked by the
Commission are as follows:
(1) How best to determine and weight monthly generation and transmission allocators.
The parties agreed that no consensus could be reached on this issue - primarily
because each party represents a different customer or customer group, and any change in the
allocators would produce winners and losers. The parties recommend that this issue should
remain an issue to be resolved in rate proceedings before the Commission.
(2) How to most accurately capture coincident peak demand responsibility.
This issue is similar to the previous one. The parties agreed that no consensus could
be reached on this issue — primarily because each party represents a different customer or
customer group, and any change in the allocation of peak demand responsibility would produce
winners and losers. The parties recommend that this issue should remain an issue to be resolved
in rate proceedings before the Commission.
(3) Whether new growth is properly covering its cost of service.
Most of the workshop time was devoted to discussion of this issue. The parties
agreed that there was something inherently troubling with the way costs, associated with growth,
were allocated. This is evidenced by the relatively large increase in revenue requirement
allocated to customers whose load and energy requirements were unchanged or grew only
slightly. While there was agreement that the cost of growth did not necessarily get allocated to
THE PARTIES' FINAL REPORT 4

the customers and customer classes that grew, we were unable to devise a technical remedy to
the allocation procedure that would also satisfy the courts. The parties were unable to devise and
agree to a cost-of-service allocation methodology that would properly allocate the cost of
growth, without making a distinction between new and old customers. Even a search of what
others, around the country, were doing produced little in the way of an acceptable solution.
Therefore, it was concluded that the only remedy is a policy solution. The parties were not
willing to agree to the particulars of such a policy and recommend that the Commission
formulate such a policy in the next rate proceeding.
(4) Recommendations regarding any needed changes in Idaho Power's line extension
rules.
The majority of the parties agreed (all except Pike Teinert) that the line extension
rules should require new customers to pay the full incremental cost of new distribution plant, to
the extent the courts would allow. The existing line extension rules are designed to do this;
therefore there was no further discussion on this issue.
(5) Other issues where the parties reached consensus.
In accordance with the issues raised by the Irrigators during the workshop
discussions, Idaho Power has offered to take several actions as part of its next general rate case
filing.
• Idaho Power will provide customer load research data in computer-
readable files so that it will be easier for other parties to review the
development of the coincident peak demand responsibility factors and to
propose alternative methods for determining coincident peak demand
responsibility if they wish.
• Idaho Power will implement a more sophisticated nonlinear method of
converting billing month energy data to calendar month energy data. The
new method will capture the effects of weather on energy consumption by
using actual load research data to develop daily usage patterns rather than
using simple linear interpolation to spread billed energy evenly across
each billing cycle. Accordingly,the new method will improve the process
of determining coincident peak demand responsibility.
• Based on the proposal put forth by the Irrigators and agreed to by the
parties, Idaho Power will prepare and include a surrogate for a.demand
normalization method, along with a traditional method, for the
determination of coincident peak demand responsibility in its next general
t
THE PARTIES' FINAL REPORT 5
i

rate case filing. As agreed following the final workshop, the
normalization surrogate would be the 5-year median demand ratios from
load research samples applied to normalized monthly class energy values.
THE PARTIES' FINAL REPORT 6