20060130Youngblood direct, exhibits.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
OF FINANCIAL DISINCENTIVES TO
INVESTMENT IN ENERGY EFFICIENCY BY IDAHO POWER COMPANY.
CASE NO. IPC-O4-
IDAHO POWER COMPANY
DIRECT TESTIMONY
MICHAEL J. YOUNGBLOOD
Please state your name and business address.
My name is Michael J. Youngblood and my
business address is 1221 W. Idaho Street. in Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company as a
Senior Pricing Analyst in the Pricing and Regulatory Services
Department.
Please describe your educational background.
In May of 1977 , I received a Bachelor of
Science Degree in Mathematics and Computer Science from the
University of Idaho.From 1994 through 1996, I was a graduate
student in the MBA program of Colorado State University.
Please describe your work experience with Idaho
Power Company.
I became employed by Idaho Power Company in
1977.During my career , I have worked in several departments
and subsidiaries of the Company, including Systems
Development, Demand Planning, Strategic Planning and IDACORP
Solutions.Most relevant to this testimony though, is my
experience within the Pricing and Regulatory Services
Department.From 1981 to 1988, I worked as a Rate Analyst in
the Rates and Planning Department where I was responsible for
the preparation of electric rate design studies and bill
frequency analyses.I was also responsible for the validation
and analysis of the load research data used for cost of
YOUNGBLOOD, DI
Idaho Power Company
service allocations.
From 1988 through 1991 , I worked in Demand
Planning and was responsible for the load research and load
forecasting functions of the Company including sample design,
implementation, data retrieval, analysis, and reporting.
was responsible for the preparation of the five-year and
twenty-year load forecasts used in revenue proj ections and
resource plans as well as the presentation of these forecasts
to the public and regulatory commissions.
In 2001 , I returned to the Pricing and
Regulatory Services Department and have worked on special
projects related to deregulation , the Company s Integrated
Resource Plan, and filings with this Commission and the Oregon
Public utility Commission.
What is the purpose of your testimony in this
case?
The purpose of my testimony is to describe a
Fixed Cost Adjustment ("FCA") mechanism that would true-up
fixed cost recovery for residential and small commercial
customers.The proposed FCA is an effort to reduce or remove
a currently existing disincentive to pursue conservation
measures for those two classes of customers.Mr. Ralph
Cavanagh first discussed the disincentive to pursue
conservation measures in Case No. IPC-03-13 (the Company
last general rate case) .
YOUNGBLOOD , DI
Idaho Power Company
What has been your involvement with the
development of an FCA mechanism?
I began working on the development of a fixed
cost true-up mechanism in 2004 during Case No. IPC-03-
shortly after the Company read Mr. Cavanagh's testimony in
that proceeding.I was designated as the proj ect Manager
responsible for the review of existing mechanisms and
identification of a true-up mechanism that Idaho Power could
support.As part of this review process, the Company hired a
consultant, Mr. Eric Hirst, to write a "white paper " which he
titled "Decoupling for Idaho Power Company I have included
this white paper as Exhibit No.
Did you work with Mr. Hirst in the preparation
of this white paper?
Yes.At Mr. Hirst's request, I gathered 2003
test year information regarding the fixed costs associated
with the Company s five largest rate classifications
(residential , small commercial , large commercial , irrigation
and industrial classes) .With this information Mr. Hirst and
I were able to identify the portion of those fixed costs that
are recovered as a component of each specific rate class
volumetric rate (energy charge) Because conservation
measures encourage the reduction of energy consumption, fixed
costs normally recovered through a volumetric rate are not
recovered when such conservation measures are pursued.Mr.
YOUNGBLOOD , DI
Idaho Power Company
Hirst also provided a description of various types of
recoupling mechanisms used for recovery of these lost fixed
costs and developed conclusions that I reviewed.
Have you had any additional involvement in the
review of fixed cost recovery true-up mechanisms since 2004?
Yes.The Idaho Public Utilities Commission, in
review of its Order No. 29505 in Case No. IPC-03-13 found it
reasonable to initiate an investigation of financial
disincentives to investment in energy efficiency by Idaho
Power.In Order No. 29558, the Commission established Docket
No. IPC- 04 -15 for such an investigation and stated that the
scope of the investigation should be focused on decoupling and
performance based ratemaking.The Company, along with the
Northwest Energy Coalition , the Commission Staff , the
Industrial Customers of Idaho Power , and other interested
parties, held several workshops to discuss the issues and
prepare a report for the Commission of the workshops'
findings.I was a participant at these workshops and prepared
much of the analyses that were used during the investigation.
Were the findings of Mr. Hirst's white paper
used as part of the workshop s investigation?
Yes.Mr. Hirst attended the very first
workshop and made a presentation of his study to the group.
This provided all of the participants with an understanding of
the fixed costs associated with the Company s energy charges,
YOUNGBLOOD, DI
Idaho Power Company
and provided a springboard for further discussions into the
concerns and various mechanisms that may be considered for
fixed cost recovery associated with additional investment in
DSM.
What was the result of the workshop effort?
The final report by the workshop participants
was filed with the Commission on February 14, 2005.The
report provided the Commission with an overview of the
workshops, the issues discussed, and the recommendations of
the workshop participants.One of the action items resulting
from this process was a direction for the Company to simulate
the potential impacts of a broader fixed cost true-up
mechanism that could be utilized until Idaho Power s next
general rate case.I was responsible for developing and
maintaining that simulation (Exhibit No.6), the results of
which are the genesis of the FCA mechanism the Company is
proposing in this case.
Please describe the fixed cost true-up
simulation that you developed as a workshop assignment.
The Natural Resources Defense Council and
Northwest Energy Coalition proposed a true-up mechanism to
restore lost fixed-cost revenues to Idaho Power that resulted
when conservation measures reduced future energy consumption.
Rather than recommending the actual implementation of such a
mechanism, the workshop participants agreed to a "simulation
YOUNGBLOOD , DI
Idaho Power Company
of the true-up proposal to help illuminate the potential
impacts a true -up mechanism might have had on Idaho Power and
its customers if a true-up mechanism had been in place.The
simulation was to review the years from 1994 to the next
general rate case, using the fixed-cost revenue requirements
approved in the Company s last two general rate cases as
starting points, and then comparing those with actual fixed
cost revenues recovered through energy sales.At the time of
the writing of this testimony, the year-end numbers for 2005
are not yet final therefore, the simulation currently reviews
the years from 1994 through 2004.For the period of 1994
through May 31 , 2004 , the simulation uses as a base the fixed
cost revenue requirements established in IPC-E- 94 - 5.From
June 1, 2004 forward, the analysis uses the fixed cost revenue
requirements established in IPC-03-13, the Company s last
general rate case.
The simulation was to assume an annual level of
efficiency savings of 0.5 percent of the previous year'
consumption (roughly equivalent to the level of savings
achievable under the Northwest Power & Conservation Council'
NWPCC") Fifth Power Plan) .
For the residential and commercial classes, the
allowed fixed cost recovery included in the simulation was
allowed to increase each year based upon the growth in actual
customer count.For the industrial and irrigation classes,
YOUNGBLOOD, D I
Idaho Power Company
the allowed fixed cost recoveries were allowed to increase
based upon the forecasted energy sales in the most recent IRP
for any given year (i. e., the 2000 IRP for years 2000 and
2001 , the 2002 IRP for years 2002 and 2003, etc.
For purposes of the simulation , Idaho Power was
to continue to absorb the risks or benefits of purely weather-
related effects on fixed-cost revenue recovery, as it always
has.Actual sales were to be weather-normalized before making
the annual true-up calculation.The maximum annual average
rate impact of the true-up mechanism for any customer class
was to be capped at 2 percent, with any additional amounts
carried over to the next year s true-up.
What were the results of the simulation that
are relevant to this FCA filing?
The results of the simulation that are relevant
to this filing are those for the residential and small
commercial classes.Each class would have received both
positive and negative adjustments during the 1994 through 2004
simulation period.The results demonstrate the two-way nature
of this adj ustment, similar to the Company s Power Cost
Adjustment ("PCA"In years where customer growth was
greater than energy growth, an under-collection of authorized
fixed costs occurred, which would have triggered a rate
adjustment to collect the lost fixed costs from the customers
in the following year.During years when energy growth was
YOUNGBLOOD, DI
Idaho Power Company
greater than customer growth (even with the 0.5 percent DSM
energy savings assumption), an over-collection of fixed costs
would have been returned to the customers through a rate
reduction the following year.
What was the largest annual FCA calculated for
the simulation?
The largest adjustment for both the residential
and small commercial classes in the simulation was 2 percent
because of the constraint capping any one-year rate change.
That cap came into play in 4 out of 10 years for the
residential class and 4 out of 10 years for small commercial.
However , one of those years for the small commercial class
represented a 2 percent cap on the reduction in rates.The
highest positive adjustments for both classes occurred in 2002
and 2003, very possibly reflecting the higher energy costs
observed by Idaho Power s customers and a consequent reduction
in energy sales.
Had a cap not been in place, what would have
been the range of percentage changes in FCA rates for the
simulation period?
Wi th no restriction on the amount of change on
adjusted rates from year to year, the percent change to
residential rates ranged from a reduction of 0.17 percent to
an increase of 3.94 percent, with an average increase for the
ten years of 1. 35 percent.For the small commercial class,
YOUNGBLOOD, DI
Idaho Power Company
the largest decrease in fixed cost adjustments occurred as a
result of 2001 customer growth at 0.44 percent with a
concurrent increase in normalized energy growth of 6.
percent (including the 0.5 percent DSM assumption) This
would have resulted in an over-collection of fixed costs and a
56 percent reduction in adjusted rates.
wi thout the 2 percent cap in place, the largest
increase the small commercial sector would have seen would
have occurred following a 7.36 percent reduction in 2002
normalized energy sales combined with a 3.34 percent growth in
The net resul t of the FCA would have been a 7.customers.
percent increase in rates.The average percentage change for
the ten-year period would have been a 1.27 percent increase in
rates.
In your opinion, were the assumptions for the
level of conservation applied to the historical loads in the
simulation reasonable?
Yes, I believe they were reasonable for the
following reasons.The assumptions for the level of
conservation on historical loads were used for the simulation
period in order to see the effects a fixed cost mechanism
would have had if an effective conservation plan had been in
place.The workshop consensus to use O. 5 percent each year
for the simulation was because it was considered to be roughly
equivalent to the level of savings determined to be achievable
YOUNGBLOOD, DI
Idaho Power Company
under the NWPCC's Fifth Power Plan.I believe that it is
reasonable to expect future conservation impacts on Idaho
Power loads to be consistent with regional expectations of
conservation impacts, and therefore it was reasonable to use
these estimates in the simulation.Ms. Darlene Nemnich , the
Company s Energy Efficiency Leader, has informed me that she
also believes the 0.5 percent annual Demand Side Management
DSM") estimate is reasonable.Ms. Nemnich believes the 0.
percent savings is achievable with the Company s energy
efficiency programs that are currently in place, again
validating the assumed level used in the simulation.Even
assuming the somewhat higher level of savings assumed by Mr.
Cavanagh (adding another 0.5 percent per year), the Company
views the proposed cap on rate adjustments as reasonable.
Is the Company s proposal for an FCA mechanism
in this case based upon the same assumptions as contained in
the workshop simulation?
Yes.Essentially, the FCA mechanism proposed
is the same as the true-up mechanism suggested by the workshop
participants and used in the simulation.There are just a few
small variations in the mechanism as proposed in this filing.
While the simulation modeled the largest five
rate classes, the Company is proposing an FCA mechanism for
the residential and small commercial classes , Schedules 1 and
7 respectively.Mr. Gale s testimony discusses the reasons
YOUNGBLOOD, DI
Idaho Power Company
the Company has chosen these two classes at this time.
In the simulation , any upward or downward
movement in rates as a result of a FCA was capped at 2
percent.For the proposed FCA mechanism, the Company is
proposing a 3 percent cap on the FCA rate adjustment, and only
on rate adjustment increases.While most of the rate
adjustments in the simulation were less than the cap,
averaging 1.35 percent for residential and 1.27 percent for
small commercial when no cap was imposed, there were four
years out of ten when the 2 percent cap was applied.The
effect of the cap is to defer the remainder of the FCA to the
following years.With a 3 percent cap, applied at the
Commission s discretion, the effects of a deferral carry-over
would be minimized.Wi th a 3 percent cap in place,
residential rate adjustments would have exceeded the cap in
only one of ten years.Small commercial rate adjustments
would have hit a 3 percent ceiling in two years.Even by
moving the cap to 3 percent, the impact on a customer
average monthly bill would be less than $2.00.
Are there any other variations from the
methodology used in the simulation?
Yes.In the simulation, fixed cost recovery
adjustments were determined based on an annual deviation.
order to better match cause and effect for accounting
purposes, the Company is proposing to book adjustments on a
YOUNGBLOOD, DI
Idaho Power Company
monthly basis.The ultimate balance in the account will be
determined annually, but will be booked to Company accounts on
a monthly basis.This is similar to PCA accounting practices.
Over the course of a year , an FCA balancing
account may show both positive and negative monthly amounts,
depending on the respective growth rates of customer counts
and energy usage.For example, while residential customer
counts may grow at a constant rate during the year, the
monthly consumption of energy over the course of the same year
will not be as constant.Residential customers may use more
energy during the winter and summer months and less during the
spring and fall.If one were to look at the balance in the
FCA deferral account for a month early in the year , it may
appear that the Company has over-collected its fixed costs
because energy usage had grown faster than customer growth.
Yet by year-end, if customer growth continues to grow at a
consistent pace, the FCA may result in an under-collection of
fixed costs.
Please describe the Fixed Cost Adj ustment
mechanism the Company is proposing in this filing.
For both the residential and small commercial
classes (Schedules 1 and 7), the FCA mechanism would be the
The formula used to determine the FCA amount would be:same.
FCA = (CUST X FCC) - (NORM X FCE)
Where:
YOUNGBLOOD, DI
Idaho Power Company
mechanism?
FCA = Fixed Cost Adjustment;
CUST = Actual number of customers, by class;
FCC = Fixed Cost per Customer, by class;
NORM = Weather-normalized energy, by class;
FCE = Fixed Cost per Energy, by class.
What values are required to implement the FCA
As outlined in the above formula, for each
class (residential and small commercial), the actual number of
customers (CUST), the fixed cost per customer (FCC), weather-
normalized energy (NORM), and the Fixed Cost per Energy
FCE") are required to determine the FCA amount.Two of
these variables " CUST and NORM) would be determined monthly
based upon actual data as it occurs.The other two variables
(FCC and FCE) would be determined as part of this case.
What is the Company s proposed method for
determining the FCC and FCE?
The Fixed Cost per Customer (FCC) and the Fixed
Cost per Energy (FCE) would be established using the data
filed during the Company s general rate case filing.In order
to determine the FCC and FCE rates, we would establish
principal base level values determined in class cost of
service and revenue requirement calculations , both of which
are established during the Company s general rate case.
How are these principal base level values for
YOUNGBLOOD, DI
Idaho Power Company
the FCA mechanism determined in the current application?
The principal base level values for the FCA
mechanism use 2005 test year numbers, which are found in the
data submitted for the IPC-05-28 general rate case currently
filed.They will most accurately represent the Company
current fixed costs.While the numbers may change for
subsequent general rate cases, the methodology would remain
the same.
The first base level determination necessary
for the FCA is a determination of the 2005 test year fixed
cost recovery embedded in the energy charges for residential
and small commercial customers.For the residential class,
$138 388,237 of fixed costs would be recovered from Schedule 1
energy charges.For the small commercial class , $8,712,552 of
fixed costs would be recovered from Schedule 7 energy charges
(Exhibit No.7) .
Do these fixed cost amounts for the residential
and small commercial classes include more than their actual
class cost of service?
Yes.There is a difference between the class
cost of service numbers and the amount of requested revenue
requirement.This difference is primarily a result of cross-
class subsidies that are currently present in the Company
rate structure.
Why is it important to include these fixed cost
YOUNGBLOOD, DI
Idaho Power Company
subsidies for the residential and small commercial classes?
As I mentioned before, when fixed costs are
recovered through a volumetric rate, the effects of any
conservation program that reduces energy consumption results
in a loss in the recovery of those fixed costs.In the case
of both the residential and the small commercial classes, the
reduction of energy consumption through conservation measures
not only prevents the Company from recovering the fixed costs
associated with those classes but, in addition , prevents the
fixed cost recovery of the subsidies which are incorporated in
their energy rates.
How are the other principle base level values
for the FCA mechanism determined in the current application?
The second base level determination necessary
for the FCA is a determination of customer counts for the
residential customer class and the small commercial class.
Based upon Case No. IPC-05-28 data, 2005 average customer
counts are 359,802 for the residential customer class and
30,899 for the small commercial class.
with these two principle base level values, the
FCC rate can be determined.The annual fixed cos t recovery
amounts divided by the customer count results in an annual
authorized recovery per customer.This amount divided by 12
results in the authorized recovery per customer per month, or
the monthly FCC rate.For the residential class, the
YOUNGBLOOD, D I
Idaho Power Company
authorized fixed cost recovery per customer per month is
$32.05 ($138,388,237 / 359,802 / 12).For the small
commercial class, the authorized fixed cost recovery per
customer per month is $23.50 ($8,712 552 / 30,899 / 12).
The third base level determination necessary
for the FCA is a determination of base level residential and
small commercial weather-normalized energy consumption for the
test year 2005.Based upon Case No. IPC-E-05-28 data, 2005
weather-normalized annual energy consumption for the
residential customer class is 4 503,865 230 kWh and annual
energy consumption for the small commercial class is
218,605,825 kWh.The monthly weather-normalized consumption
for these two classes (totaling up to their respective annual
weather-normalized consumption) would be used in determining
the monthly FCE rates.
With these additional principle base level
values , the FCE rates can be determined.The annual fixed
cost recovery amounts divided 12 (for the average monthly
fixed cost amount to be recovered) divided by the monthly
normalized energy results is an authorized fixed cost recovery
per kWh per month, or the monthly FCE rates.The following
table provides those monthly rates for each class:
YOUNGBLOOD, D I
Idaho Power Company
Residential Small Commercial
Energy FCE Energy FCE
January 521,441,918 $0.022116 212 875 $0.032686
February 474,386,901 $0.024310 21,028,201 $0.034527
March 422 463,431 $0.027298 19,175,405 $0.037863
April 364,339,261 $0.031653 16,668,063 $0.043559
May 311,538,986 $0.037017 15,583,867 $0.046590
June 289,411 745 $0.039848 15,550,690 $0.046689
July 325,367 237 $0.035444 17,433,880 $0.041646
August 367,476 844 $0.031383 644,764 $0.038941
September 340,623 099 $0.033857 865,158 $0.040640
October 299,584,302 $0.038495 16,504,791 $0.043990
November 339,226 389 $0.033996 300,035 $0.041968
December 448,005,117 $0.025742 20,638,096 $0.035180
TOTAL 503 865 230 218,605,825
How would the proposed FCA work for the
residential and small commercial classes , going forward?
Once these principle base level rates of FCC
and FCE are determined, the FCA would work identically for
both the residential and small commercial classes.For each
class, the actual number of customers per month would be
mul tiplied by the monthly FCC rate.This product would
represent the "allowed fixed cost recovery" amount.This
amount would be compared with the amount of fixed costs
actually recovered by the Company.To determine this "actual
YOUNGBLOOD , DI
Idaho Power Company
fixed costs recovered" amount, the Company would take monthly
weather-normalized sales for each class and multiply that by
the respective monthly FCE rate.The difference between these
two numbers (the "allowed fixed cost recovery" amount minus
the "actual fixed costs recovered" amount) would be the FCA
for each class.
Is this information sufficient in order to make
monthly bookings in the deferral account?
determined?
Yes.
How would monthly customer counts be
Each month the Company would determine the
number of active service points for the residential and small
commercial classes.This count of action service points is
the same information that is used in determining customer
counts for FERC Form 1 reporting requirements.
How would monthly weather-normalized energy be
determined?
In order to determine weather-normalized
monthly energy, heating and cooling degree-day information
would be gathered from the National Weather Service Forecast
Office.These numbers are used in the Company s weather
normalization model to determine monthly weather-normalized
energy.
Can the FCA deferral amount be negative, and if
YOUNGBLOOD, DI
Idaho Power Company
, what does this mean?
Yes, it can.The FCA can be either positive or
negative.If the adjustment amount were positive, that would
mean the Company s authorized fixed cost recovery amount was
greater than the fixed costs recovered through the class
energy rate.This would stem from the fact that the growth
rate in weather-normalized energy was less than the growth
rate in customers, i. e., the use per customer had decreased.
This would indicate that the Company had under-collected fixed
costs and therefore, additional dollars would be collected
from the customer in order to make the Company whole.In a
similar fashion , if the FCA were negative, that would indicate
that the Company had over-collected fixed costs, and would
result in a refund of the adjustment amount back to the
customer.
Would you please describe how the deferral
balance would work and when the deferral balance would be
collected from or refunded to the customer?
The deferral balance for the FCA would be
accumulated in a regulatory account in similar fashion to the
PCA.On a monthly basis, the FCA would be determined and
booked to the regulatory account.At year-end, the balance in
the account would be the FCA associated with that year.The
Company proposes to begin collecting/refunding the deferral
balance on June 1 of the following year , concurrent with rate
YOUNGBLOOD, D I
Idaho Power Company
changes associated with the PCA.The adjusted rate would
remain in effect for one year, through May 31 of the following
The Company proposes that the same carrying charge usedyear.
for PCA purposes would be applied to the deferral balance.
What would be the impact on the deferral
balance if a 3 percent FCA cap were reached?
If the 3 percent FCA cap was exceeded, and the
Commission chose to implement the cap, then the FCA would not
recover the full amount in the deferral account.The balance
of the deferral would remain in the account, subj ect to the
carrying charge, and would become part of the deferral balance
for the following year.
Please describe the possible rate impacts to
the average customer's bill.
From a review of the historical simulation
looking at the possible rate impacts to an average customer'
bill, the effects of the FCA would be small.Looking at the
period of 1994 through 2004 , with the assumptions of the
simulation as stated before, the average monthly impact to a
residential customer's bill would be $0.64.For an average
small commercial customer over the same period , their monthly
bill would see an average change of $0.31.ve calculated
these averages based upon the information shown for the
Monthly Bill Effect for Average Customer" in Exhibit No.
Are you proposing any reporting requirements
YOUNGBLOOD , DI
Idaho Power Company
for the Company to this Commission?
Yes.I would propose to report to the
Commission, on a monthly basis, the status of the balancing
account for the FCA.This would be done in the same manner as
is currently performed for reporting of the Company s Power
Cost Adjustment balance.The timing of the two reports could
be concurrent.
Are you providing an example of a new tariff
for the FCA?
Yes.I have included Exhibit No.9 as an
example of an FCA tariff.This Exhibit is for discussion
purposes only.An actual tariff would not be filed with the
Commission until June 2007.
Does this conclude your testimony?
Yes, it does.
YOUNGBLOOD, DI
Idaho Power Company
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BEFORE THE j; il.lii::::::; l:O,iiiISSiiJ;;
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O4-
IDAHO POWER COMPANY
EXHIBIT NO.
MICHAEL J. YOUNGBLOOD
Decoupling for Idaho Power Company
(Eric Hurst Study)
DECOUPLING FOR IDAHO POWER COMPANY
Eric Hirst
Consulting in Electric-Industry Restructuring
Bellingham, Washington
March 30, 2004
Prepared for
Idaho Power Company
Boise, Idaho
Mike Youngblood, Project Manager
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 1 OF 29
CONTENTS
1. INTRODUCTION ....................................................... 3
CURRENTSITUATION .................................................
3. COLLECTION OF FIXED COSTS THROUGH VARIABLE RATES ............. 5
POSSIBLERECOUPLINGMECHANISMS ................................. 8
5. ANALYSIS OF RECOUPLING MECHANISMS FOR IPC . . . . . . . . . . . . . . . .
. . . .,
IPCDECOUPLING-MODELRESULTS ...................................
BASE CASE ...................................................... 12
REVENUE PER CUSTOMER RECOUPLING ........................... 15
INFLATION RECOUPLING ......................................... 16
FORECAST-LOAD-GROWTHRECOUPLING .......................... 17
EFFECTSOFDSMPROGRAMS ..................................... 177. CONCLUSIONS ....................................................... 18
APPENDIX A: PAST EXPERIENCE WITH DECOUPLING ..................... 21
APPENDIX B. DETAILS ON RECOUPLING WORKBOOK.....................
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 2 OF 29
1. INTRODUCTION
Decoupling severs the link between a utility s kWh sales and its recovery of revenues
to cover fixed costs. Advocates of energy-efficiency programs favor decoupling because
current ratemaking practices collect substantial revenues for fixed costs through a utility
energy charge ($/MWh). As a consequence, utility programs that improve customer energy
efficiency create tension between the interests of customers (whose bills go down) and
shareholders (whose earnings decline).
Although decoupling may be motivated by the desire to expand electric-utility energy-
efficiency programs, its effects are broader. That is, decoupling will affect customer bills and
rates, as well as utility revenues, even if no utility DSM programs are implemented.
During the early 1990s, various forms of decoupling were deployed in Maine, New
York, California, and Washington. During the rnid-1990s, these efforts were largely abandoned
as utilities and state regulators anticipated a restructured, competitive electricity industry,
although Oregon began decoupling in the late 1990s. Recently, California reinstituted
decoupling. Appendix A provides details on the states' experiences with decoupling. Readers
interested in additional background on decoupling should see the references by Carter;" Eto,
Stoft and Belden;# Hirst;* Moskovitz, Harrington and Austin;t and Nadel, Reid and Wolcott:"
Decoupling involves two major steps. The first is the policy decision to break the link
between sales and revenues. The second, analytically more difficult, step is to recouple utility
revenues (more precisely, revenues to cover fixed costs) to something other than actual kWh
sales. Decoupling also involves other issues, such as:
whether to decouple for all or only some rate classes,
whether to recouple on a class-specific or system-wide basis,
whether to apply the decoupling-induced rate adjustments to energy charges only or to
both energy and demand charges, and
S. Carter, "Breaking the Consumption Habit: Ratemaking for Efficient Resource Decisions,The Electricity
JoumaI14(l0), 66-74, December 2001.
J. Eto, S. Stoft and T. Belden, The Theory and Practice of Decoupling, LBL-34555, Lawrence Berkeley
Laboratory, Berkeley, CA, January 1994.
E. Hirst, Statistical Recoupling: A New Way to Break the Link Between Electric-Utility Sales and Revenues,
ORNL/CON-372, Oak Ridge National Laboratory, Oak Ridge, TN, September 1993.
D. Moskovitz, C. Harrington and T. Austin
, "
Weighing Decoupling vs Lost Revenues: Regulatory
Considerations The Electricity JoumaI5(9), 58-63, November 1992.
S. N. Nadel, M. W. Reid and D. R. Wolcott (editors), Regulatory lncentivesfor Demand-Side Management,
American Council for an Energy-Efficient Economy, Washington, DC, 1992.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 3 OF 29
the frequency with which rates are adjusted for decoupling.
The next section describes the current (2003) situation that Idaho Power Company (IPC)
faces with respect to recovery of its fixed costs. Section 3 focuses on class-specific rate
structures and how they affect recovery of fixed costs. Section 4 briefly reviews alternative
ways to recouple utility revenues to something other than energy sales. Section 5 explains the
analytical method developed to examine alternative recoupling mechanisms for IPC, with
additional details in Appendix B. Section 6 presents model results. And the final section
summarizes the results, findings, conclusions , and recommendations from this study.
2. CURRENT SITUATION
This paper focuses on (and deals only with) the following rate classes: Residential
(Schedule 1), Small General (7), Large General (9), Large Power (19), and Irrigation (24).
Together, these five classes account for 99% of IPC's 2003 proposed revenue requirement.
Based on information from the current IPC rate case, 56% of the 2003 cost-of-service
revenue requirement covers fixed costs ($303 million of the $541 million total), with the
remaining 44% for variable energy costs ($237 million for fuel, purchased power, and variable
operations and maintenance at generating stations): As shown in Fig. 1, the fixed-cost (FC)
component is greatest for Schedule 7 (70%) and smallest for Schedule 19 (36%); this difference
is probably a consequence primarily of differences in load factors among classes. This suggests
that the net-revenue-loss problem associated with utility energy-efficiency programs might be
greatest for the Small
General class of customers.80%
Figure 1 also shows
fixed costs as a share ofproposed revenue
requirements. Because of
the large proposed cost
shift from the irrigation
class to the other classes
(25% of the irrigation cost
of service), the share of
revenue requirement from
fixed costs is much greater IPC
';"'
C,,.
for this class than the share Fig. 1.
...J
70%
II- 60%
a: 50%
cs::I:
40%
cs:
t; 30%
20%
u:: 10%
l1li% of Costs
D% of Revenue Requirement
d.. -----_
.-----_'~!~_~~-~-_~~:'~-----_'_---_'_-_"'_---
Residential Small General Large General Large Power Irrigation
Percentage of 2003 costs and proposed revenue
requirement from fixed costs, by rate class.
I assume that the only variable costs IPC experiences are for energy production.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 4 OF 29
of total costs: The effects of the shift from cost of service to revenue requirements is much
smaller (about 5%) for the other four classes. The remainder of this paper uses proposed
revenue requirements as the basis for calculating and adjusting fixed costs.
Table 1 provides key statistics, based on the 2003 rate case, for each customer class. The
Residential class accounts for just over half of the company s total fixed costs. Normalizing the
fixed costs for each class by the number of customers in each class shows substantial
differences, ranging from $420/customer for Small General to $206,000 for Large Power. The
difference between the proposed energy charge and variable energy cost is greatest for Small
General ($40IMWh) and smallest for Large Power ($3IMWh), with an average of $ 161MWh.
Table 1.Fixed- and variable-cost characteristics of IPC rate classes
Rate Class
Total
Fixed costs, million $153.13.54.21.6 60.303.4
Fixed costs as percentage 63.69.46.36.60.4 56.
of total cost
Fixed costs as percentage 60.66.4 43.34.4 80.56.of revenue requirement
Fixed costs/customer
, $
457 420 186 206,278 253 756
Variable cost, $IMWh 21.7 22.21.1 19.24.21.5
Energy charge, $IMWh 51.9 62.26.22.35.3 37.
The 2003 cost of service for class 24 is $100.but the proposed revenue
requirement is only $75.4 million, a 25% reduction.
million
3. COLLECTION OF FIXED COSTS THROUGH VARIABLE RATES
The relative importance of decoupling for different rate classes depends on the
relationship between fixed and variable costs (Fig. 1) and the rate design for that class
(discussed here). Rates for classes 1 and 7 include per-customer and energy charges, while
those for the other classes also include several demand charges.
The assumption that an of the class 24 fixed costs are to be recovered from the proposed rates implies that
the energy charge for this class is much too low. Thus, the substantial subsidy of c1ass 24 costs make the results
presented here suspect for that class.
To keep this discussion from becoming too complicated and to focus on the issues rather than the details, the
Schedule 9 and 19 subc1asses (Secondary, Primary, and Transmission) are combined into one average class. Similarly,
the demand charges are aggregated for each c1ass into one average charge.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 5 OF 29
For schedule 1 74% of the class-specific fixed costs are collected through the energy
charge (top of Fig. 2), amounting to $113 million for 2003 (bottom of Fig. 2). For Schedule 7,
the percentage of fixed costs collected by the energy charge is almost as high (71 %), but IPC' s
exposure is much lower ($10 vs $113 million) because Schedule 7 accounts for less than 10%
of the revenues of Schedule 1.
Interpreting the rate schedules for the other three classes is more complicated because
of their demand charges. Should these demand charges be considered variable or fixed? That
is, do they vary with energy (volumetrically) or are they fixed? The answer is probably class
and charge specific and likely falls part way between 100% variable and 100% fixed: For
example, the peak demand for Schedule 9 customers may have a large weather-sensitive
component, in which case summer demand (MW) and summer energy consumption (MWh) are
likely to be highly correlated. On the other hand, demand for Schedule 19 customers might be
dominated by industrial processes, which are independent of weather. If these processes are
either on or off, demand will be largely independent of energy sales. This issue is complicated
by the fact that the proposed rate schedules include on- and off-peak demand charges as well
as basic (12-month average) demand charges.
To some extent, the treatment of demand charges is an empirical issue. We could
analyze historical data by rate class to determine how tightly coupled (i.e., correlated) energy
sales and demand are. To some extent, this is a policy issue: deciding whether to adjust rates
for decoupling through energy charges only or through energy and demand charges.
If the revenues collected through demand charges are largely independent of energy
sales , then energy-efficiency programs aimed at Schedules 1, 7, and 24 have much greater
effects on FC recovery per kWh of energy saved than do such programs aimed at Schedules 9
and 19 (top of Fig. 2). Weighting each class by its contribution to total revenue shows the
importance ofIPC' s exposure to FC losses from each class. Clearly, the Residential class ($113
million, bottom of Fig. 2) is the most important, and Large Power ($3 million) is the least
important. Overall, 58% ($177 million) of IPC's FC revenues are collected through energy
charges, and an additional 25% ($76 million) is collected through demand charges.
On the other hand, if the revenues from demand charges are proportional to those from
energy charges, all five customer classes create exposures of 70% or more. Indeed, in this case
more than 90% of fixed costs are collected through variable charges for Schedules 9, 19, and
24. Overall, $252 million of fixed costs are collected through energy and demand charges
accounting for 47% of IPC revenues.
In the long run (say, 10 to 20 years), all costs are vanable.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD , IPC
PAGE 6 OF 29
a: w
LL C)
en I- oc:( 60
en
0 w
....I
En 40
oc:(
LL (t
LL oc:( 300 ~
'#-
DecouplingDala
100
LL
s:: a:
oc:(= J:.- 0-w
en ....I
I- En
en oc:(0 -0 ~ C ~
u::
DecouplingData
Fig. 2.
100
Residential Small General Large General Large Power Irrigation
120
Iii! Energy and Demand Charges Are Variable
0 Energy Charge Are Variable
Residential Small General Large General Large Power Irrigation
Collection of fixed costs through variable charges (energy plus demand or
energy only) by rate class. The top chart shows the percentage of fixed costs
collected through variable charges, and the bottom chart shows the year
2003 dollar amounts collected through variable charges.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 7 OF 29
Figure 3 presents
this information in yet
another way. This figure ~:!! 30
shows the net revenue loss
(the loss in FC recovery) ~
to IPC per MWh of energy u: 20
reduction: Again, results ~
are shown for two cases:
II:demand changes are I- 10
proportional to energy
changes, and demand
changes are independent
of energy changes. On a D.""p,.,D".
per MWh basis, the Fig. 3.
company is most exposedto energy-efficiency
programs aimed at the Residential and Small General classes, with losses of $27 and $36 per
MWh. At the other end of the spectrum, if demand-related revenues are independent of energy
sales, the losses for the Large General and Large Power classes are only $3 and $1 per MWh.
A veraged over all five classes, the company would lose $16 for every MWh reduction in sales.
Iij Energy and Demand Charges
Are Variable
0 Energy Charges Are Variable
Residential Small General Large General Large Power Irrigation
Loss of fixed-cost revenues per MWh of sales
reduction by rate class.
These results suggest that, if IPC decides not to implement decoupling for all rate
classes, it might focus initially on schedules 1 and 7. Because the residential class accounts for
more than half of IPC' s fixed costs and residential customers pay for much of their fixed costs
through the energy charge, IPC's earnings losses are quite high , both in absolute terms and on
a per MWh basis. Although Schedule 7 accounts for only 4% ofIPC's fixed costs, its energy
charge of $621MWh is the highest of all rate schedules.
4. POSSIBLE RECOUPLING MECHANISMS
Decoupling mechanisms, of necessity, recouple utility revenues to something other than
sales. Possible recoupling mechanisms include explicit attrition adjustments intended to track
the determinants of fixed costs (e.g., the cost of capital), the number of utility customers (which
seems most applicable to distribution costs), inflation (perhaps with a productivity offset), the
determinants of electricity sales, or some other mechanism. A key policy issue here is whether
recoupling should focus on tracking fixed costs (which seems the most reasonable but could
The numbers shown in Fig. 3 are based on the proposed rate structures, while those in Table I are based on
actual costs. The only substantial discrepancy occurs for Irrigation customers; Figure 3 shows a net revenue loss of
$26.3/MWh while Table I shows only $1O.7/MWh.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 8 OF 29
be quite complicated ) or on some proxy for sales (consistent with the traditional treatment of
fixed costs). A third option is to agree upfront on the level of allowed fixed costs for a few
years and to then have frequent rate cases. The Oregon PUC chose this approach in the mid-
1990s for decoupling mechanisms implemented by PacifiCorp and PGE, with rate cases to be
held every two years.
Two statistical analyses of data from several utilities showed little connection between
changes in a utility s fixed costs and its electricity sales:
In the long-run the relationship between (fixed) cost and customer growth
is stronger or no worse than the corresponding relationship between costs
and sales.
The short-term analysis of year-to-year changes in sales vs. base costs
shows no statistically significant relationship. Yet, ... the assumed
existence of a strong correlation between these two factors is the
foundation of traditional sales-based regulation.
Similarly, Eto, Stoft, and Belden wrote, "Relying on 25 years of aggregate financial
statistics from 160 investor-owned utilities, we find that one-year changes in load or numbers
of customers are both poorly-correlated with changes in nonfuel costs. Hence, the proponents
of RPC (revenue per customer decoupling) are correct in arguing that RPC does no worse than
traditional ratemaking in tracking nonfuel costs (indeed, we find it does slightly better).
These analyses show that decoupling replaces one set of factors unrelated to the
determinants of fixed costs with another set of factors unrelated to those costs. Decoupling, on
average, should have no positive or adverse effect on a utility s opportunity to recover its fixed
costs. On a year to year basis, decoupling might (or might not) stabilize FC recovery.
C. Marnay and G. A. Comnes
, "
California s ERAM Experience," Chapter 3 in Regulatory Incentives for
Demand-Side Management, edited by S. M. Nadel, M. W. Reid, and D. R. Wolcott, 39-, American Council for an
Energy-Efficient Economy, Washington, DC, 1992.
D. Moskovitz and G. B. Swofford, "Revenue-per-Customer Decoupling," Chapter 4 in Regulatory Incentives
for Demand-Side Management edited by S. M. Nadel, M. W. Reid, and D. R. Wolcott, 63- 77, American Council for
an Energy-Efficient Economy, Washington, DC, 1992.
J. Eto, S. Stoft, and T. Belden, The Theory and Practice of Decoupling, LBL-34555, Lawrence Berkeley
Laboratory, Berkeley, CA, January 1994.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 9 OF 29
5. ANALYSIS OF RECOUPLING MECHANISMS FOR IPC
I developed an Excel
workbook to quantify the effectsof different recoupling
mechanisms on customer
electricity bills and rates and on
IPC revenues. The workbook
calculates the interactions
between a particular recoupling
mechanism and alternative
forecasts of the number of
customers, peak demand, and
energy sales. These analyses use
data for 2003 from the IPC rate
case to simulate results for 2004, Fig. 4.
2005 , and 2006 (Fig. 4).
INPUTS
2003 Rate Case
2004 IRP Forecasts
2004 - 2006
Base Case
PARAMETERS
Recoupling Mechanism
Alternative Forecasts
Recoupling
Analysis
Results
Diagram of recoupling model.
The workbook is set up to test three forms of recoupling:
Revenue-per customer (RPC) decoupling, in which the amount of allowed FC recovery
is based on the number of customers each year. This method can be implemented on a
class-specific basis or on an aggregate basis (across the five rate classes) each year.
Inflation, in which the amount of allowed FC recovery is increased each year according
to the overall inflation index based on Gross Domestic Product (GDP).
Forecast growth, in which the amount of allowed FC recovery is predetermined on the
basis of the IRP forecasts of number of customers, electricity sales, and peak demand
for each year. Combined with the rate structures proposed in the 2003 rate case, these
forecast values determine the amount ofFC revenues expected to be collected each year.
Table 2 shows the forecasts prepared for the company s 2004 IRP used to simulate these
three recoupling mechanisms. Over the 4-year period from 2003 to 2006, growth is highest for
forecast revenue (7.3%) and lowest for inflation (6.1 %). Because of the relative magnitudes of
these forecasts, decoupling on the basis of forecast load growth will yield more revenue to
cover IPC' s fixed costs than would RPC decoupling, which , in turn, would yield more revenue
than would use of the GDP inflation factor.
Other forms of recoupling might be feasible, but have not yet been incorporated into the workbook or tested.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 10 OF 29
Year-to-year growth for three IPC recoupling mechanismsTable 2.
Revenue per GDP Forecast
customer inflation revenue
2004 1.024 1.020 027
2005 023 1.020 1.023
2006 023 1.021 1.021
2004 to 2006 1.071 1.061 073
The workbook considers two forms of recoupling: (1) all five rate classes face the same
changes in energy and demand charges because of decoupling, or (2) recoupling is done on a
class-specific basis. In the latter case, some classes could face rate increases at the same time
other classes face rate decreases. Although this might be hard to explain to the public, class-
specific decoupling might be more equitable because it considers separately the contribution
from each class to FC recovery.
Finally, the workbook adjusts rates in one oftwo ways: (1) energy and demand charges
or (2) energy charges only. This distinction is irrelevant for classes 1 and 7 (Residential and
Small General) because these two classes do not face demand charges. Customers in the three
other rate classes with high load factors would prefer a mechanism that adjusted both energy
and demand charges , while customers with low load factors would favor adjustments to only
the energy charge.
Appendix B contains additional detail on this workbook. The workbook contains many
assumptions necessary to conduct the calculations and to focus on the essentials rather than the
details. The key assumptions include:
All year-to-year changes in variable energy costs are recovered through the Power Cost
Adjustment (PCA) clause.
None of the transmission and distribution costs are variable; all of these costs are fixed.
The schedule 9 and 19 subclasses (Secondary, Primary, and Transmission) can be
combined into single classes to simplify the present analyses.
The various demand components (basic , summer, and nonsummer) can similarly be
combined into one demand component (and charge) for each relevant schedule (9, 19,
and 24).
The basic demand component varies from year to year with the IRP forecasts of average
peak monthly demand (average of the 12 monthly peaks) each year.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 11 OF 29
The summer and nonsummer demand components vary from year to year with the IRP
forecasts of maximum monthly demand (maximum of the 12 monthly peaks) each year.
Only five rate classes are considered here (1, 7,9, 19, and 24); the other classes (which
together, account for only 1 % of IPC's revenues) are ignored.
The decoupling rate adjustments occur without any lag (i., in the same year the costs
change). That is, this analysis ignores the complications of balancing accounts and after-
the- fact trueups that would affect rates in subsequent years.
The decoupling mechanisms considered here are all weather-normalized. That is
they-unlike current ratemaking-compensate the company for its fixed costs on the
basis of normal weather conditions:
6. IPC DECOUPLING- MODEL RESULTS
BASE CASE
The base case is defined as the situation forecast for the 2004 IRP in terms of annual
growth in the number of customers, peak demand, and energy use for each customer class. The
effects on customers and on IPC's FC recovery is exactly as expected , based on the three-year
growth in the three recoupling mechanisms.
With forecast recoupling, there are no adjustments (by definition); i.e., actual growth
in customers, energy, and demand match expected growth in these factors. Company losses
(and customer bill reductions) are greater with inflation recoupling than with RPC recoupling,
Table 3 and Fig. 5 show the effects of these two decoupling mechanisms on each rate class
when decoupling is implemented on a class-specific basis and when it is implemented in
aggregate (last column in Table 3). The results show both percentage and absolute changes in
customer bills (and IPC FC revenues), demand charges, and energy charges. (Because classes
Similarly, customer payments for fixed costs are weather normalized. For example, if the weather one year
is extreme, the company will collect (and consumers will pay) less money for transmission and distribution with
decoupling than it (they) would under traditional ratemaking. Adding a weather-adjustment component to a recoupling
mechanism is feasible but complicates the calculations. Doing so would require use of the IPC computer models that
weather adjust sales for each customer class and development of assumptions on "actual" weather (heating and cooling
degree days) in future years.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 12 OF 29
1 and 7 do not have demand charges, these numbers are alwayszero.* Annualized changes are
one-third the 3-year totals presented here.
Table 3.Base-case results (3-year changes in electric bills and rates relative to case
with no decoupling) for RPC and inflation recoupling, 2004 to 2006a
Rate Class Aggre-
Totalb gate
Revenue-per-customer recoupling
% Electric Bill 1.60 1.01
$ Electric Bill 320 1058 1539 2009 1593 - 2694 801
(thousand $)
% E/D Charges 1.20
Energy Charge
((t/kWh)
Demand Charge
($/kW -month)
Inflation recoupling
% Electric Bill 0.45 0.45
$ Electric Bill 2999 1578 3637 1280 1813 7681 681
(thousand $)
% E/D Charges 1.33 1.93 2.48
Energy Charge
((t/kWh)
Demand Charge
($/kW -month)
Results for forecast recoupling are not shown because it is the base case.
These percentage and dollar changes are the same as those IPC would experience in its
recovery of fixed costs.
AU the results shown in this section apply the same percentage change to energy and demand charges. It would
be possible (and the Recoupling model is set up) to adjust energy charges only. It is not possible to adjust demand
charges only because classes I and 7 pay no demand charges.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 13 OF 29
CJ) ~
...J CJ)..J W
III a:
a: C(W::J::EOCD0 c 0
CJ) C( :J
::E o:r
Z W 0- C C'II
W )::
C) C)Z a:
c:( W::I: Z0 w
"#-
Recoupling
Recoupling Metric: Per-Customer Recoupling
III Bills 0 Energy/Demand Charges
Total
RATE CLASS
Recoupling Metric: Inflation Recoupling
CJ) -
..J CJ)..J W
III a:
a: C(W::J::50CD0 c 0
CJ) C(
:J :E o:r
Z W 0- C C'II
W )::
C) C)Z a:C( W ma Bills::J: Z0 W
'#-
Recoupling
Fig. 5.
0 Energy/Demand Charges
Total
RATE CLASS
Three-year effects of two recoupling mechanisms on customer bills and
energy/demand charges by rate class. With RPC decoupling, IPC collects
$2.7 million less than it would with no decoupling mechanism. With
Inflation decoupling, IPC collects $7.7 million less over this 3-year period.
Under these base-case conditions, the forecast load growth recoupling
mechanism yields no changes in customer bills or rates.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD. IPC
PAGE 14 OF 29
The effects are much greater for inflation decoupling than for RPC decoupling because
the assumed growth in inflation is lower than the assumed growth in the number of customers
(6.1 v 7.1 % over the 3-year analysis period). With class-specific recoupling, customer bills (and
IPC FC recovery) are cut by $2.7 million with RPC decoupling and by $7.7 million with
inflation decoupling, compared with the base-case recovery of fixed costs (absent any
decoupling mechanism) of $946 million over the 3-yearperiod. These reductions represent 0.
and 0.45% of total customer bills for this 3-year period.
The effects of the two mechanisms under base-case conditions are greatest for Class 7
but result in bill and rate increases for class 24: The percentage changes in the energy and
demand charges are greater than those in overall bills because customer bills increase under
base-case conditions and because the customer charge is unaffected by decoupling.
Although there are substantial differences in the results between the two recoupling
mechanisms, among rate classes when implemented on a class-specific basis, and between the
total and aggregate results for RPC decoupling, these effects are all small. For example, the 3-
year effect on customer bills is well under 1 percent. The effects on rates, although larger in
percentage terms, are also small.
I next tested each of the three recoupling mechanisms against different growth rates for
customers, demand, and energy. The results of these analyses are discussed below, separately
for each of the three recoupling mechanisms.
REVENUE PER CUSTOMER RECOUPLING
Because this recoupling mechanism is based on one component of customer bills (the
monthly customer charge), the results differ according to differences in growth rates among the
three billing components (customers, demand, and energy).
As noted above, the base case results when all classes are treated the same (aggregate)
are quite different than when the classes are treated separately. The effects are much larger for
the class-specific recoupling, presumably because of the large differences among classes in the
fixed-cost-per-customer amounts, ranging from $420 for class 7 to $206,000 for class 19, and
because the results for class 24 (and sometimes for class 1) are of the opposite sign than those
of the other classes and the aggregate.
Appendix Table A-3 shows results for cases in which one or more of the billing
determinants is increased by %/year for all three years, six cases in all. In addition, the table
shows these results relative to the base-case results, the focus of this discussion.
As noted earlier, the results for Schedule 24 are suspect.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 15 OF 29
The results, for both customers and IPC, are symmetrical about the base case. That is
increasing, say, energy use by %/year over its base-case values has exactly the same effects
but with the opposite sign of decreasing energy use by %/year relative to the base case. This
symmetry applies to the two other recoupling mechanisms also.
Increasing (or decreasing) the growth rates for all three billing determinants by the same
amount has the same effects on FC recovery as does the base case. If growth in the number of
customers is higher (lower) by %/year than in the base case, FC revenues are higher (lower)
by 0.5%, independent of whether decoupling is class specific or aggregate. Customer bills
increase most for class 19 (0.8%) and least for class 9 (0.3%) with the class-specific application
of this recoupling mechanism.
Increasing demand and/or energy growth, while leaving customer growth unchanged,
lowers FC revenues. The results are much more sensitive to changes in energy use than to
changes in peak demand, probably because classes 1 and 7 have no demand charges.
The effects of changes in any of these three factors are additive. For example, the effects
of increasing peak demands by %/year plus the effects of increasing electricity use by 1 %/year
are the same as the effects of increasing both demand and energy by %/year.
INFLATION RECOUPLING
Inflation recoupling is completely independent ofthe three billing determinants. As with
RPC, the effects of changes in customer, demand, and energy growth are symmetrical around
the base case. That is, increasing growth in the number of customers, peak demand, or energy
use have the same effects, but with the opposite sign, as do decreasing growth in these three
factors.
Unlike RPC, the effects of inflation recoupling are the same regardless of whether it is
implemented in aggregate or on a customer-specific basis. Also unlike RPC, the effects on each
customer class are similar. Specifically, none of the six cases analyzed shows a difference in
the direction of effect across customer classes. For example, increasing all three growth rates
by 1 %/year leads to a reduction in customer bills that ranges from -3% for class 9 to -
for class 19, with an average of -6%.
Table A-4 shows results for the same set of cases discussed above for RPC, in which
one or more of the billing determinants is increased by %/year for all three years. Changes
in energy growth rates have a much larger effect than do changes in demand, which, in turn
have a larger effect than do changes in the number of customers. The effects of changes in the
three factors are additive.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD , IPC
PAGE 16 OF 29
FORECAST-LOAD-GROWTH RECOUPLING
Forecast recoupling depends on changes in all three billing determinants. Comparing
the right-hand sides of Tables A-4 and A-5 shows that the effects of forecast recoupling,
relative to the base case, are identical to those for inflation recoupling.
As with the other two mechanisms, the results are symmetrical around the base case.
Similarly, the effects are additive across all three billing determinants.
EFFECTS OF DSM PROGRAMS
When the only change from base-case conditions is slower growth in energy sales (and
perhaps peak demand), the company s collection ofFC revenues increases (as intended) by the
same amount regardless of the recoupling mechanism in place. If demand growth is unaffected
by the assumed IPC DSM program (i.e., its only effects are on energy sales), the decoupling
adjustment is smaller (as expected, because revenue collection through demand charges is
unaffected). Table 4 shows the effects on IPC FC recovery for DSM programs that cut energy
and demand by 1 %/year (i.e., 1 % in 2004, 2% in 2005, and 3% in 2006) and programs that cut
energy use only.* The effects of even such a large and effective DSM program on IPC revenues
are very small, less than 1 % of base revenues over this 3-year period. In these cases
decoupling works exactly as intended to ensure the company suffers no loss in FC revenue
because of reductions in energy use or peak demand.
Reductions in
Increase in IPC fixed-cost recovery (relative to base case) associated with
reductions of 1 % per year in energy use or energy use and demand
Increase in IPC fixed-cost recovery. 2004- 2006
million $ Percentage
Table 4.
Energy only 11 0.
Energy and demand 16 0.
IPC fixed-cost revenue for the 3-year period 2004- 2006 in the base case is $946
million.
The reductions in energy sales and demand described above, relative to the base case,
lead to a 0.9% increase in customer electricity bills and a 3% increase in energy and demand
charges over this 3-year period. As shown in Fig. 6, the percentage rate increases are highest
for classes 7 and 24 and lowest for classes 9 and 19.
The same results would obtain for such reductions in energy and demand regardless of the motivation for the
energy and demand cuts.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 17 OF 29
011
~ en...J W iii ~
II: c:(W J::!i u CD 30 C gI- Z C'IIen c:( ,
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C) C)Z II:c:( WJ: ZU W
'if-
Recoupling Metric: Load Growth Recoupling
mBllls 0 Energy/Demand Charges
Total
R~...'.'RATE CLASS
Fig. 6.Effects of 1 % per year reductions in energy use
and peak demands for three years on electricity
bills and rates, relative to the base case.
7. CONCLUSIONS
Current electric-utility ratemaking, as practiced in most jurisdictions throughout the
United States, collects substantial revenues to recover fixed costs from variable energy charges.
This practice makes little economic sense. Specifically, a utility s ability to recover its prudently
incurred fixed costs depends on factors that are (a) unrelated to those costs and (b) largely
outside its control, including economic and population growth in its service area, which, in turn,
affect energy sales.
This long-standing quirk in ratemaking unintentionally, but unavoidably, penalizes
utilities that encourage their customers to use electricity more efficiently. Thus, utilities face
a clear disincentive to help their customers improve energy efficiency.
Decoupling is a mechanism that breaks the link between electricity sales and utility
revenues. To implement decoupling, utility revenues need to be recoupled to some other
factor(s). This recoupling is necessary to ensure that the utility has an opportunity to recover
its fixed costs. However, many of the factors considered for recoupling-such as the number
of customers , inflation, or forecast revenues-may have no more logical connection to fixed
costs than does kWh sales.
Although decoupling is intended to remove the penalties in existing ratemaking for
utility DSM programs, its effects can be much broader. That is, depending on the recoupling
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 18 OF 29
method chosen, utility revenues (and, therefore, customer rates and bills) can vary from year
to year independent of a utility s DSM programs:
Decoupling is a zero-sum effort. If the company is paid more money to cover its fixed
costs (good for IPC), consumers will, unavoidably, pay more for transmission and distribution
services (bad for consumers). The reverse is also true.
The amount of the decoupling adjustment each year depends on how far from actual
conditions the recoupling mechanism is. For example, if recoupling is tied to inflation and the
actual growth in billing determinants differs substantially from inflation for that year, the
decoupling adjustment will be large. If the year-to-year changes in the number of customers,
peak demand, and energy sales yield changes in non-PCA revenues very different from the
inflation rate, the decoupling adjustment will be much larger than if the inflation rate and actual
revenues move together. Thus, decoupling does not necessarily stabilize FC recovery nor does
it make such recovery more predictable than traditional ratemaking.
Preparation of this paper was motivated by the advocacy of decoupling by the Natural
Resources Defense Council and the Northwest Energy Coalition.# Cavanagh proposes that the
Idaho PUC allow the company and other interested parties three to six months to develop
design recommendations for the Commission s consideration." These recommendations are
to consider the recoupling mechanism, separate v combined treatment of rate classes, weather-
normalization of the recoupling mechanism, and the frequency with which true-ups are to
occur. Cavanagh suggests there is ample "analysis and experience" to support a workable
mechanism.
I agree with Cavanagh that such a mechanism can be developed. Indeed, this paper
examined three such alternatives. The larger questions, in my view , are:
Does decoupling make sense to IPC at this time? IPC's DSM programs currently
operate at a very modest level, yielding only small effects on energy use. The 2004 IRP
might propose additional, stronger programs. But those programs are likely to focus on
reductions in summer peak demand more than on year-round energy efficiency. As
such, the new programs may have little effect on IPC's kilowatt-hour sales.
What unintended effects might decoupling have? Although decoupling would
completely sever the link between energy sales and utility revenues , it can and will
affect utility revenues for other reasons. In particular, the combination of a recoupling
Indeed, regulators in Maine and Washington abandoned decoupling in the mid-1990s largely for reasons
independent of the utilities' energy-efficiency programs. Decoupling in both states led to large rate increases because
of a slowdown in the economy (Maine) or high power costs (Washington).
R. Cavanagh Direct Testimony of Ralph Cavanagh, Case No. IPC-033-13, before theidaho Public Utilities
Commission, February 20, 2004.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD , IPC
PAGE 19 OF 29
mechanism and large changes in the factors affecting that mechanism could yield
nontrivial year-to-year changes in IPC revenues and, therefore, in customer bills and
rates.
Given the uncertain answers to these two questions, I recommend that IPC maintain an
open mind about decoupling. Specifically, I suggest the company accept Cavanagh'
suggestion and form a decoupling collaborative to work on these issues at the conclusion of the
current rate case. Hopefully, this paper will serve as useful background for that collaborative.
There is no way to know what IPC's actual fixed costs and FC recovery would be in the
future. They might be higher (or lower), more (or less) predictable, and more (or less) stable
than without decoupling. Absent detailed information on expected fixed costs and the
determinants of these costs, function by function, the potential benefits of decoupling with
respect to revenue predictability and stability remain unknown.
From a theoretical perspective, the recoupling mechanism should be tied to factors that
directly affect a utility fixed costs. Such factors are surely function specific, with different
factors affecting fixed costs for generation, transmission, and distribution. Developing such a
mechanism could be time consuming and complicated (as evidenced by the Electric Revenue
Adjustment Mechanism used in California from the early 1980s through the early 1990s).
Absent such a detailed understanding of utility fixed costs and their determinants, recoupling
uses mechanisms that relate to fixed costs no better than do kilowatt-hour sales, the current
approach to ratemaking.
My bottom line , based on past experience and the analyses presented here, is that
decoupling is likely to have only modest effects on IPC revenues and customer bills. It could
have slightly larger effects on the energy and demand rates for particular customer classes,
depending on the specifics of the recoupling mechanism.
C :\Dala\DocsIIPC\lPCDecouplingRepon, wpd
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 20 OF 29
APPENDIX A: PAST EXPERIENCE WITH DECOUPLING
This brief discussion is divided into three parts, the first dealing with decoupling during
the mid-1980s to early 1990s, the second covering the Oregon decoupling collaboratives in the
early- to mid-1990s, and the third dealing with decoupling implemented after the Western
electricity crisis of 2000/2001.
MID-1980s TO EARLY 1990s
California was the first state, in 1981 , to implement a decoupling system, called the
Electric Revenue Adjustment Mechanism (ERAM) (Marnay and Comnes 1992). Once every
three years, the California PUC set rates for each of the state s utilities in a general rate case.
The rate-case process, based on a future test year, included a determination of the amount of
money the utility could collect for its fixed costs. The ERAM mechanism was used to ensure
that for the years between rate cases the utility collected the correct amount of money to cover
these costs.
The PUC used attrition mechanisms to determine the amount of money the utility could
collect each year. Financial attrition adjusted for changes in the utility s cost of capital. These
adjustments were handled in annual proceedings that set interest rates and return on equity for
all the California utilities.
Operational attrition adjusted for changes in operating costs, such as wage rates and the
costs for certain materials. These costs were adjusted on the basis of price indices.
Finally, rate-base attrition adjusted for changes in the utility s ratebase. These
adjustments were based primarily on forecasts of capital expenditures developed during the
general rate cases.
During the first decade of operation, ERAM had very small effects on utility rates and
volatility.
New York, during the late 1980s and early 1990s, used decoupling mechanisms similar
to California s ERAM.
Washington and Maine adopted decoupling mechanisms in 1991 (Washington Utilities
and Transportation Commission 1992; Maine PUC 1993). Neither state used the California
approach. Instead, these states adjusted allowed fixed costs on the basis of growth in the
number of electricity customers.
The mechanisms adopted in Washington and Maine were used for only a few years. The
commissions abandoned decoupling because of substantial rate increases. These rate increases
had nothing to do with the utility s DSM programs. In Washington, power-supply costs (which
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD , IPC
PAGE 21 OF 29
were part of the decoupling mechanism) increased sharply, which led to decoupling-related
price increases. In Maine, slower than expected economic growth led to rate increases.
MID-1990s
PGE (1993) and PacifiCorp (1993) conducted decoupling collaboratives , in response
to an order from the Oregon PUe. The PGE collaborative proposal included the following
steps:
Establish base revenues using a 2-year test period,
Establish monthly revenue benchmarks and incremental power cost estimates,
Restate actual sales and revenues as if normal weather had occurred
Implement decoupling rate adjustments every six months,
Amortize decoupling adjustments over 18 months,
Spread decoupling adjustment among customer classes using the rate spread adopted
by the PUC in the 1991 general rate case.
In March 1995, the Oregon PUC adopted the PGE collaborative mechanism. The
following year, the PUC declined to adopt a decoupling mechanism for PacifiCorp. However
in 1998, the PUC ordered PacifiCorp to adopt an Alternative Form of Regulation that applied
decoupling only to the distribution function.
In 2001 , PGE (Lesh 2001) proposed a distribution-only decoupling mechanism for
residential and small nonresidential consumers only. The mechanisms would apply on a per
customer basis. The PUC rejected the PGE proposal.
EARLY 2000s
During the past two years, the California PUC, in response to state legislation, has
reintroduced decoupling for the California utilities (Bachrach and Carter 2004). Southern
California Edison currently has a decoupling mechanism in place for distribution costs only,
using a revenue-per-customer approach. The company proposed to add fixed-generation costs
to a new decoupling mechanism, using ERAM-like mechanisms. PG&E proposed to decouple
fixed costs for distribution and generation using an inflation index. SDG&E proposed a
revenue- per-customer mechanism.
As of now, decoupling operates in California and in Oregon only. While other states
may be considering decoupling, none has such mechanisms in place.
SUMMARY
Four states adopted decoupling mechanisms during the mid-1980s through early 1990s.
These experiences suggest the following lessons. The California ERAM mechanisms worked
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD . IPC
PAGE 22 OF 29
as expected and yielded very small rate adjustments. However, these mechanisms can be
complicated, and the annual mini-rate cases required for implementation can be contentious.
The Washington and Maine experiences show that decoupling can have effects that go well
beyond those related to utility DSM programs. In particular, nontrivial changes in other factors
included in the decoupling mechanism (power-supply costs in Washington and changes in the
trend of per-customer electricity use in Maine) can lead to politically unacceptable rate
Increases.
The Oregon experience during the mid-1990s included different decoupling mechanisms
for PGE and PacifiCorp. More recently, the California PUC is, once again, implementing
decoupling, and other states are considering such mechanisms.
Although the initial decoupling experiments were reasonably well documented
(especially California s), that is not the case for the more recent experiments. In particular, I
had a tough time finding (and understanding) information on the Oregon and recent California
experiences. Perhaps more important, I could find no study on the effects and effectiveness of
decoupling on utility DSM programs. As a consequence, we have no idea what the practical
effect, if any, is of decoupling 'on a utility s incentive to run cost-effective programs.
REFEREN CES
D. Bachrach and S. Carter
, "
Status of California s Policy Efforts to Eliminate Utilities
Disincentive to Invest in Energy Efficiency and Distributed Generation," Natural Resources
Defense Council, San Francisco, CA, February 27 , 2004.
P. G. Lesh 2001
, "
Advice No. 01-03, Distribution Decoupling Adjustment," Letter to Oregon
PUC, Portland, OR, March 19.
Maine Public Utilities Commission 1993, Order Approving Stipulation, Docket Nos. 90-085-
et aI., Augusta, ME, February 5.
C. Marnay and G. A. Comnes, "California s ERAM Experience " Chapter 3 in Regulatory
Incentives for Demand-Side Management edited by S. M. Nadel, M. W. Reid, and D. R.
Wolcott, 39-62, American Council for an Energy-Efficient Economy, Washington, DC, 1992.
PacifiCorp 1993, Report of PacifiCorp Decoupling Collaborative Portland, OR, May.
Portland General Electric 1993 Decoupling Collaborative Final Report, Portland, OR, April.
Washington Utilities and Transportation Commission 1992, First Supplemental Order
Rejecting Tariff Filing; Authorizing Refiling, Docket No. UE-920630, Olympia, W A,
September 24.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD. IPC
PAGE 23 OF 29
APPENDIX B. DETAILS ON RECOUPLING WORKBOOK
The Recoupling workbook contains three sheets: 1&0, Base, and Calc. The top part of
the first sheet (1&0, which stands for inputs and outputs) contains all the user inputs, while the
bottom part contains the decoupling results. The user inputs include class-specific or aggregate
growth rates (%/year relative to the base case discussed below) for the number of customers,
peak demand, and electricity sales. In addition, the user specifies which of the three forms of
recoupling to use, whether results are calculated on a class-specific basis or in aggregate, and
whether differences between actual and allowed fixed cost-recovery are collected or refunded
through energy and demand charges or through energy charges only.
The bottom part of 1&0 contains results for the particular decoupling case chosen (left-
hand side) as well as the base case (right-hand side). Decoupling results (all of which are
presented relative to the no-decoupling base case) include:
Percentage and dollar changes in annual electric bills,
Changes in IPC recovery of fixed costs: and
Percentage and actual changes in energy (It/kWh) and demand ($/kW-month) charges.
The Base sheet contains information from the 2003 rate-case filing, in particular data
from Brilz exhibits 42 and 43; see Table A-I. These data include characteristics of each rate
class (number of customers , basic demand, summer and nonsummer demand, and summer and
nonsummer energy use); proposed rate structures for each class; year 2003 revenues for each
customer class based on the proposed rate structures; and the fixed and variable costs for each
class. Table 1 summarized these results for each rate class.
In addition, the Base sheet contains the company s IRP forecasts for 2004, 2005, and
2006 of the number of customers, maximum monthly demand, annual average of the maximum
monthly demands each year, and electricity sales for each ofthe five rate classes, as well as the
overall inflation rate. Table A-2 shows these results.
These two sets of inputs are combined to calculate base-case results on class-specific
and total revenues, including recovery of fixed costs.
The Calc sheet calculates decoupling results given the inputs provided in I&O. These
results, for 2004, 2005 , and 2006, include the number of customers, the three demand
components, annual energy use, revenues collected from retail customers, revenues collected
for fixed costs (i., those not collected through the PCA), and allowed FC recovery (based on
the form of recoupling selected in 1&0).
Changes in IPC recovery of fixed costs are equal in magnitude and opposite in sign to the changes in annual
customer electric bills.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 24 OF 29
Table A-1. Inputs to Recoupling workbook from 2003 rate case
Rate Class Total or
Average
Rate Class Characteristics
# of customers 334 917 32,152 076 105 13,684 397 934
Basic 11,737 530 16,267
~ ~
Summer 399 997 040 6,436
E ~Nonsummer 709 908 515 13,131
Total 20,845 8,434 555 35,834
:;:...~
Summer 932,072 68,475 800,214 505,668 226,233 532 662
E'~Nonsummer 3,209 321 196,860 2 214 213 1 473 156 312 462 406 012
~ ~
Total 4,141 ,393 265,335 3 014,427 1 ,978 824 538,695 10,938 674
2003 Proposed Idaho Rates
Customer, $/month 10.10.24.500.
"0 I Basic
~ ~ 0 Summer 5.40
E ~ E Non-summerOJ Average
Summer 0614 0729 0290 0249 0326
OJ - ~Non-summer 0491 0583 0252 0212 0457
:;:...~
Total 0519 0620 0262 0221 0353 0373
Fixed Cost Percentages
of total costs 63.69.46.36.60.4 56.
of requested rev req 60.66.4 43.34.4 80.56.
2003 Proposed Revenues (thousand $)
Customer 190 858 957 628 374 008
Demand 40,087 379 16,416 882
Energy 214 787 16,463 78,961 43,773 306 408,291
Total 254 977 20,321 124 006 780 096 534 180
Costs, thousand $
Variable 101 888 832 69,595 41 ,197 893 233 406
Fixed 153 089 13,489 54,411 583 58,203 300,775
Total 254 977 321 124,006 780 72,096 534 180
Variable, $/MWh 0246 0257 0231 0208 0090 0213
:ixed-Cost Revenue/Customer 457.419.186 206,278 253 755.
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 25 OF 29
Table A-2. Base-case growth rates (%/year) from IRP
Rate Class Total or
24 Average
Customers
2004 2.41 2.42
2005 1.80
2006
Cumulative 1.08 1.06
Maximum MW
2004 2.48 3.41
2005
2006 1.36
Cumulative 1.08 1.08 1.08 1.08
Average MW
2004 2.49
2005 2.48 2.47 2.48
2006
Cumulative 1.08 1.08
Sales
2004 2.49
2005 0.45
2006 2.43
Cumulative 1.07 1.09 1.08
Price Deflator
Year PCWGDP Inflation, %/yr
2003 127
2004 149
2005 171
2006 195
Cumulative 061
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 26 OF 29
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Historical Fixed Cost Simulation Results
I Allowed t-Ixe
Cost Recovery
Based on Actual Fixed
Actual Actual Cost
Customer Customer Energy Revenue
Year Count Count Growth Difference Recovered
(1)(2)(4)(7)(8)(9)
1993 245,474 $103 007 702 524 040 $103,007,702
1994 246,586 0.45%$103,474 244 620 572,247 1.37%(0.92%)$104 416,786 ($942,542)
1995 264 456 25%$111,175,661 861 699 926 3.57%67%$108,346,096 $2,829,565
1996 272,622 09%$114 947 746 500 757 861 57%52%$110,368,374 $4,579,372
1997 280 588 92%$118,306,290 18,789 846,132 2,35%57%$112,960,910 $5,345 380
1998 288,999 00%$121 852 881 19,231 968,358 3.18%(0,18%)$116,550,678 $5,302 202
1999 298,803 39%$126,337,802 19,842 056,437 2.22%17%$119,469,857 $6.867 945
2000 307,559 93%$130 252 635 282 140,715 2,08%85%$122,151 096 $8,101,538
2001 318,293 3.49%$134 798,371 20,704 121 961 (0.45%)94%$121,597,857 $13,200 514
2002 327,192 80%$138 566,906 20,610 079,658 (1.03%)82%$120,349,923 $18 216,983
2003 335 604 57%$142,129 817 20.398 199,809 2.95%(0.37%)$123,894,364 $18 235,453
2004 346,949 38%$136 627 149 999 351 300 3,61%(0.23%)$129,991,644 $6,635,504
oWed Fixe
Cost Recovery
Based on Actual Fixed
Actual Actual Cost
Customer Customer Energy Revenue
Year Count Count Growth Difference Recovered
(1)(2)(4)(7)(8)(9)
1993 406 00%507,698 229,877 0.00%00%$9,507,698
1994 25,215 31%$9,822 516 149 230 531 28%03%534,763 $287 753
1995 26,363 55%$10 224 415 153 236 997 2,80%75%$9,758,858 $465,557
1996 687 02%$10 660 404 185 248 538 4,87%15%$10,160,242 $500,162
1997 932 50%$11,139,997 243 255,383 2,75%74%$10,440,053 $699,944
1998 29,778 92%$11,465 661 277 261,803 2.51%0.41%$10,702,494 $763 167
1999 127 17%$11 684 104 309 266 490 1,79%(0.62%)$10,973,034 $711 071
2000 30,183 18%$11,754 998 332 269,702 1.21%(1.02%)$11,152,184 $602 815
2001 317 44%$11,807 284 349 286 924 6,39%(5.94%)$11,864,288 ($57 004)
31,331 34%$12,202,217 1,435 265 806 (7.36%)10.70%$10,991,096 211 120
2003 32,342 23%$12,596,127 329 273,673 2.96%27%$11,316,375 279 752
2004 33,426 35%$11,624 521 368 287 958 5.22%(1,87%)$11 731,943 ($107,422)
" S M ALlC 0 M M ERC1Aa;:!/);;)!i\\t~;~'j;;'7f\#~~i(;f0~~wi;~g;~~f;~~J~!Jfl~%W?~f%\~Jf"lJ&4t~1fi!!
owed Fixe
Cost Recovery
Based on Actual Fixed
Actual Actual Cost
Customer Customer Energy Revenue
Year Count Count Growth Difference Recovered
(1)(2)(4)(7)(8)(9)
1993 597 00%$32,615,451 068,196 0.00%00%$32 615,451
1994 12,185 07%$34 268,350 10,341 911 398 (7.58%)12.65%$30,142,754 $4,125 596
1995 13,061 18%$37,271 238 557 263 424 18.42%(11.23%)$36,219,999 $1,051,239
1996 13,509 3.43%$39,459,583 317 353 663 3.99%(0.56%)$38,553,006 $906,577
1997 13,953 29%$40,758,583 11,768 452,008 4.18%(0.89%)$40,163,890 $594 693
1998 605 67%$42,661 417 260 580,652 5.25%(0.58%)$42,271,081 $390 337
1999 15,117 51%$43,766,277 903 711 684 5.08%(1.57%)$44,024,382 ($258 105)
2000 15,451 21%$44,500,593 13,558 840,574 4.75%(2.54%)$45,875,273 ($1,374 680)
2001 16,197 82%$46,646,906 203 962,895 4.31%52%$47,850,749 ($1,203.844)
2002 101 58%$49,251,340 814 934,711 (0.95%)53%$47,395,585 $1,855,755
2003 17,198 57%$49,531,521 14,674 005,724 2.42%(1.85%)$48,542,446 $989,075
2004 17,197 (0.01%)$48 074,110 15,029 050,001 1.47%(1.48%)$48,312,355 ($238 245)
EXHIBIT NO.
CASE NO. IPC-Q4-
M. YOUNGBLOOD, IPC
PAGE 1 OF 2
Historical Fixed Cost Simulation Results
INDUSTRIAL
vveatller
Allowed Fixed Normalized
Forecasted Cost Recovery Energy (MWH)Actual Fixed
Energy from Forecasted Based on DSM Energy Less DSM Cost
HistoricallRPs Energy Forecasted Savings Energy Energy Revenue Amount of
Year (MWH)Growth Energy (MWH)Savinas Growth Difference Recovered True-
(1)(2)(3)(4)(5)(6)(7)(8)(9)(10)
50%
1993 880 462 00%$18,409,719 880,462 0.00%00%$18,409,719
1994 985,287 57%$19,435,956 9,402 775,897 (5.56%)11,14%$17,386,032 $2,049,924
1995 880,357 (5.29%)$18,458,822 879 668,893 (6.03%)74%$16,382,948 $2,075,874
1996 952 786 85%$19,254,467 344 732 825 3,83%02%$17,085,655 $2,168,812
1997 056 208 30%$20,274 211 664 818,779 4.96%34%$17,933,163 341 048
1998 127,265 3.46%$20,974 828 094 911,967 5,12%(1.67%)$18,851 999 122,829
1999 194 621 17%$21 791,083 560 879,224 (1.71%)88%$18,659,410 131,672
2000 222 505 27%$22,158,370 396 933,734 2.90%(1.63%)$19,279,324 $2,879 046
2001 349 614 72%$23,425 655 669 017 030 4.31%1.41%$20 109,791 315,864
2002 136,545 (9.07%)$21,301 358 10,085 918,544 (4.88%)(4.19%)$19,127,885 173 473
2003 239 701 83%$22 329,819 593 976 985 3,05%78%$19,710,538 619,281
2004 138 111 (4.54%)$20,841 909 885 992,469 0.78%(5.32%)$19,422 219 419 690
Allowed Fixed
Forecasted Cost Recovery Actual Fixed
Energy from Forecasted Based on Cost
HistoricallRPs Energy Forecasted Energy Revenue Amount of
Year (MWH Growth Ener Growth Difference Recovered True-
(1)(2)(3)(4)(7)(8)(9)(10)
1993 620,515 00%$31 583,841 620,515 0.00%00%$31,583,841
1994 582 693 (2,33%)$30 846,696 103 632,834 0.76%(3.09%)$31,823,932 ($977 236)
1995 553 878 (1.82%)$30,154,892 164 557,930 (4.59%)77%$30,364,051 ($209,159)
1996 524 626 (1,88%)$29,379 549 790 624 957 4.30%(6.18%)$31,670,415 ($2 290,866)
1997 605,811 32%$30,943,976 125 538,128 (5,34%)10.67%$29,978,110 $965 866
1998 629,434 1.47%$31 399 190 691 588,471 27%(1.80%)$30,959 309 $439,881
1999 652 021 39%$32,240 433 942 670,605 5.17%(3.78%)$32,560,086 ($319,653)
2000 511,326 (8.52%)$29,712 668 353 827,588 9.40%(17.91%)$35,619 699 ($5,907 030)
2001 518,243 0.46%$29,848,667 138 660,369 (9.15%)61%$32 360,592 ($2,511,925)
2002 520 805 17%$29,899,032 302 632,697 (1.67%)84%$31 821,270 ($1,922,238)
2003 582,424 05%$31 110,457 163 611 305 (1.31%)36%$31,404,332 ($293 875)
2004 568 551 (0,88%)$35 258 287 057 616,744 0.34%(1.21%)$31,510 342 $3,747 945
~~j~~~~~~~~~~~~~01~;;~~~~;C~ '~
vveatner
Normalized
Energy (MWH)Actual Fixed
DSM Energy Less DSM Cost
Allowed Fixed Savings Energy Revenue Amount of
Year Cost Recovery (MWH)Savinas Recovered True-
(1)(2)(3)(4)(5)(6)(7)(8)(9)(10)
50%
1993 $195,124,410 323,090 $195,124,410
1994 $197,847,762 46,615 122 908 $193,304 267 $4,543,495
1995 $207,285,028 45,615 427,169 $201,071,952 $6,213,075
1996 $213,701,749 136 717,845 $207,837,692 $5,864,057
1997 $221 423,057 48,589 910,430 $211,476,125 $9,946,931
1998 $228,353,978 49,552 10,311,252 $219,335,561 $9.018,417
1999 $235,819,700 51,556 10,584,441 $225,686,769 $10,132,931
2000 $238,379,265 922 012,314 $234,077,576 301 689
2001 $246,526,883 55,062 11,049,179 $233,783,277 $12,743,606
2002 $251,220,852 55,246 10,831,417 $229,685,759 $21,535,093
2003 $257,697,741 54,157 067,496 $234,868,054 $22,829,687
2004 $252,425,975 55,337 298,472 $240,968,502 $11,457,473
EXHIBIT NO.
CASE NO. IPC-04-
M. YOUNGBLOOD, IPC
PAGE 2 OF 2
..., \\', '. '
7"7 r;; 5: 05
BEFORE THE lj\;~~, ::0;';\5510'
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-O4-
IDAHO POWER COMPANY
EXHIBIT NO.
MICHAEL J. YOUNGBLOOD
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IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-O4-
IDAHO POWER COMPANY
EXHIBIT NO.
MICHAEL J. YOUNGBLOOD
Monthly Bill Affect
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IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-O4-
IDAHO POWER COMPANY
EXHIBIT NO.
MICHAEL J. YOUNGBLOOD
Example of Fixed Cost Adjustment Tariff
Jdaho Power Company
. ~
I.P.C. No. 27 Tariff No. 101 OriQinal Sheet No. 54-
SCHEDULE 54
FIXED COST ADJUSTMENT
APPLICABILITY
This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company s Residential Service (Schedules 1 , 4, and 5) or Small General Service (Schedule
7).
FIXED COST PER CUSTOMER RATE
The Fixed Cost per Customer rate (FCC) is determined by dividing the Company s fixed cost
components for Residential and Small General Service customers by the average annual number of
Residential and Small General Service customers, respectively. The monthly FCC rate is $32.05 per
customer for Schedules 1 , 4 and 5 and $23.50 per customer for Schedule 7.
FIXED COST PER ENERGY RATE
The Fixed Cost per Energy rate (FCE) is determined by dividing the Company s fixed cost
components for Residential and Small General Service customers by the weather-normalized energy
load for Residential and Small General Service customers, respectively. The monthly FCE rates per
kWh for Residential (Schedules 1 , 4, and 5) and Small Commercial (Schedule 7) are:
January
February
March
April
May
June
July
August
September
October
November
December
Residential
2116i
2.4310i
7298i
1653i
7017i
9848i
5444i
1383i
3857i
8495i
3996i
5742i
Small
Commercial
3.2686i
3.4527i
7863i
3559i
6590i
6689i
1646i
8941i
0640i
3990i
1968i
5180i
ALLOWED FIXED COST RECOVERY AMOUNT
The Allowed Fixed Cost Recovery amount will be computed monthly by multiplying the average
number of Residential and Small General Service customers by the appropriate Residential and Small
General Service FCC rate.
ACTUAL FIXED COSTS RECOVERED AMOUNT
The Actual Fixed Costs Recovered amount will be computed monthly by multiplying the
weather-normalized energy load for Residential and Small General Service customers by the
appropriate Residential and Small General Service FCE rate.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 1 OF 2
ldaho Power Company
LP.C. No. 27. Tariff No. 101 Ori inal Sheet No. 54-
FIXED COST ADJUSTMENT
The Fixed Cost Adjustment (FCA) is the difference between the year-end Allowed Fixed Cost
Recovery balance and the year-end Actual Fixed Costs Recovered balance , the result divided by the
estimated consumption for the following year.
The monthly Fixed Cost Adjustment applied to the Energy rate for Residential Service
(Schedules 1 , 4, and 5) is cents per kWh. The monthly Fixed Cost Adjustment applied to
the Energy rate for Small General Service (Schedule 7) is cents per kWh.
EXPIRATION
The Fixed Cost Adjustment included on this schedule will expire May 31 , 2008.
EXHIBIT NO.
CASE NO. IPC-O4-
M. YOUNGBLOOD, IPC
PAGE 2 OF 2