20050215Final Report Workshop Proceedings.pdf

William M. Eddie ISB #5800
ADVOCATES FOR THE WEST
O. Box 1612
Boise, Idaho 83701
Phone: [phone]
FAX: [phone]
i ED
(~D( CEPlEO
inns fEU 1 L~ 1'1"1 it: 04
01 ILh1ES co'i:\~ii~smN
Attorney for NW Energy Coalition
Express Mail Address
1320 W. Franklin Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
OF FINANCIAL DISINCENTIVES TO
INVESTMENT IN ENERGY EFFICIENCY BY
IDAHO POWER COMPANY
FINAL REPORT ON WORKSHOP
PROCEEDINGS
CASE NO.IPC- E-04-
INTRODUCTION
This is a final report to the Idaho Public Utilities Commission on the workshop
proceedings undertaken in the above-captioned matter. This Final Report is intended to provide
the Commission with an overview of the workshops and the issues discussed, and the
recommendations of the workshop participants. Attached hereto are summaries of all five (5)
workshops, which provide substantially more detail.
The workshops were successful in that they included an open and well-informed
discussion of the nature and extent of fixed-cost revenue losses caused by demand-side
management (DSM) programs, and possible means to neutralize those losses or create other
incentives for strong performance in DSM programs. The participants in the workshops came to
INVESTIGATIVE WORKSHOP FINAL REPORT, Page
a general consensus that Idaho Power should apply to the Commission to undertake a
performance-based incentive pilot to allow the Company to fully recover fixed-cost losses and
to possibly acquire incentive benefits achieved by its two residential programs covering the new
construction market segment. These two programs are: (i) ENERGY STARCID Homes
Northwest, its residential new construction energy efficiency program, and (2) Rebate
Advantage for New Manufactured Homes, its program directed at the manufactured housing
market. In addition, it was the general consensus of the workshop participants that the potential
impacts of a broader fixed cost true-up mechanism should be simulated until Idaho Power s next
general rate case.
BACKGROUND
On May 25, 2004, the Idaho Public Utilities Commission (Commission) in Order No.
29505 (Idaho Power Company general rate case No. IPC-03-13) determined that a separate
proceeding to assess financial disincentives inherent in Company-sponsored conservation
programs is appropriate and should proceed by informal workshops." The Commission s Order
provided in relevant part as follows:
The Commission specifically directs the parties (Idaho Power NW Energy
Coalition, Industrial Customers of Idaho Power (ICIP) and Commission Staff) 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... technologies... In short, the
Commission believes 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. (emphasis
added)
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 2
Order No. 29505 at pp. 68 , 69.
As a follow up to the Commission s Order, the NW Energy Coalition on June 18 , 2004
formally requested that a proceeding be initiated and that a workshop schedule be established.
The Commission in Order No. 29558 established this docket to investigate financial
disincentives that hinder Idaho Power s investment in cost-effective energy efficiency resources.
The Commission stated that the scope of the investigation should be focused on true-up
mechanisms and performance based ratemaking.
As directed by the Commission, the participating parties provided a written status report
to the Commission on December 15 2004 to update the Commission on the status of the
investigative workshops.
PROCESS
The parties participated in five workshops to date: August 24, September 27, November
, December 1 , and December 13 , 2004. These workshops included presentations by
participants group discussion, and sensing for areas of agreement and disagreement. Susan
Hayman (North Country Resources) facilitated the workshops.Workshops were designed in
cooperation with four designated workshop coordinators representing each of the four major
interests at the table (Idaho Power Company, Idaho Public Utilities Commission Staff, Industrial
Customers of Idaho Power, and Northwest Energy Coalition).Copies of all workshop
summaries are provided as attachments to this Final Report.
PARTICIPANTS
The following people attended one or more workshops, received meeting materials and
summaries , and were considered active workshop participants:
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 3
Name and Affiliation Name and Affiliation
IPU Staff
Lynn Anderson
Randy Lobb
T em Carlock
David Schunke
Scott Woodbury
Northwest Enen?:v Coalition
Nancy Hirsh, NW Energy Coalition
Bill Eddie, Advocates for the West
Ralph Cavanagh, Natural Resources Defense
Council
Idaho Power
Ric Gale
Bart Kline
Maggie Brilz
Darlene N emnich
Greg Said
Tim Tatum
Mike Youngblood
Industrial Customers of Idaho Power
Peter Richardson, Industrial Customers of Idaho
Power
David Hawk, J .R. Simplot Co
Don Reading, Ben Johnson Associates
Other Interested Parties
Brad Purdy, Community Action Partnership
Association
of Idaho
Laura Nelson, IPUC Policy Strategist
NATURE AND EXTENT OF LOST FIXED COST REVENUES
The underlYing problem addressed in the workshops was described in the Direct
Testimony of Ralph Cavanagh submitted in case number IPC-03-13: Successful
implementation of DSM programs generally results in fewer sales of kilowatt-hours and/or
reductions in demand for energy than would occur without the programs. Because Idaho Power
primarily recovers its fixed costs of service as a portion of kilowatt-hour sales and/or demand
charges, many DSM programs result in reduced fixed-cost revenue recovery.
The workshops first focused on identifYing the nature and extent of fixed-cost revenue
recovery impacts associated with varying levels of DSM investment by Idaho Power. These
impacts are highly dependent on the type, level and effectiveness of DSM programs. For the
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 4
workshop proceedings, IPUC Staff analyzed expected fixed-cost revenue losses over a 9-year
period (with 2 assumed intervening rates cases) under the level of DSM investment
recommended in the Northwest Power and Conservation Council's Fifth Plan. The Fifth Plan
level of DSM investment is approximately equal to savings on the order of 0.5% per year
(including Northwest Energy Efficiency Alliance efforts, fuel conversions, building codes
appliance standards, and other DSM for which utilities have limited, little, or no control). Under
Staffs contention that except for 6-month regulatory lag any future fixed-cost revenue losses
from installed efficiency measures are "zeroed out" after each assumed rate case, the 9- year total
fixed-cost revenue loss is $54.6 million.The present value of the $54.6 million is about
$39 million, and the levelized loss is $6 million per year.
IPUC Staff conducted a similar 9-year analysis under the level ofDSM investment
anticipated under Idaho Power s 2004 Integrated Resource Plan. The 2004 IRP DSM plan does
not include efficiency gains achieved under regional efforts such as NEEA, code changes, or
other advancements, but does include a substantial increase in utility-managed DSM programs.
Again assuming that any future fixed-cost revenue losses from installed efficiency measures are
zeroed out" after each rate case, the Staff-quantified 9-year total fixed-cost revenue loss is
$3 million; the present value is about $2 million; and the levelized value is about $0.3 million per
year. This $0.3 million amount is illustrative of the Staff-calculated fixed-cost revenue losses
expected under potential levels of DSM activity identified by Idaho Power s 2004 Integrated
Resource Plan (IRP).
However, as the discussion ofNWPCC's Fifth Plan partly demonstrates, the amount of
fixed-cost revenue losses would be much higher if the calculation accounted for other energy
efficiency advances undertaken outside of Idaho Power s programs and for persisting energy
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 5
efficiency measures across rate cases. In the workshops, NRDC and NWEC contended these
analyses understated potential losses from aggressive Idaho Power DSM programs. For
example, Ralph Cavanagh of NRDC reviewed with the group the basis for the conclusion in his
filed testimony that programs saving just one percent of system-wide electricity consumption
annually would eliminate about $45 million in fixed-cost recovery within just five years. And
NRDC/NWEC contended that even regular rate cases could not remove the continuing adverse
effects of long-term electricity savings on the Company s balance sheet.
The amount of fixed-cost losses incurred under all of these scenarios varies by customer
class due to the differing fixed costs of service for each class, and the amount of fixed costs
recovered from energy and/or demand charges that vary with consumption. More than other
classes, the fixed costs of serving the residential and small commercial customers are recovered
through variable energy charges - and DSM programs for this class result in the largest fixed
cost revenue losses. Moreover, in the residential class, energy usage per customer generally has
been declining in recent years from a high mark of an average 14,474 kWh customer/year in
1991 to 12 635 kWh customer/year in 2003.
POTENTIAL MECHANSIMS TO ADDRESS LOST FIXED-COST REVENUES
In light of the expected loss of fixed-cost revenues from DSM programs described above
the workshop participants agreed that material financial disincentives to the implementation of
DSM programs do exist. However, not all participants agreed that restoration of lost fixed-cost
revenues - such as through an annual true-up mechanism - would directly result in additional or
more effective investment in DSM programs by Idaho Power.The Commission s order
initiating this matter identified possible solutions to address the disincentives to investment in
DSM programs created due to lost fixed-cost revenues, including a true-up mechanism to restore
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 6
lost fixed costs, as well as performance based mechanisms to allow Idaho Power Company to
share some of the benefits of successful DSM programs.
The workshop participants came to agreement on a set of criteria to evaluate different
approaches to address lost fixed-cost revenues incurred by the Company due to successful DSM
programs, or to provide incentives for DSM programs. The criteria are:
1. Stakeholders are better off than they would be without the mechanism.
2. Minimize cross subsidies across customer classes.
3. Removes financial disincentives.
4. Optimizes the acquisition of all cost-effective DSM.
5. Promotes rate stability.
6. Simple mechanism.
7. Administrative costs and impacts of the mechanism are known, manageable, and
not subject to unexpected fluctuation.
8. Monitors short and long term effects to customers and company.
9. Avoids perverse incentives.
10. Close link between mechanism and desired DSM outcomes.
These criteria generally governed the workshop participants consideration of
mechanisms to address the lost fixed-cost revenues issue. For example, so-called "lost revenue
recovery" mechanisms limited to DSM savings can be criticized because they turn program
evaluation into a high-stakes adversarial process, and because they create an incentive for a
utility to fashion a program that "looks good on paper " but does not actually perform well.
Likewise, a mechanism that simply trues up a utility s recovery of its authorized fixed-
cost revenue requirement may be easy to implement and monitor, but only removes the financial
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 7
disincentive to DSM while other barriers may remain. For that reason, a true-up mechanism on
its own may not drive a utility to acquire all cost-effective DSM available in its territory. In
addition, a true-up mechanism may shift the current allocation of risks from changes in sales due
to weather, economic shifts, or technological advances.
The workshop participants gave careful consideration to two mechanisms: a true-up
mechanism to ensure that Idaho Power reco\:,ered no more or less than its authorized fixed-cost
revenue requirement; and a pilot program to provide an incentive to the Company to achieve
substantial cost-effective savings in one important category ofDSM programs.
True-up mechanism: The Natural Resources Defense Council and NW Energy
Coalition proposed a true-up mechanism to restore lost fixed-cost revenues to Idaho Power. The
starting point for the proposal was the fixed-cost revenue requirement and retail rates approved
by the Commission for Idaho Power s most recent rate case. The fixed-cost revenue requirement
would then be automatically adjusted annually (until reestablished in the next rate case) as
follows: (a) for the Industrial and Agricultural sectors, the fixed cost revenue requirement would
be adjusted to reflect the same rate of increase (or decrease) shown for retail electricity sales, net
of any DSM programs, in the load forecast section of Idaho Power s latest Integrated Resource
Plan; or (b) for the Residential and Commercial sectors, the fixed cost revenue requirement
would be adjusted to reflect the actual changes in annual customer count for the residential and
commercial sectors (in other words, the fixed cost revenue requirement per customer would
remain fixed until the next rate case). Concurrent with each annual power cost adjustment case
true ups would occur by customer class based on any divergence between the total fixed-cost
revenue recovery that forecast sales of kilowatt-hours and demand charges (for Agricultural and"
Industrial sectors) or actual customer growth (for Residential and Commercial) would have
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 8
delivered versus the fixed-cost revenues actually recovered through actual sales. Idaho Power
would continue to absorb the risk or benefits of purely weather-related effects on fixed-cost
revenue recovery, as it does now. Actual sales would 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 would be capped at 2% annually, with any additional amounts carried
over to the next year s true up.
Rather than actual implementation, the workshop participants agreed to a "Simulation" of
the true-up proposal to help illuminate its potential impacts under the criteria described above.
The Simulation would include both retrospective and prospective components by using the fixed-
cost revenue requirements approved in the 1994 and 2004 rate cases as starting points. It would
apply an assumed level of efficiency savings of 0.5% annually (roughly equivalent to the level of
savings achievable under the NWPCC's Fifth Plan) each year starting in 1994 and 2004.
To illuminate the impacts of the true-up proposal, the Simulation would calculate the: (1)
annual rate impact to each customer class for the true-up; (2) the impact of DSM savings on the
PCA; (3) the annual impact to average customer bill amounts (assuming the 0.5% annual
efficiency savings and the annual net benefit estimates developed in the energy efficiency
assessment provided as an addendum to the 2004 IRP); and (4) total impact of true-up
mechanism to IdaCorp shareholders.
Pilot Incentive: At the group s request the IPUC Staff developed a strawman proposal
for a performance based Pilot Incentive.CIDStaff chose to target the ENERGY STAR Homes
Northwest program for the strawman and at the group s request, Idaho Power and IPUC Staff
later collaboratively refined it into a proposal. This DSM program, which was included in the
Company s 2004 IRP, offers an incentive to builders to achieve a standard of 300/0 energy
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 9
savings over and above existing code requirements. The original program proposal targeted a
specific number of homes in which to achieve these savings in 2005. With further refinement
Idaho Power adopted a MWH reduction target, encouraging the company to achieve even greater
savings as well as putting the focus of the program on energy savings rather than a specific
number of homes. The energy target to be achieved through this program in 2005 is a reduction
of 1 070 annual MWH. The Idaho Energy Division conducts quality assurance for the program
and NEEA provides builder training.Under the Pilot Incentive, Idaho Power would recover
fixed-cost revenues lost due to the validated energy savings provided by the program, and earn
an additional incentive if the energy savings achieved by the program exceed 100% of the
targeted savings. As described below, Idaho Power is expected to submit an application to the
Commission to implement this program.
The ENERGY STARCID Homes Northwest program was chosen for the Pilot Incentive
because residential rates have a high fixed-cost component recovered through variable energy
charges and because it is a relatively small program so any potential unanticipated impacts of the
Pilot Incentive will be small. Also, this program is projected to be very cost effective and its
results are expected to be relatively easy to monitor. The workshop participants also agreed to
recommend adding Idaho Power s Energy Efficient Manufactured Home Incentives program to
the Pilot Incentive. The targeted savings for this project is 555 annual MWH.
RECOMMENDATIONS OF THE WORKSHOP PARTICIPANTS
Idaho Power Company anticipates filing an application with the Commission to
implement the pilot program described above. The workshop participants are supportive of the
pilot as described in the workshops, but reserve their rights to comment on the proposal as filed
with the Commission.
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 10
In addition, Idaho Power has agreed to implement a Simulation of the true-up mechanism
proposed by NRDC and NW Energy Coalition, as described above, until Idaho Power s next
general rate case. This action does not require action by the Commission; however, the results of
the Simulation will be provided to workshop participants and the Commission
contemporaneously with each annual PCA filing. Idaho Power will work with workshop
participants as the Company prepares its next rate case filing to analyze the results of the
Simulation and evaluate incorporation of a true-up mechanism into the rate filing.
This Final Report to the Commission has been reviewed and approved by Commission
Staff and Idaho Power Company.
Dated this 14th day of February, 2005.Respectfully submitted
. \
William Eddie
"-- -
Attorney for NW Energy Coalition
INVESTIGATIVE WORKSHOP FINAL REPORT, Page 11
CERTIFICATE OF SERVICE
I hereby certify that on this 14th day of February 2005, true and correct copies of
the foregoing FINAL REPORT were delivered to the following persons via hand delivery
(for Commission recipients) and U.S. Mail (for all others):
Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W.Washington
Boise, ill 83702
Lawrence Gollomp
Assistant General Counsel
S. Dept. of Energy
1000 Independence Ave., SW
Washington, DC 20585
Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
472 W.Washington
Boise, ID 83702
Dean Miller
McDevitt & Miller
O. Box 2564
Boise, ill 83701
Barton Kline
Idaho Power Company
O. Box 70
Boise, ID 83707-0070
Conley Ward
Givens Pursley
601 W. Bannock St.
O. Box 2720
Boise, ID 83701-2720
John R. Gale
Idaho Power Company
O. Box 70
Boise, ill 83707-0070
Brad Purdy
2019 N. ih St.
Boise, ID 83702
Peter Richardson
Richardson & O'Leary
O. Box 1849
Eagle, ill 83703
Michael Kurtz
Kurt J. Boehm
Boehm, Kurtz & Lowry
36 E. Seventh St., Suite 2110
Cincinnati, OH 45202
Don Reading
Ben Johnson Associates
6070 Hill Road
Boise, ID 83703
(:/'/
Vl/
William Eddie
Randall Budge
Racine, Olson, et al.
201 E. Center
O. Box 1391
Pocatello, ill 83204-1391
William M. Eddie ISB #5800
ADVOCATES FOR THE WEST
O. Box 1612
Boise, Idaho 83701
Phone: [phone]
FAX: [phone]
Attorney for NW Energy Coalition
Express Mail Address
1320 W. Franklin Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
OF FINANCIAL DISINCENTIVES TO
INVESTMENT IN ENERGY EFFICIENCY BY
IDAHO POWER COMPANY
ATTACHMENTS TO FINAL
REPORT ON WORKSHOP
PROCEEDINGS
CASE NO.IPC- E-04-
Attached hereto are summaries of all five (5) workshops conducted in the above matter.
Due to the volume of material, one original printed copy is provided to the Commission, together
with a computer disc providing electronic copies of the same. Additional computer discs can be
obtained by contacting the undersigned counsel.
Dated: February 14, 2005 Respectfully submitted
-"---
William M. Eddie
Attorney for NW Energy Coalition
DECOUPLING FOR
IDAHO POWER COMPANY
Eric Hirst
Consultant in Electric-Industry Restructuring
Bellingham, WA
Eric~Ehirst.com www.Ehirst.com
August 2004
SETTING RATES
SETTING RATES HAS TWO STEPS
2. Design rates
Functionalization: Generation, Transmission,
Distribution, Other
Classification: Energy, Demand, Customer Service
Allocation: Residential, Small Commercial, Large
Commercial, Industrial, Irrigation, etc...
TOPICS TO COVER:
. Basics of rate setting
. Regulatory reforms to support utility DSM programs
. Basics of decoupling
. Idaho Power Company costs and rates
fixed vs. variable costs
. Recoupling mechanisms
. IPC model results
. Conclusions and suggestions
SETTING RATES HAS TWO STEPS
1. Determine Revenue Requirements:
- RR = Expenses + Return on Rate Base
Expenses = Fuel + Other Variable Costs + Fixed
Costs
Fixed Costs = Fixed Operating Costs +
Depreciation + Taxes + Interest Payments
Return on Rate Base =
Overall Return (equity + debt)*Rate Base
COST ASSIGNMENT IN RATE DESIGN
TYPICAL RATE MIGHT HAVE
SEVERAL ELEMENTS
. Monthly customer charge, $/month
. Energy charge(s), it/kWh
- Time Invariant, seasonal, time-of-use, or hourly
. Demand charge(s), $/kW-month
- Coincident and/or noncoincident peak demands
REFORMS TO PROMOTE
UTILITY DSM PROGRAMS
IPC RESIDENTIAL CLASS COST
$243 MILLION IN 2003
Customer Demand Energy
Generation
Transmission
Distribution
Customer
$153 million
SETTING RATES INVOLVES MANY
ASSUMPTIONS AND JUDGMENTS
. Historical vs. future test year
. Average vs. marginal costs
. Split generation costs into
fixed vs. variable
. Inflation and Interest rates
. Capital structure
THREE-LEGGED STOOL FOR
DEMAND SIDE MANAGEMENT
. Prompt and assured recovery of prudently incurred
costs for program design and operation
. Protection against net lost revenues (e., decoupling)
. Incentives (share-the-savings) for exemplaryprog~ms
. Environmentalists focus on these key obstacles to
utility implementation of cost-effective DSM
- Align utility financial incentives with actions that
benefit customers
RESIDENTIAL CLASS:
2003 PROPOSED RATES
. Rates Include monthly and energy charges, no
demand charges
- $10/month
- 335,000 customers- $40
19 it/kWh
140 GWh
$215 = $255 million
. 74% of fixed costs collected from energy rate
. Proposed revenues ~ costs to offset subsidy for
irrigation customers
IPC SHAREHOLDERS LOSE MONEY IF
RESIDENCES CUT CONSUMPTION
. Energy charge:19 ~/kWh
. IPC energy cost:17 ~/kWh
. IPC shareholder loss from
energy savings: 3.02 ~/kWh
TRADITIONAL FIXED-COST
RECOVERY DEPENDS ON FACTORS
. Largely unrelated to fixed costs
. Largely outside the utilitys control
(e., weather and economic growth)
RATE REFORM WOULD ELIMINATE
LOST-REVENUE PROBLEM
. Cut energy charge from 5.19 to 2.17 ~/kWh
. Increase monthly customer charge from $10 to $41
. IPC revenue unchanged, still $255 million
. IPC has no incentive to either discourage
conservation or promote sales growth
- Revenues from increased sales exactly cover
increased variable costs
NO LOGIC TO CURRENT SYSTEM
. Two studies (early 1990s) showed no link between
changes in utility fixed costs and electricity sales
. Few reasons for current system of recovering fixed
costs through variable charges:
- Tradition
- Convenience
. Should utility shareholders benefit from weather
extremes (and lose money during mild winters and
summers)?
HOW TO TREAT LOST REVENUE?
. Drop all utility energy-efficiency programs
. Run aggressive marketing programs
. Conduct annual rate cases
. Modify rate design
(shift from energy to customer charges)
. Adopt net-lost-revenue adjustment
mechanism
. Adopt decoupling mechanism
. Other?
DECOUPLING BASICS
DECOUPLING HAS TWO PARTS
1. Policy decision to sever link between revenues (and
utility earnings) and sales (kWh and perhaps kW)
2. Recouple revenues (more precisely, revenues to
cover fixed costs) to something else:
- Number of customers
Inflation
Determinants of fixed costs (cost of capital, labor
rates, etc)
Forecasts of billing determinants
Other??
DECOUPLING ISSUES
. Decouple rates for all or only some rate classes
. Recouple on a class-specific or systemwide basis
. Select recoupling mechanism(s)
. Whether to weather-normalize adjustments
. Frequency of rate adjustments for decoupling
. Limits on magnitude of such rate adjustments
IPC COSTS AND RATES
DECOUPLING MECHANICS
. Bill customers under current tariffs
(existing customer, demand, and energy charges)
. Calculate allowed revenues with recoupling
mechanism
. Put differences between actual and allowed revenues
in balancing account
. Refund (surcharge) amount in imbalance account
POSSIBLE DECOUPLING CRITERIA
. Remove disincentive to customer energy efficiency
. Remove incentive for uneconomic load building
. Align incentives with IRP
. Retain incentives to
- control costs, improve customer service, etc.
. Simple to understand and administer
. Difficult to manipulate
. Minimize volatility of electricity prices and utility
earnings
CLASSES DIFFER SUBSTANTIALLY
(these 5 account for 99% of IPC revenue)
% of customers % of energy
Residential (1)
Small general (7)
Large general (9)
Large Power (19)
Irrigation (24)
56% OF IPC'S COSTS ARE FIXED
..J 70
";ft.
Average. 56%
c:( 40
fiJ 20
Residential Small General Large General Large Power Irrigation"000"'-
FRACTION OF FIXED COSTS FROM
VARIABLE CHARGES
100
:;: 80
IE ~ 70'" C)
'" c(
0 J:
~g~ 40
u.. ~
~ ~ 30
Residential Small General Large General Large Power Irrigation
RESIDENTIAL AND SMALL COMMERCIAL
CREATE LARGE EXPOSURE
:;:
..JW 20::J
IJEnergy and Demand ChargesAre Variable
DEnergy Charges Are Variable
Residential Small General Large General Large Power Irrigation
BIG DIFFERENCES BETWEEN
ENERGY COSTS AND CHARGES
~ 0.
mCharge DCost
~ 0.
~ 0.
:3 0.
Residential Small General Large General Large Power Irrigation
RESIDENTIAL CLASS: 2/3 OF FIXED COSTS
FROM ENERGY CHARGES
120
:;:
100u.. '"
...~
2 ~ 80;: J:
;~
I- III
:3 $0 ~ 40
C ;:.
u:
Ii Energy and Demand Charges Are Variable
0 Energy Charge Are Variable
Residential Small General Large General Large Power Irrigation
RECOUPLING MECHANISMS
SEVERAL RECOUPLING OPTIONS
POSSIBLE
. Conduct rate cases with future test year every year or
two (Oregon proposal)
. Recouple revenues to number of customers
- Aggregate or class specific
. Recouple revenues to Inflation
- National or regional deflator, or Industry specific
indices (Handy Whitman)
. Forecast growth rates (using approved IRP forecasts
for customers, energy, and demand)
. California-style attrition mechanisms
IPC MODEL RESULTS
TESTED THREE RECOUPLING
MECHANISMS WITH MODEL
. Revenue-per customer (RPC)
- Class specific
- Aggregate
. Inflation
. Forecast growth in customers, kWh and kW from
2004 IRP, by class
. Used 2003 as base, analyzed 2004 to 2006
- 2003 results from IPC rate case, Includingproposed (not approved) rate structures
- 2004 - 2006 growth rates from IRP
. Customers, energy, demand, Inflation
MORE GENERALLY, SHOULD
RECOUPLING TRACK
. Determinants of fixed costs
. Determinants of sales growth
DEVELOPED EXCEL WORKBOOK TO
ANALYZE DECOUPLING FOR IPC
INPUTS
2003 Rate Case
2004 IRP Forecasts
2004 . 2006
Base Case
PARAMETERS
Recoupling Mechanism
Alternative Forecasts
Recoupling
Analysis
Results
AS WITH ALL ANALYSES
SEVERAL ASSUMPTIONS MADE
. All year-to-year changes in variable energy costs
covered by Power Cost Adjustment, not analyzed here
. All T&D costs fixed
. Schedule 9 and 19 subclasses combined into single
classes
. Seasonal and other demand components combined
into one demand charge for each schedule
. Decoupling rate adjustments occur with no time lag
. Decoupllng mechanisms weather normalized
- Unlike current system, compensate for fixed costs
based on normal weather
IRP FORECASTS AFFECT
DECOUPLING REVENUES
Revenue GDP Forecast
per inflation revenue
customer
2004 024 020 027
2005 023 020 023
2006 023 021 021
2004 to 2006 071 061 073
BASE CASE ASSUMES IRP GROWTH
RATES FOR BILLING DETERMINANTS
three-year (2004-2006) effects
RPC
- Bills down 0.05%
- IPC revenues down $2.7 million
- Energy/demand charges down 0.
. Inflation
- Bills down 0.
- IPC revenues down $7.7 million
- Energy/demand charges down 1.
. Forecast growth
- No changes In bills or rates (by
definition)
BASE-CASE INFLATION EFFECTS
GREATER
'"
Recoupling Metric: Inflation Recoupling
VI ::J 13 iii~ ffi ~
~ (J:g -I- ~:;: -VI c( ,a:;: ~
:!: ~:;:
w): -C! C!
~ ffi J: Z -(J W?fI.
!!J6111s 0 Energy/Demand Charges
Total
,.~....
RATE CLASS
CONDUCTED TWO SETS OF
ANAL YSES
. Base case (IRP growth rates by class) comparison
across three recoupling mechanisms
. Effects of changes in individual growth rates on
recoupling amounts for each mechanism
BASE-CASE RPC EFFECTS DIFFER
ACROSS CLASSES
'"
VI ::J 13 iii ~ ffi ~ ~ (J:g -
I- C '"VI Z N -a~~
:!: ~:;:
W): -C! C!Z III:: -0c( WJ: Z -(J W?fI.
Recoupling Metric: Per-Customer Recoupling
86111s 0 Energy/Demand Charges
Total
RATE CLASS
'-",
RPC RESULTS VARY ACROSS
CLASSES
. Fixed costs per customer vary from $420 for Sch 7 to
$4,300 from Sch 24 and $206 300 for Sch 19
. Results, relative to base case, are symmetrical for
higher (lower) growth in customers, energy, or
demand
. Effects are additive for changes in multiple factors
. Effects differ in sign (as well as magnitude) among
classes
. Overall, effects are small, .:; 1% of 3-year bills
INFLATION RECOUPLING HAS
LARGER EFFECTS
. Again, results, relative to base case, are symmetrical
for higher (lower) growth in customers, energy, or
demand
. Effects are additive for changes in multiple factors
. Unlike RPC, results are same for class-specific and
aggregate decoupling
. Effects are similar across customer classes
. Although larger than RPC, effects are small
(e: 1% of bills over 3 years)
DECOUPLING WORKS AS INTENDED
FOR DSM PROGRAMS
. Tested slower growth in energy and demand (by
%/year for three years)
. IPC fixed-cost recovery increases (over 3 years) by
$16 million (0.9%) relative to no-decoupling case
- Larger programs run for longer times (with no rate
cases) yield larger losses for IPC
. % increase in rates ~ % increase in bills (next slide)
CONCLUSIONS
. Current rate-making collects substantial revenues to
cover fixed costs from variable kWh and kW charges
- Makes no sense
- Penalizes utility shareholders if customers use
energy more efficiently
. Decoupling breaks link between revenue and sales
removes utility disincentive to customer efficiency
. Decoupling has other effects; customer rates and bills
can vary with decoupling independent of DSM programs
- Effects likely to be small
FORECAST GROWTH RECOUPLING
RESULTS SIMILAR TO INFLATION
. Relative to base case, forecast recoupling results are
identical with inflation recoupling
. Again, overall effects small
- 3-year change in customer bills e: 1%
DECOUPLING WORKS AS INTENDED
FOR DSM PROGRAMS
Recoupling Metric: Load Growth Recouplingo!Ien .
:JrfJ 4
jjj ~
a: c(UJ :a::O()~30 C 0I- Z '"en c( 0a:o ~
:!:; ~ ~
UJ ;;:C) C)z a:c( UJ:a: z() UJ
1/1.
IjjBllls 0 EnergyfDemand Charges
RATE CLASS
Total
SUGGESTIONS TO COLLABORATIVE
. Develop independent model of decoupllng for IPC
- Select new recoupling mechanisms
- Use actual PUC-approved rate structures
. Search for metrics related to determinants of fixed
costs
- Meet environmental goal of decoupling
- Increase stability of utility earnings
. Consider decoupling for one or two rate classes (e.
g.,
Sch. 1 and 7)
. Review recent utility experiences with
- DSM programs
- Decoupling
Final
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES, WORKSHOP #2
SEPTEMBER 27 2004 9:30 A.M. TO 12:30 P.
IDAHO POWER CORPORATE HEADQUARTERS, BOISE, ID
Facilitation Susan Hayman, North Country Resources, Inc.
Documentation Natalie Chavez, Chavez Writing & Editing, Inc.
WORKSHOP OBJECTIVES
1) Develop operational protocols for the remaining workshops
2) Continue investigating the nature and extent of financial disincentives to energy conservation
programs (DSM)
3) Explore a potential decoupling mechanism to address DSM investment disincentives
WORKSHOP DECISIONS AND OUTCOMES
The next meeting will be held November 8, 2004, from 9:30am - 3:30pm at IPC. The morning will be
spent reviewing results of action items 1 through 3 (below), while the afternoon will be reserved for
discussing performance-based incentives.
ACTION ITEMS
1) Run a model of the following:
a) IRP-rate impacts by class
b) NWPCC-rate impacts by class
c) Estimate of savings from conservation (using Aurora)
2) Discuss development of a tool to poll customers about energy-
conservation/efficiency programs.
3) Recalculate numbers with an interim rate case but in the absence of a
true-up mechanism.
4) List ideas for possible performance-based incentives, and develop a
strawman" if an idea stands out.
5) Make requested changes to "Operational Protocol" and to "Definitions.
E-mail revised documents to participants.
WORKSHOP OPERATIONAL ISSUES
Randy Lobb, Ric
Gale, and Ralph
Cavanagh
David Hawk and
Ric Gale
Lynn Anderson
All
Susan Hayman
Susan Hayman welcomed participants (Appendix 1), had them introduce themselves, and then reviewed
the agenda (Appendix 2). Participants had no changes to the agenda. Hayman had compiled an
operational protocol for the series of workshops, based on conversations she had with participants. The
group reviewed and made the following revisions to (decisions about) the operational protocols for the
workshops (Appendix 3):
Workshop Purpose statement 1-add "and customers" to the end of the clause
Workshop Purpose statement 2-retain "performance-based ratemaking" since that language
appeared in the IPUC order (Order No. 29558, p. 2), but add "incentives" in parentheses following
that phrase
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Roles and Responsibilities statement ~t-designate coordinators: IPC-Mike Youngblood , IPUC-
Lynn Anderson , NWEC-Bill Eddie, and Industrial Customers-Peter Richardson
Analysis statement-replace the question with "Analysis needs will be identified and assigned as they
emerge.
Hayman also provided a definitions list for review (Appendix 4). Following are the revised definitions for
demand side management" and "true-up." Definitions for "performance-based incentives" and
decoupling" stood as worded.
Demand Side Management (DSM): Management tools and actions that are designed to result in
decreases or shifts in customer energy demand and/or consumption.
. True-Up: A decoupling mechanism where a periodic adjustment in electric rates is used to correct for
disparities between a utility s actual fixed-cost recovery and its authorized fixed-cost recovery.
NATURE & EXTENT OF FINANCIAL DISINCENTIVES
Hayman distributed questions raised in conversations with participants and grouped into categories
(Appendix 5). These questions could be revisited after today s discussions to see which had been
answered and which remained. Some could also be assigned for analysis, if appropriate. She also shared
a flowchart she had drawn on the whiteboard and asked if there was any dissension about the process.
Workshop participants accepted the flowchart.
Magnitude & location of
disincentive
(develop decision criteria)
Other Options
Recommendations
Fixed-Cost Revenue Loss Analyses
Prior to the workshop, Lynn Anderson, IPUC, had e-mailed participants a memo and Excel worksheet
(Appendix 6). He had calculated IPC's fixed-cost revenue losses under three 9-year scenarios that he
had developed to try to quantify the nature and extent of financial disincentives. These calculations are
gross estimates that are not adjusted for taxes, cost changes , offsetting benefits, etc. They also assume
~~ ~:~~I
~~~~g
;~~ ~~i
~~s :~r
~ ~~~:~
~:~~h
~~a~~~~~r~~t ~~ft
~ ~~:
~hgl
:~~;~~~:~~~~~~
7;~ldquestions.
Integrated Resource Plan Scenario
Under the IRP scenario, the fixed-cost revenue loss grows to about $1.3 million per year by 2013.
The 9-year total for all rate classes is about $6 million , with a net present value of about $4 million.
The residential 9-year total is about $2 million. These figures are based solely on energy charges, not
energy and demand charges. Adding fixed-cost revenue loss from demand savings would increase
the $6 million by about a third.
Summary of the September 2004, Workshop
Deleted: to zero
Assessing Financial Disincentives and Resolution Opporlunities Workshop
Northwest Energy Efficiency Alliance (NEEA) efforts were excluded from the scenario.
Northwest Power and Conservation Council Scenario
Under the NWPCC scenario, the fixed-cost revenue loss grows to about $23 million per year by 2013.
The 9-year total for all rate classes is about $114 million, with a net present value of about
$75 million. The residential 9-year total is about $51 million.
Results from this analysis are consistent with numbers that Ralph Cavanagh came up with. His
calculations show $45 million in fixed-cost revenue loss over the first five years, his number includes
demand charge losses as well as energy charge losses. Anderson arrived at $38 million using only
energy charge losses.
For the commercial class, the 10ss/MWh unsold jumped from $9.70 under the IRP scenario to $41.
under the NWPCC scenario. This class included both schedule 07 and 09 rate classes though. If the
analysis were fine-tuned, this discrepancy would need to be addressed.
IPC's share of 6.5% is based on sales. The potential is greater since IPC hasn t done much DSM in
the last several years.
How rate cases would affect the $114 million was uncertain. Intervening rate cases reset fixed-cost
revenue requirements but do not allow IPC to recover revenue losses incurred since the previous rate
case. Ric Gale said that an analysis of what would happen would be fairly simple to do.
Historical Residential Scenario
Under this scenario, only residential fixed-cost revenue losses are calculated. Using weather-
normalized kWh per customer consumption data, the hypothetical fixed-cost revenue loss grows to
$18 million in 2003, the 9th year following IPC's 1994 rate case.
The $18 million shown for 2003 is almost identical to what the IPUC will give IPC for the rate increase
for residential customers under the just-completed rate case, despite the scenario being an
oversimplification.
Average monthly per customer usage decreased by 143 kWh in the 9-year period. During this time
IPC had very little residential DSM; its participation in NEEA probably accounts for less that 5% of the
reduction. The reductions are mostly focused into two years (2001 and 2002) when there was also a
nationwide reduction in electricity consumption. There were also 40% PCA increases in those two
years. These electricity savings may have been offset by increased gas consumption.
Summary-Areas of Agreement
After the three scenarios were presented and discussed , participants listed their conclusions about the
magnitude of the problem and the location of disincentives. Below are issues that were raised during this
discussion:
IPC's historical lost revenues are a disincentive to something, but it's difficult to say thatthey are a
disincentive to energy efficiency since the lost revenues in the third scenario are not associated with
DSM.
If there is a relatively aggressive DSM program and it achieves energy-efficiency objectives, there is a
cost to the company. What remains unknown is how much it would cost to "fix" the problem and
whether that price is tolerable. In addition, it is important to understand what IPC would do differently
if the company recovered costs incurred through DSM.
Demand reduction" occurs with higher pricing. But higher pricing isn t the solution that people are
looking for. They would like to know how to separate demand reduction due to energy-efficiency
programs from that due to higher prices. Also, what are the impacts of different energy-efficiency
programs?
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
STRAWMAN" PROPOSAL FOR AN IDAHO POWER TRUE-UP MECHANISM
Ralph Cavanagh introduced a strawman proposal for a true-up mechanism (Appendix 8). A true-up
mechanism is "not about paying the company anything; it simply provides IPC a means for recovering
fixed costs." It is designed around an authorized fixed-cost revenue requirement.
Under his proposal, the starting point would be the fixed-cost revenue requirement and retail rates
approved by the IPUC in the latest IPC rate case. If, after the first year, changes in retail electricity use
lead to under- or overrecovery of the fixed-cost revenue requirement, then a rate true-up would occur in
the following year on the same schedule as IPC's current PCA. Until reestablished in the next IPC rate
case, the currently approved fixed-cost revenue requirement would be automatically adjusted annually to
reflect the same rate of increase or decrease shown for retail electricity sales , net of any DSM programs,
in IPC's latest IRP. True-ups would occur annually based on any divergence between the total fixed-cost
revenue recovery that forecast sales would have delivered and the fixed-cost revenues actually
recovered. The true-ups would be done for each customer class based on divergence between actual
and forecast sales to each customer class. IPC would continue to absorb the risk or benefits of purely
weather-related effects on fixed-cost revenue recovery, as it does now. Actual sales would be weather
normalized before the annual true-up calculation was made. Cavanagh emphasized that the maximum
annual anticipated rate impact of the true-up mechanism , up or down , under extreme conditions would be
5%.
Several issues were raised during the presentation and associated discussion (Appendix 9):
This mechanism does not include figuring out how much of the difference is attributable to different
factors.
Because the fixed-cost revenue requirement would track forecasted sales rather than historical sales,
IPC would not be paying extra if DSM programs were successful. Every year, the company would be
truing up to a number known in advance at the same schedule that is now used.
Although Cavanagh proposed truing up for every customer class (except special contracts because of
other complexities), the mechanism would work in part (for certain customer classes).
At one point, IPC classified DSM as a supply side investment: the money was capitalized and
amortized over a number of years. But the benefits didn t materialize for a number of reasons.
Basing the true-up mechanism on forecasted sales might motivate IPC to inflate its forecasted
numbers. Deterrents might include having the forecast adopted independently or using a different
index after the next general rate case.
To better understand the effects of DSM on fixed-cost revenue loss, people suggested rerunning the
scenarios and running the Aurora model, given some of the discussion points raised during the
workshop. The following action items resulted from this discussion and were assigned to Randy Lobb
Ric Gale , and Ralph Cavanagh to coordinate:
Rerun the IRP scenario with rate impacts by class
Rerun the NWPCC scenario with rate impacts by class
Use Aurora to estimate chanQes in power supply costs that may result from increased levels of
energy .c()n~ervatiol1 .
'Recalculate scenario numbers with an interim rate case (assigned to Lynn Anderson)
. A poll of customers' appetite for energy-efficiency programs might help in estimating potential savings
from conservation. David Hawk and Ric Gale will discuss the value and development of a poll.
NEXT STEPsIWRAP-
Hayman reviewed action items that need to be done before the next workshop. This workshop Was set for
November 8, 2004, from 9:30am - 3:30pm at IPC. The morning will be spent reviewing results of the
model runs and Anderson s scenarios with an interim rate case included. The afternoon will be reserved
for discussing performance-based incentives. Gale encouraged people to develop other strawmen if they
Summary of the September 2004, Workshop
' -
Deleted: savings from
Assessing Financial Disincentives and Resolution Opporlunities Workshop
have ideas. Cavanagh offered to circulate a proposal for a performance-based mechanism in advance of
the workshop.
During a quick workshop evaluation, participants asked that people who will be sharing information
distribute that information in advance so that people have a chance to review it.
ApPENDIX 1-PARTICIPANTS
Name and Affiliation
Peter Richardson, Industrial Customers of Idaho
Phone No.
Don Reading, Ben Johnson Associates
Mike Youngblood, Idaho Power
Maggie Brilz, Idaho Power
Greg Said, IPC
Lynn Anderson, IPUC
Brad Purdy, Self
Randy Lobb, IPUC
Bart Kline, Idaho Power
Ralph Cavanagh, Natural Resources Defense Council
I Darlene Nemnich, Idaho Power
Tim Tatum, Idaho Power
Laura Nelson, IPUC
Scott Woodbury, IPUC
David Schunke, IPUC
Bill Eddie, Advocates for the West
Ric Gale, Idaho Power
Terri Carlock, IPUC
David Hawk, J.R. Simplot Co.
E-mail Address
peter~richardsonandoleary. com
dreading~mudspring.com
myou ng blood~ i dahopower. com
mbrilz~idahopower.com
gsaid~idahopower.com
landers~puc.state. id. us
bm purdy~hotmail. com
rlobb~puc.state. id. us
bkline~idahopower.com
rcavanagh~nrdc.org
dnemnich~idahopower.com
ttatum~idahopower.com
Inelson~puc.state. id. us
swoodbu~puc.state.id. us
dschunk~puc.state.id.
billeddie~rmci. net
rgale~idahopower.com
tcarloc~puc.state. id. us
david.hawk~simplot.com
938- 7901
342-1700
388-2882
388-2848
388-2288
334-0353
384-1299
334-0350
388-2682
[phone]
388.2505
388-5515
334-0363
334-0320
334-0355
342- 7024 x 3
388-2887
334-0356
9- 7306
, .' - . '
D~i~t;t;..280-5...
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 2-AGENDA
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLU110N QpPORTUNIl1ES
WORKSHOP #2
September 27.2004
9:30am-12:30pm
Auditorium East
Idaho Power Corporate Headquarters
Boise. Idaho
Objectives:
1) Develop operational protocols, objectives and outcomes for this effort;
2) Continue investigating the nature and extent of financial disincentives to energy conservation
programs (DSM);
3) Explore a potential decoupling mechanism to address financial disincentives.
Draft Agenda
TIme Topic Process
9:00am CoffeelTea available in meeting room
9:30am Welcome/Introductions/Meeting Overview - Susan Hayman Information
Facilitator
9:40am Workshop Operational Issues - Susan Hayman Information/Discussion
Workshop series purpose and products (in~1. terminology)
Participant roles & responsibilities
Decision-making
Documentation
---.---
1 0:20am Nature & Extent of Financial Disincentives Presentation
Fixed-Cost Revenue Loss Analyses - Lynn Anderson Discussion
- important Omissions, Caveats and Disclaimers
- DSM-caused losses under IRP projection
- DSM-caused losses under NWPCC draft DSM projection
- Residential historical deciining kWh per customer
Areas of agreement on the current situation
11 :20am BREAK
11 :30am Strawman" Proposal for an Idaho Power True-Up Mechanism Presentation
- Ralph Cavanagh Discussion
...----.----
12:1 Opm Wrap-Up - Susan Hayman Discussion
Workshop schedule
Agenda items for next workshop - Susan Hayman
Evaluation
12:30pm Adjourn
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 3-0PERA TIONAL PROTOCOLS
Workshop Series - Operational Protocol
Workshop Name: Assessing Financial Disincentives and Resolution Opportunities
Workshop Purpose:
1) To investigate the nature and extent offinancial disincentives to investment in energy efficiency
by Idaho Power Company and cu::.tomers;
2) To investigate decoupling and pelformance-based ratemaking (incentives)as mechanisms to
address financial disincentives (IPUC Order # 29558 8/10/2004). Other mechanisms can be
subsequently explored if the participants agree thai this would be useful.
Workshop Products: A written report to the Idaho Public Utilities Commission to update the
Commission on the status of the investigative workshops. This report will include a summarized
assessment of:
1) The nature and extent of financial disincentives to investment in energy efficiency by Idaho
Power Company;
2) Recommendations regarding specific decoupling and/or pelformance-based mechanisms that may
reduce/remove these financial disincentives.
3) Recommendations for next steps.
Workshop Tenure: August 24 through December 15, 2004
1) Composition of Workshop Participants
While workshops will be open to the public, it is expected that participants will generally represent
the Idaho Public Utilities Commission, Idaho Power Company. Northwest Energy Coalition
representatives of industrial customers, representatives of residential customers, and representatives
of irrigation customers.
2) Roles & Responsibilities of Workshop Participants
a) Be active in the discussion, be solutions-oriented, and act in "good-faith.
b) Help others at the table to understand your interests, and actively seek to understand the interests
of others.
c) Be informed - Review the previous workshop summary, the agenda and prework in advance of
the next workshop.
d) Follow-through in a timely manner with any assigned action items.
e) Attend workshops regularly - the group will not revisit decisions/discussions missed by others.
f) Workshop Coordinators: One representative each from Idaho Power Company G'vlike
Youngblood),Idaho Public Utility Commission (Lvnn Anderson),aH4-NorthwestEnergy
Coalition (Bill Eddie). and industrial customers (Peter Richardson").Responsibilities include
coordination with the facilitator on the workshop obj ectives, outcomes, agenda and process.
3) Role & Responsibilities of the Facilitator
a) Manage the workshops, serve as a process coach, maintain neutrality and impartiality, and
reinforce the collaborative process.
b) Refine the objectives and outcomes for each workshop, in cooperation with the workshop
coordinators. Propose a workshop agenda. and appropriate processes to reach the identified
Page 1 of! - Operational Protocol
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
obj ectives and outcomes, and finalize this with the coordinators. The agenda, and any prework
materials, will be distributed to participants at least one week prior to each workshop.
c) Communicate with participants outside of workshops as needed.
d) Maintain a record of workshop participants, and a summary ofwork&1op discussions (see #6
Record Keeping).
e) Assist in preparation/compilation of the written report to the Idaho Public Utilities ColIUT\ission.
4) Analysis
W!m f,8i1tg 181'Jf'('j~.Ue ttJial)."Ii.v .vttpp61 liel t,~i,v umjr.y!jop (.')('JLJ()('.t d.'tt,1, di:~'dep and IfHlai)re
5l.CII5H'iSj, BId ~ Analvsis needs will be identified and a..";signed as they emerge.
5) Decision-Making
a) Entities with multiple representatives: While each individual participant will have input into
the workshop deliberations, it is desirable that each entity represented speak with one voice in
decision-making. Therefore, while numerous individuals may represent a given entity at a
workshop, it is expected that one person will speak on behalf of the entity when decisions are
made. Earn entity should designate that person in advance. The facilitator will provide time for
representatives to consult with each other as needed prior to critical decisions.
b) Types of decisions: There are two types of decisions participants will make:
)-
Workshop decisions: These decisions are related to workshop topics, process and
srnedule. Workshop decisions already made by the IPUC in Orders 29505 and 29558
will be honored. Decisions at the discretion of the group will be made by consensus.
)-
Product decisions: These decisions are related to the findings and recommendations
workshop participants will present in their written report to the IPUC on December 15,
2004. Consensus will be the goal- However. if consensus cannot be reached, areas of
agreement and disagreement on the findings and recommendations will be provided in thewritten report.
6) Record-Keeping
a) The facilitator will arrange for notes to be taken on a laptop computer during the workshop. The
distributed workshop will include key discussion points, decisions, areas of agreement and
disagreement, action items, etc. They will not be a transcription of "who said what"
b) The facilitator wi II be responsible for preparing the workshop summary and distributing it to
participants within three business days after each workshop.
c) The facilitator will maintain a file of all workshop sulIUT\aries, handouts, and products.
7) Principles of Meeting Conduct
a) Focus attention on the speaker (no side conversations)
b) Be specific, but succinct. in questions and colIUT\ents
c) Participate fully, but don't dominate the discussion.
d) Respect others contributions. and learn from them.
e) C1Jallenge ideas, not people
f) Be on time
g) Turn cell phones. pagers or other electronic devices off or inaudible during meetings.
Page 2 of2 - Operational Protocol
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 4-DEFINITIONS (WITH REVISIONS)
Definitions
Demund Side M~magcmcnt (DSM): Management tools
and actions !lmt are designed to result in decreases or shifts in
customer energv demand and/or eol1suITIPt!onAfl-yHti-ng that II
utility doer; thatnffeet:; eu.;lomer energy demond. eon:;umption
Alurar time of U:;13
Pcrt..rmancc-Buscd InccntiYcs (PHI): Mechanisms that
allow a utility to share and retain benefits gained from energy
efficiencies. as well as provide consequences for failing to meet
elliciency goals.
Dccou))ling: Severing the link between a utility s kWh sales
and its recovery of revenues to cover fixed costs.
True--UI): A decoupling mechanism where a periodic
adjustment in electric rates is used to correct for disparities
between a utility s actual tixed cost reco','oriesrecoverv
.,.
and its
authorized fixed-cost rccovervrate of return
Summary of the September 2004, Workshop
Final
ApPENDIX 5-QUESTIONS RAISED IN PARTICIPANT CONVERSATIONS
Questions ~aised in Participant Conversa~
Financial Disincentives
\x/hat effects do disincentives have on customers and on IPC?
Vv'hat is the projected loss ofrevenue to IPCa ITom DSM programs over the next lOyears?
0 What are the NWPC projections of demand over the next 10 years (relevant to IPCa)?
0 What would the removal of disincentives accomplish for customers and IPCO?
Should IPCO be "made whole" when they encourage customers to use less of their products
it mean to be "made whole
Vv'hat should be the basis for reimbursement of lost kWh and out-of-pocket cost to support 0
0 If disincentives were not in place, could IPca invest more in DSM?
0 Are there disincentives to DSM other than fmancial?
DSM Programs
n What effect doe!'; nSM have on re!';ource acqui!';ition?
0 If customers ultimately have to pay more (to decouple fixed costs from variable energy use),
programs will be created?
Should there be consequences for not investing in DSM?
Iffunds are invested to support DSM programs...
-- How will these funds be administered?
-- How will the efficacy of adm inistration be measured/monitored?
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Questions Raised ~ciDant Conversations (cont'
Decoupling and/or Performance-Based Mechanisms
\N11at effects would decoupling have on customers and on IPCO?
0 If de coupling would have been in place during the last 10 years, what would have been the
customers and IPCa (state assumptions)
0 If decoupling were adopted at IPCa, what would be the options for structuring (rate classes
system-wide, apply to energy charges or both energy and demand charges, etc.
\N11at are the side effects to decoupling?
\N11at effects would perfoffi1ance based mechanisms have on customers and on IPCO?
\N11at ate the side effects to perfoffi1ance-based incentives?
0 What criteria will we use to evaluate decoupling and perfoffi1ance-based mechanisms?
Other Mechanisms
0 Are there more appropriate mechanisms than decoupling and/or perfoffi1ance-based mechaI
IPCO financial disincentives?
Summary of the September 2004, Workshop
Final
ApPENDIX 6-FIXED-COST REVENUE Loss ANALYSES
End ollRP
Planning Period
IPC DSM F-C Revenue Loss -IRP
Only DSM Selected in the 2004 IRP (2004-2013 Planning Period)
Idaho Power IPC.04-018, IRP Technical Appendix
Energy Savings (Excluding NEEA)
Net of Free Riders. Includes Losses
Enerav Savinas (Meaawatt-hours)
Residential Commercial Irrioation Industrial070 389 5 767 9.421
625 1 087 11 534 18 853
193 1 900 17 300 28 280784 2 810 23 067 37,706
397 3 801 28 834 47 133
205 4 861 34 601 56 559028 5 980 40 368 65 986872 7 149 46 134 75 412
734 8 359 51 901 84 839
aMW (2004 IRPI=
259506 424 195
Year
2005
2006
2007
2008
2009
2010
2011
2012
2013
Total MWh
653
34 ,100
674
367
166
105 226
123 363
141 566
159 833
18.25
788 946Total908337
Calculation of Fixed Cost Lost Revenue er MWh for Various Rate Schedules
Residential Commercial' Irri alion IndustrialU
Energy Rate ($/MWh) 51.9 30.0 32.21.8
Vmiable Cost ($/MWI)\.2.Q.l 2Q.J m .1!Lf!
Loss/MWh unsold $31.20 $9.70 $-9.10 $3.
n Commercial rate is a weighted avg. of schedules 07 & 09S based on energy lIse.
.. Ind. rate is a we htd. ay . of ScilS. 09 P & T and 19 S, P & T based on ener use.
(Numbers by IPC 9/21/04)
Peak Reduction (MW)
Res. Com. Irrio..l.!:!..Q.. Total01 2.1.2 4.0.4 5.2.4 10.0.1 8.7 3.15.43.4 1.1 11.5 4.8 20,
1.5 14.4 6,26.23 1.9 17.72 31.3 2.4 20.2 8.37.228 231 9.6 42.3 3.3 26.0 10.483
8.3 3.3 260 10.8 48.
PeaK MW (Energy Progratl1s) 48.
Pel;JK MW (Demand Response) 75,
Total Peak MW Selec\ed DSM 123.
~Jote Ihalthe $IMWH I-~re
arB diil for cc'n1. & Indus!.
. than on NW PeG sheet
End of IRP
Planning Period
Total
WACC = 7.20%
PV 9-yr. (2005-2013)
Avg Annual
Levelized (9-yr.
Year
2005
2006
2007
2008
2009
2010
2011
2012
2013
Fixed Costs Not Recovered Due to DSM Selected in IRP
Residential Commercial Irriaation Industrial Total
$33 370 $3)7L) $52,480 $31 109 $120.134
905 10 548 104 959 62 215 259 627
130 837 18.432 157.430 93 324 400,023
180,467 27 256 209 910 124 430 542 063
230,799 36 871 262 389 155 539 685 599
287 187 47 156 314 869 186 645 835 857
344 084 58 008 367 349 217 754 987 194
401 601 69 341 419 819 248 860 1 139 621
459 689 81 082 472 299 279 969 1 293 038
The fixed-costs not
recoverd at left are the
product of multiplying
each year s energy
savings (excluding NEEA)
in the top box by the
10ss/MWh unsold in the
middle box (IPC adj. of
Eric Hirst numbers). The
losses. are not adjusted
for income taxes, cost
changes. offsetting
benefits, etc. All losses
assume no rate cases
2005-2013.
$2.149 939 $352,469 361 505 $1 399.844 $6,263,756
434 141 $ 232 128 593 395 $ 944 526 $ 4 204 190
429 988 70,494 472 301 279 969 252 751
214.415 34,705 238 224 141 214 628 557
Summary of the September 2004, Workshop
Final
NWPCC Draft 5th Plan -- Not Reviewed By Council IPC DSM F.C Revenue Loss - NWPCC
Achievable Cost-EffecUve DSM PotenUal bv 2025
IPC's 2G-yr.IPC'lPG's
Potential DSM in NW aMW (Q)annual amual Idaho Powers Fixed-Cost Revenue Losses ($millions)
2005-2025 Total aMW 6.500;.aMW MWh 2005 2.QOO.2QQI 2.Qill!2.QQ2 2011 2Q1l 2Qj
Res. Refrigerators
Res. Clothes Washers 135
Res. Dishwashers
Res. Water Heaters
Res. H.P. Water Heaters 195
Res. H.W. Hea. Recovery
Res. Compact Fiourescent 535
Res. New Space Condo
Res. Existing Space CorKl.
Res. HVAC Upgrades
Res. HVAC Conversion
Res. HVAC Commission
IRes. Total 44.801.270 82.157 10.
Com. Equipment. new/ie pl.
Com. HVAC. new/repl.150
Com. Infrastructure. new/rep!.
Com. Lighting. new/lepL 245
Com. Shell, new/lepL
Com. Equipment. retrofit 110
Com. HVAC. retrofit 120
Com. Infrastructure. retrofit 110
Com. Lighting. retrofit 115
Com. Shell, retrofit
ACiDC ower oonv.155
Com. Total 40.135 73.8 32.313 5.4 10.12.
Irrig. All Agricultule
IIrrig. Total 801.278
Ind.All Non-Aluminum 350
Iind. Total 12.350 22.1.14 965
Totai 100.835 184.712 10.12.7 152 17.20.22.
2005 2006 2007 2008 2009 2010 2011 2012 201
Cumulative Total $2.$7.$15.$25.4 $38.1 $53.$71.$91.4 $114.
Energy Charge
Variable Cost
LosslMWh lUlsold
$/MWh From IPC's 3/30104 Eric Hirst DecouDlina ReDort D. 5 -- IPC Uodated
Res. Com. -J.illl. Imust. -all 9 & 19 sch. (wi. avq.
51.90 62.60 32.60 24.40 Note that the $lMWH here
.2Q.lQ .21.1Q. ll.2!!. are dill. for com. & indusl
$31.20 $41.50 $9.10 $4.90 thanonIRP-selectedsheet.
Idaho Powers 6.5% share is based I
its curren! NEEA allocation, which may
represent its potential for each program
customer class.
All revenue losses assume no interv
rate cases am no customer glDwth.
Summary of the September 2004, Workshop
Final
Idaho Power-Idaho Only Sales and Customers
Residential Only
Weather
Residential Normalized
Year Revenue MWh Sold Customers
1987 $129,436 545 217 104
1988 140,569,164 219,005
1989 155 211 941 221 617
1990 153 080 652 226 323
1991 162 388 156 231 347
1992 158 306 311 237 837
1993 173 124 151 524 040 246 278
1994 174 880 654 589 867 255 735
IPC DSM F-C Reverue Loss - Historical
Hypothetical
Weather Fixed-Cost
Norm. kWh RevenueCust./mo. Loss
192
1170
1995
1996
1997
1998
1999
2000
2001
2002
2003
184 321 208
191 716 079
190,655,639
201,626 186
203 972 260
215 560,768
250 774 139
296 274 337
266,499 664
717 787
776 360
864,922
987 589
076 279
160,997
142 665
100,268
141 393
264 901 1170 23 324
273 834 1 149 2 108 207
282,054 1 142 2,945,197
290 532 1 144 2 831,082
300 072 1 132 4 242 165
309,499 1,120 5 727 683
318 076 1 085 10 056 112
326 788 1 046 15 194,468
336 204 1 ,027 18 035 272
year total= $61 163 509
Post 1994 "Hypothetical Fixed-Cost Revenue Loss" calculation uses 1 170 kWh per month as the
residential weather nonnalized consumption base.
The average consumption decrease of 143 kWh from 1 170 in 1994 to 1 027 in 2003 represents a
1.4% average annual decrease. Idaho Power had very little residential DSM during this time period. It is
likely that increased natural gas penetration is responsible for most of the decreased electricity use.
The calculation uses $31.20 as the residential "loss/MWh unsold" (I PC's update to Hirsrs number)
and assumes the fixed-cost lost revenue recovery fonnula would have compensated IPC for all weather
normalized declining kWh sales per customer.
1994
1995
1996
1997
1998
1999.
2000
2001
Total Retail Sales All ClassesRevenue MWh Customers
434 690 290 11 622,194 306 881
438,527,438 11,395,255 317,760
458 675,200 12,410 881 328 676
454,141 771 12 594 311 339,022
488 226 974 12 720,471 349 339
489 565 724 13 077 842 360,021
537 735 312 13 895,478 370 101
624,448 755 12 391 914 380 593
Energy Charge
Variable Cost
Loss/MWh unsold
$/MWh From IPC's 3/30/04 Eric Hirst Decouplina Report. P. 5 -- IPC UpdatedRes. Com. -.!r!:i.9.. Indust. -all 9 & 19 sch. (wt. ava.
51.90 62.60 32.60 24.40 Note that the $/MWH here
20.70 21.10 23.50 19.arediff.forcom.&indust.
$31.20 $41.50 $9.10 $4.90 than on IRP-selected sheet.
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Actual Actual
yr.yr. Avg. 3-yr. Avg.
Avg.Revenue Actual kWh/cust. kWh/cust.
Year Bill per kWh Kwh sold er month er month
198T 49.0432 995 218 168 150
1988 53.49 0446 148 903 043 198
1989 58.0469 306,433 702 243 197
1990 56.0474 230 831 759 190 210
1991 58.49 0473 3,430,432 527 236 223
1992 55.47 0481 289 387 264 153 193
1993 58.0483 582 828 720 212 200
1994 56.0484 610 314 912 1.,176 180
yr. Average, 1987 to 1994 =195
1995 57.0518 556,816,130 119 169
1996 58.0508 775,150,065 149 148
1997 56.0496 843 356 042 136 134
1998 57.0518 891 822,308 116 134
1999 56.0510 997,632,389 110 121
2000 58.0515 189 182 972 128 118
2001 65.0609 117 127 872 079 106
2002 75.0706 197,803 194 070 092
2003 66.0629 238 675 325 051 067
ApPENDIX 7 -FLIP CHARTS REGARDING ANALYSES
Weather Norm.
kWh Sold
524 040,421
589 867,417
717 787 134
776,360,493
864 921 749
987 588.792
076 279 049
160 997 320
142 664 831
100,268,216
141 393,426
Financial Disincentives
(Lynn Anderson s Presentation)
1) Add in lost demand charge to calculating of total
financial loss (IRP scenario)
2) $6 million loss in revenue under I RP DSM
projections. IRP-no tax impact if company made
whole
3) Lynn s projections do not include savings from
NEEA
4) $114 million loss in revenue under NWPCC
scenario.
Financial Disincentives (cont.)
5) 6.5% kWh sold in NWPCC attributed to IPC6) Intervening rate cases reset fixed-cost
requirements, but do not allow IPCO to recover
lost $$ since previous rate case. 7) (hist) NEEA effects c:: 5% customer use-has
occurred without utility DSM programs.
8) Over 9-year period, utility had no active residential
DSM program.
Conclusions-Financial Disincentives
1) IPCo historical lost revenues is a disincentive to
something. Historically, not tied to D~M.2) If there is a relatively aggressively DSM program
and achieves objectives, there is a cost to
company.
3) "Demand destruction" occurs with higher pricing.4) Lost revenues occur with successful DSM
programs
is it a disincentive
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 8-STRAWMAN" PROPOSAL FOR AN IDAHO POWER TRUE-UP MECHANISM
STRAWMAN"PROPOSAL FOR AN IDAHO POWER TRUE-UP MECHANISM
Submitted by Ralph Cavanagh, NRDC (9/22/04)
1. Starting point: fixed-cost revenue requirement and retail rates approved by Idaho
PUC in latest Idaho Power rate case.
2. If, after initial year, changes in retail electhcity use lead to under- or over-
recovery of fixed cost revenue requirement, a rate true-up would occur in the
following year on the same schedule as the Company s current Power CostAdjustrrent.
3. Until reestablished in the next Idaho Power rate case, the currently approved fixed
cost revenue requirement would be automatically adjusted annually to reflect the
same rate of increase (or decrease) shown for retail electricity sales, net of any
DSM programs, in Idaho Power s latest IRP. True ups would occur annually
based on any divergence between the total fixed-cost revenue recovery that
forecast sales would have delivered and the fixed-cost revenues actually
recovered (so if, for example, sales were forecasted to increased by 2 percent and
actually increased by a larger percentage, Idaho Power would refund the
difference at the time of the next Power Cost Adjustment; if retail sales increased
by a smaller percentage than forecast, Idaho Power would get back the lost
revenues at the time of the next Power Cost Adjustment).
4. True-ups would occur by custorrer class based on divergence between actual and
forecast sales to each custorrer class.
5. Idaho Power would continue to absorb the risk or benefits of purely weather-
related effects on fixed-cost revenue recovery, as it does now. This would rrean
weather nonmlizing actual sales before making the annual true-up calculation.
MAXIMUM ANNUAL ANTICIPATED RATE IMPACT OF THE TRUE UP
MECHANISM, UP OR DOWN, UNDER EXTREME CONDITIONS = 1.5 PERCENT.
ApPENDIX 9-FLIP CHARTS REGARDING STRAWMAN PROPOSAL
Strawman Proposal
1) True-up by each customer class
2) Mechanism could be applied to individual/selected
classes and still be acceptable
3) Remove special contracts from mechanism.
4) *Plea to not exclude industrial class5) Predicted load growth in each class to establish
authorized revenue requirement.
Strawman Proposal (cont.)
6) True-up would result in surcharges/benefits by
rate class
7) Forecast of fixed-costs may, potentially, create an
incentive to inflate the forecast in the future.
8) Because this rate case is already decided, fixed-
cost projections would be established without
consideration of true-up mechanism effect
May be a challenge in the future
May apply inflation factor in future
Summary of the September 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES, WORKSHOP
NOVEMBER 8,2004 9:30 A.M. TO 3:30 P.
AUDITORIUM EAST, IDAHO POWER CORPORATE HEADQUARTERS, BOISE, ID
Facilitation Susan Hayman, North Country Resources, Inc.
Documentation Natalie Chavez, Chavez Writing & Editing, Inc.
WORKSHOP OBJECTIVES
1) Continue investigating the nature and extent of financial disincentives to energy conservation
programs; identify areas of agreement and any additional information needs.
2) Identify criteria that workshop participants would use to evaluate the applicability/desirability of
potential mechanisms to address disincentives.
3) Brainstorm potential mechanisms to address disincentives, including additional true-up mechanisms
performance-based incentives, etc.
WORKSHOP DECISIONS AND OUTCOMES
The next meeting is scheduled for December 1 , 9:30am to 3:30pm at IPC. An additional meeting is set for
December 13. If people with action items are unable to complete them in time for the December
meeting to be productive, that meeting will be cancelled and all parties notified by Susan Hayman
facilitator.
ACTION ITEMS
When?What?
1) Check with Commission regarding scope of performance-
based incentive discussion (is it DSM-related only?) and
provide response to the workshop participants
2) Talk with Bill Eddie about report coordination; reply to
Hayman
3) E-mail proposed report coordination assignments to the
workshop participants
4) Coordinate timing of status report
5) Develop PBR strawman suitable for Idaho and successfully
demonstrated elsewhere
6) Refine true-up mechanism
7) Analyze the refined true-up strawman and PBR strawman
Who?
Randy ASAP
Nancy November 9
Susan In next few days
Susan Next meeting or e-mail
IPUC Next meeting
Ralph Next meeting
IPC Deferred
, With the approval of workshop participants, Workshop Objectives 2 and 3 were deferred to the December 1 workshop to allow for
more extensive presentation and discussion of financial disincentives information at this workshop.
Summary of the November 8, 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
WORKSHOP INTRODUCTION
Susan Hayman, North Country Resources, welcomed participants (Appendix 1), had them introduce
themselves, and then reviewed the agenda (Appendix 2). She distributed revised copies of the
operational protocols (Appendix 3) and reviewed posters showing purpose, products , definitions , and
principles of meeting conduct (Appendix 4). Although three key participants representing the NWEC
perspective were absene, the group decided to listen to planned presentations, discuss the information
and represent the NWEC perspectives as best they could , but not draw any conclusions until the others
were present.
CONTINUED EXPLORATION OF FINANCIAL DISINCENTIVES
Scenarios with Interim Rate Cases
Before the workshop, Lynn Anderson, IPUC e-mailed participants a memo and two Excel worksheets
(Appendices 5 and 6). He had incorporated three interim rate cases to recalculate IPC's fixed-cost
revenue losses under two of the three 9-year scenarios that he had presented at the September 27
workshop. Under both scenarios, forward-looking revenue losses from past DSM efforts are eliminated
(except for an assumed six-month lag between the end of the rate case test year and rate
implementation), even though past DSM savings are assumed to persist into the future. DSM efforts that
occur after each rate case test year result in new fixed-cost revenue losses that accrue until the next rate
case. As a surrogate for rate case adjustments, the levels of fixed-cost revenues per MWh are increased
by the average MWh growth rate projected in the IRP for each rate class.
Anderson first showed results of his recalculations of the IRP level of DSM (which excludes NEEA). The
IRP rate-case adjusted, 9-year total fixed-cost revenue loss is $3 million, or about half of the $6.2 million
presented previously. The present value of the $3 million is about $2 million, and the levelized loss is
$0.3 million per year.
Next, he showed results under IPC's 6.5% share of the NWPCC level of DSM (which includes NEEA, fuel
conversions, building codes, appliance standards, and other DSM for which utilities have limited , little, or
no control). The NWPCC rate-case adjusted, 9-year total fixed cost revenue loss is $54.6 million
compared with the $114.2 million presented previously. The present value of the $54.6 million is about
$39 million, and the levelized loss is $6 million per year.
Prior to the meeting, Cavanagh e-mailed a response to Anderson s recalculations (Appendix 7). Copies
were made and distributed to those who had not received the e-mail. First, Cavanagh reminded people
that NWPCC projections were not the upper limits of energy efficiency targets. Second, he disagreed with
Anderson s elimination of continued revenue losses after a rate case. According to Cavanagh , using this
approach understates IPC's losses from persistent savings and rewards short-lived efficiency measures
while discouraging durable savings.
Following the presentation, participants raised and discussed the following issues:
IPC loses fixed cost revenues when consumption declines. It is still uncertain how much reduced
consumption is due specifically to DSM rather than to other factors. Therefore, some participants
aren t certain whether this situation is best resolved by a true-up mechanism or some other
disincentive/incentive mechanism.
. A decoupling/recoupling or true-up mechanism is not an incentive but a removal of a disincentive.
More frequent rate cases would reduce fixed cost lost revenue even more than the hypothetical 3-
year interval rate cases included in this analysis.
Fixed cost revenues may be over-collected in the case where kWh sales, less DSM savings, are
greater than the forecasted kWh growth, resulting in a refund for the customers under this true-up
2 Ralph Cavanagh (Natural Resources Defense Council), Bill Eddie (Advocates for the West), and Nancy Hirsh (NW Energy
Coalition) were absent at the beginning of the meeting. Their absence left no representatives of the NWEC stakeholder group. Hirsh
arrived before lunch break, and Cavanagh participated via conference call in the afternoon. Eddie was unable to participate at all.
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
mechanism. At the same time, increased kWh sales will usually mean an increase in customer
growth, which may require IPC to spend money for a new distribution plant and equipment. IPC is
concerned about the possible scenario where they are giving a refund to customers at the same time
as expending dollars in capital investment.
What level of fixed costs, if recovered, would encourage or allow IPC to do what it wouldn t do
otherwise with DSM or other programs?
Greg Said, IPC, illustrated what happens between rate cases (see below) in the absence of a true-up
mechanism. Lost fixed cost revenues from DSM could accumulate over a 1 a-year period unless a
rate case adjusts the rates up to recover the lost fixed costs. This adjustment ~ould change the angle
of the lost revenue line down (in blue) so that future fixed cost losses are accelerated. For the sake of
illustration, Said assumed a straight-line reduction, although it would likely be curved (in red).
Anderson said that the surrogate for the blue dotted line was captured in his analysis.
Is lost and unrecoverable
, $129 million
I Rate case
............................................"""""""""""'..... ,
Would have been lost but is now recovered
Possible curve (assuming no straight-line
relationship)
Year Shifted lost revenue curve after rate case
Rate Impacts by Class under IRP and NWPCC Projections
Mike Youngblood, IPC, distributed a 1 a-page packet with rate impacts under the true-up mechanism for
both IRP and NWPCC energy efficiency projections (Appendix 8) and a single sheet regarding fixed cost
lost revenue per MWh by customer class (Appendix 9) prepared by Tim Tatum , IPC. Under this model
the true-up mechanism is based on forecasted sales as the method for (PC to recover fixed costs.
Youngblood showed the assumptions he could change to analyze various scenarios.
Using the residential rate class, he walked participants through the model, which also included high- and
low-growth scenarios to illustrate a range around the base case. The following issues were raised during
the discussion (see Appendix 1 a for flip chart notes):
If energy sales grow faster than forecasted and DSM equals growth, there will be no apparent
divergence from the base case.
Although this model is not based on customer counts, increased kWh growth likely means increased
customer growth. If so, IPC has to make capital investments for new customers. Youngblood
commented that his numbers reflect divergence from an assumed 2% growth rate. Hypothetically, an
increase in kWh use and an increase in the number of customers may result in a refund to customers
and the requirement for IPC to add facility investment.
For DSM , the percentage of class increase is still relatively small on an annual basis in the short term.
Regular rate cases would adjust recovery so that the long-term effect wouldn t be as high asmodeled.
Trends of true-up are similar among rate classes.
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Youngblood then presented a similar model of the true-up mechanism based on customer counts rather
than forecasted sales. Youngblood did not provide this dynamic model as a handout but demonstrated it
to the group. Appendix 11 includes one scenario based on certain input assumptions. For this analysis
he used weather-adjusted numbers , $30.14 as the total fixed cost per MWh, and 12 549 kWh to represent
the average consumption for a residential user. The high and low scenarios represent 1 % increase above
and decrease below that average use per customer. Again, people could chose from among a number of
assumptions to see their effects. Trends were similar to those under the forecasted sales true-up
mechanism although magnitudes changed. The impact over a 20-year period, all else being equal, is a
slight increase to rates, which is consistent with recovery of lost fixed revenues. Youngblood commented
that the customer count mechanism works better with residential and small commercial customers, while
the forecasted sales approach works better for industrial and irrigation customers.
Power Supply Costs under Increased Energy Conservation
Tim Tatum, IPC, distributed a four-page handout (Appendix 12) with results from the Aurora model
conducted to analyze impacts of increasing levels of DSM on power supply costs. Mike Rufo of Quantum
Consulting provided IPC an assessment of residential and commercial DSM potential within the
Company s service territory by 2013. For the analysis, Portfolio 11 from the Company s 2004 IRP was
modified to include Quantum Consulting s estimates of achievable DSM. The original Portfolio 11 was
then used as the base case in the analysis. Tatum pointed out that Northwest Power and Conservation
Council (NWPCC) estimates of achievable DSM are higher because they include market transformation
tax credits, and other mechanisms necessary to achieve those numbers. The IRP only accounts for direct
acquisition program savings and does not include savings attributable to the Northwest Energy Efficiency
Alliance (NEEA). When the 2004 IRP DSM resources are combined with Quantum Consulting
assessment findings and IPC's share of NEEA market transformation savings, the total is greater than
NWPCC estimates of achievable DSM for IPC.
IPC decided to include the higher level of DSM (excluding NEEA) into a modified portfolio to allow them to
analyze impacts to energy and capacity constraints (see Appendix 13 for flip chart notes). The first sheet
of the handout (Appendix 12) shows the higher level of DSM, which allows IPC to defer resources (shown
in orange blocks). The deferral of these resources results in an increase in variable supply costs due to
decreased market sales potential. However, the fixed cost benefit of the deferral results in net savings.
The second sheet shows the impact to power supply costs, excluding fixed costs. Factoring in DSM
savings, power supply costs are reduced in all years except 2007, which is when the first Combined Heat
and Power (CHP) resource is deferred. The third sheet shows portfolio fixed costs comparisons, with and
without DSM fixed costs, between the base case and increased DSM portfolios. In the two years with
CHP deferrals (2007 and 2010), there is a net decrease in fixed costs. The yellow columns show the
costs to achieve DSM. Results showing the impacts of increasing levels of DSM on power supply costs
are included on the last page. By increasing levels of DSM and organizing the portfolio for deferrals, the
net present value between the two portfolios from now through 2033 is $36.3 million. This analysis
indicates conservation has occurred and IPC will spend $36 million less in resources as a result. Extra
costs would be incurred to the system for the first several years, and the break-even point would occur in
2022. The analysis showed that increased DSM could reduce power supply costs in the long run, but the
disincentive needs to be removed early on.
COMMISSION REPORT
The participants expressed concern that there is not enough time before the December 15 deadline given
in the IPUC order to complete the investigation of the issues and draft a complete report. They decided to
submit a status report instead, which IPUC staffsaid will be sufficient as long as it describes the group
progress and anticipated due date for the completed report. Responsibility for drafting the status report
will be assigned at the next meeting.
Nancy Hirsh will talk with Bill Eddie about serving as report coordinator. Once written and compiled, drafts
will be circulated to all participants, though suggested revisions from participants should be coordinated
by each party (ICIP, IPC, IPUC, NWEC) before being sent back to the report coordinator. In the
meantime, work group members brainstormed the following outline for the report:
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
I. History-events leading up to the order and the parties involved in the work group.
The IPUC volunteered to write this section
II. What the work group did-issues raised, studies performed, mechanisms explored, assumptions
made, and possible solutions detailed.
The outline should allow means for showing the areas of agreement as well as areas of
disagreement.
III. Conclusions and recommendations-conclusions drawn from the studies.
This would reflect study information and perhaps respond to the four material questions discussed at
this workshop (see Appendix 15).
IV. Ancillary information-figures, tables , study details, workshop summaries , and any other
attachments needed to clarify or substantiate information.
After developing the draft outline (see Appendix 14 for flip chart notes), participants raised the need to
include information about performance-based ratemaking (PBR) alternatives. The order had charged the
work group with looking at alternatives to promoting DSM, one being decoupling and another being PBR.
IPUC staff volunteered to develop a PBR strawman that is centered on DSM for the next meeting. If there
is time to deliver the strawman to IPC for analysis before the December 1 meeting, the IPUC will do so.
Otherwise, analysis will be conducted before the December 13 meeting.
QUESTIONS RAISED
The following questions were developed before or during the workshop and discussed once Cavanagh
was able to participate via conference call (see Appendix 15 for flip chart notes):
Are there financial disincentives to energy conservation?
If there are financial disincentives, where are they (nature) and what is their extent?
Is fixed cost recovery the issue/best way to address DSM?
How much lost revenue (recovered) will cause the company to do something otherwise?
What other information do we need?
Question 1-Existence of Financial Disincentives
All parties agreed that lost fixed cost revenue was associated with every kWh not sold.
Question 2-Nature and Extent of Financial Disincentives
Participants generally accepted the following conclusions:
The nature and extent of the financial disincentive depends on the frequency of rate cases and the
magnitude of IPC's energy efficiency program.
The loss/fixed margin associated with every unsold kWh is needed to recover the fixed costs set in a
rate case. However, over the last 10 years, IPC has implemented no DSM but experienced a huge
loss/fixed margin.
IPC could exert huge effort on programs that don t materialize. Nor would removal of disincentives
guarantee energy conservation.
Question 3-Best Approach for Addressing DSM
Participants agreed that this question couldn t be answered yet since performance-based ratemaking
alternatives haven t been explored.
Question 4-Amount of Lost Revenue Recovery to Effect Change
While striving to answer this question, the following issues were raised:
Ric Gale, IPC, talked about IPC's commitment to re-energize DSM programs from a good faith
stance. But out-of-pocket expenses for DSM (the immediate need) are a bigger concern than lost
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
revenue recovery at this time. If a mechanism for eliminating the financial disincentive could be
implemented cleanly, the company would want to pursue it In the meantime, IPC has made
significant strides in DSM proposals and savings that can be achieved without lost revenue recovery.
One the other hand, management does ask Darlene Nemnich, IPC, about lost revenues any time she
takes a DSM program to management for funding. Lost revenues are an issue at the programmatic
implementation level.
The IPUC is concerned about allowing the company to collect fixed costs that may not be associated
with DSM efforts.
IPC may not be as concerned about lost revenues given the amount of DSM projected in the IRP
which is less than half the NWPCC's target
Although fuel costs, which are given to IPC as fuel recovery, can be volatile and can affect the
company as adversely as lost fixed cost revenue, the approach does differ.
Question 5--lnformation Needs
The analyses presented today addressed some of the questions that people had. However, the need still
exists for a way of determining the amount of savings resulting from DSM. In the future, monitoring and
evaluation results of DSM programs may contribute to understanding the amount of fixed costs
associated with DSM. Because a true-up mechanism may address some but not all concerns, participants
want to see similar analyses of PBR alternatives. IPUC volunteered to develop a PBR strawman for the
next meeting.
NEXT STEPsIWRAP-
Hayman reviewed action items to be completed before the next workshop (Appendix 16). This workshop
is scheduled for December 1 , 2004, from 9:30am to 3:30pm at IPC. During this meeting, participants will
hear strawman presentations, discuss evaluation criteria, and develop the status report for the
Commissioners. If people with action items are unable to complete them for the meeting, Hayman will
notify participants that the meeting will be postponed until December 13.
ApPENDIX 1-PARTICIPANTS (shading indicates work group participants unable to
participate in person or by phone in workshop #3)
Name and Affiliation
Lynn Anderson, IPUC
Name and Affiliation
Laura Nelson, IPUC
Maggie Brilz, Idaho Power
Terri Carlock, IPUC
Ralph Cavanagh, Natural Resources Defense Council
Darlene Nemnich, Idaho Power
Molly O'Leary, Industrial Customers of Idaho (sitting in for
Peter Richardson)
Brad Purdy, Community Action Partnership Association of
Idaho
Bill Eddie, Advocates for the West
Ric Gale, Idaho Power
David Hawk, J.R. Simplot Co.
Nancy Hirsh, NW Energy Coalition
Bart Kline, Idaho Power
Don Reading, Ben Johnson Associates
Greg Said, IPC
David Schunke, IPUC
Randy Lobb, IPUC
Tim Tatum, Idaho Power
Mike Youngblood , Idaho Power
Scott Woodbury, IPUC
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 2-AGENDA
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES
WORKSHOP #3
November 8, 2004
9:30am-3:30pm
Auditorium East
Idaho Power Corporate Headquarters
Boise, Idaho
Objectives:
1) Continue investigating the nature and extent of financial disincentives to energy conservation
programs; identify areas of agreement and any additional information needs.
2) Identify criteria that workshop participants would use to evaluate the applicability/desirability of
potential mechanisms to address disincentives. Deferred..
.. .................... ...... ....
3) Brainstorm potential mechanisms to address disincentives, including additional true-up
mechanisms, performance-based incentives, etc. Deferred..
Final Agenda
Time Topic Process
9:15am CoffeelTea available in meeting room
9:30am Welcome/Introductions/Meeting Overview - Susan Hayman Information
Facilitator
9:45am Continued Exploration of Financial Disincentives Presentations /
(We will take a Action item reports:Discussion
morning break IRP, NWPCC and historical residential scenarioswhen it is most
convenient to calculated with an interim rate case (but without a
the group)true-up mechanism) - Lynn Anderson
);.
Rate impacts by class under IRP and NWPCC
projections - Mike Youngblood
Potential changes in power supply costs from
increased energy conservation (using Aurora
model) - Tim Tatum
Areas of agreement and additional information ne~ds
Are there financial disincentives? If so, what is their nature and
extent? Is additional information required to assess this?
11 :45pm Lunch (on your own)
12:45pm Mechanism Evaluation Criteria - Susan Hayman Deferred..
- -
E~~r:.GL$.e
j-
Q i$.c!J_$.$iQft - --
1 :45pm Potential Mechanisms to Address Disincentives Deferred.. J~r?ll1~t~~lTli!l_
g- - - - - - - - - - --
exercise / DiscussionTrue-ups (different kinds?)
Performance Based Incentives (different kinds?)
Others?
2:30pm Next Steps, Action Items, Evaluation - Susan Hayman Discussion
3:30pm Adjourn
uuuun
uuuuu
Summary of the November 2004, Workshop
( Formatted
......-'
Formatted
'-..........
........................................m.
Formatted
Formatted
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 3-REVISED OPERATIONAL PROTOCOLS
041108
Workshop Series - Operational Protocol
Workshop Name: Assessing Financial Disincentives and Resolution Opportunities
Workshop Purpose:
I) To investigate the nature and extent of financial disincentives to investment in energy efiiciency
by Idaho Power Company and customers;
2) To investigate decoupling and performance-based ratemaking (incentives) as mechanisms to
address financial disincentives (tPUC Order # 29558, 8/10/2004). Other mechanisms can be
subsequently explo,'ed ((the participants agree that this would be useful.
Workshop Products: A written report to the Idaho Public Utilities Commission to update the
Comm ission on the status of the investigative workshops. This report will include a summarized
assessment of:
I) The nature and extent of tinancial disincentives to investment in energy efiiciency by Idaho
Power Company;
2) Recommendations regarding specific decoupling and/or performance-based mechanisms that may
reduce/remove these financial disincentives.
J) Recommendations for next steps.
Workshop Tenure: August 24 through December 15 2004
1) Composition of Workshop Participants
While workshops will be open to the public, it is expected that participants will generally represent
the Idaho Public Utilities Commission, Idaho Power Company, Northwest Energy Coalition
representatives of industrial customers, representatives of residential customers, and representatives
of irrigation customers.
2) Roles & Responsibilities of Workshop Participants
a) Be active in the discussion, be solutions-oriented, and act in "good-faith.
b) Help others at the table to understand your interests, and actively seek to understand the interests
of others.
c) Be infomled - Review the previous workshop summary, the agenda and prework in advance of
the next workshop.
d) Follow-through in a timely manner with any assigned action items.
e) Attend workshops regularly - the group wiII not revisit decisions/discussions missed by others.
t) Workshop Coordinators: One representative each from Idaho Power Company (Mike
Youngblood), Idaho Public Utility Commission (Lynn Anderson), Northwest Energy Coalition
(Bill Eddie), and industrial customers (Peter Richardson). Responsibilities include coordination
with the facilitator on the workshop objectives, outcomes, agenda and process.
3) Role & Responsibilities of the Facilitator
a) Manage the workshops, serve as a process coach, maintain neutrality and impartiality, and
reinforce the collaborative process.
b) Refin~ the objectives and outcomes for each workshop, in cooperation with the workshop
coordinators. Propose a workshop agenda and appropriate processes to reach the identified
Page 1 of I .m Operational Protocol
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
041108
objectives and outcomes, and finalize this with the coordinators. The agenda, and any prework
materials, will be distributed to participants at least one week prior to each workshop.
c) Communicate with participants outside of workshops as needed.
d) Maintain a record of workshop participants, and a summary of workshop discussions (see #6
Record Kecping).
e) Assist in preparation/compilation of the written report to the Idaho Public Utilities Commission.
4) Analysis
Analysis needs will be identified and assigned as they emerge.
5) Decision-Making
a) Entities with multiple representatives: While each individual participant will have input into
the workshop deliberations, it is desirable that each entity represented speak with one voice in
decision-making. Therefore, while numerous individuals may represent a given entity at a
workshop, it is expected that one person will speak on behalf of the entity when decisions are
made. Each entity should designate that person in advance. The facilitator will provide time for
representatives to consult with each other as needed prior to critical decisions.
b) Types of decisions: There are two types of decisions participants will make:
Workshop decisions: These decisions are related to workshop topics, process and
schedule. Workshop decisions already made by the IPUC in Orders 29505 and 29558
will be honored. Decisions at the discretion of the group will be made by consensus.
Product decisions: These decisions are related to the findings and recommendations
workshop participants will present in their written report to the IPUC on December 15
2004. Consensus will be the goal"""; However, if consensus cannot be reached, areas of
agreement and disagreement on the findings and recommendations will be provided in the
written report.
6) Record-Keeping
a) The facilitator will arrange for notes to be taken on a laptop computer during the workshop. The
distributed workshop will include key discussion points, decisions, areas of agreement and
disagreement, action items, etc. They will not be a transcription of "who said what"
b) The facilitator will be responsible for preparing the workshop summary and distributing it to
participants within three business days after each workshop.
c) The facilitator will maintain a file of all workshop summaries, handouts, and products.
7) Principles of Meeting Conduct
a) Focus attention on the speaker (no side conversations)
b) Be specific, but succinct, in questions and comments
c) Participate fillly, but don t dominate the discussion.
d) Respect others contributions, and learn from them.
e) Challenge ideas, not people
f) Be on time
g) Turn cell phones, pagers or other electronic devices off or inaudible during meetings.
Page 2 of 2 - Operational Protocol
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 4-POSTERS WITH OPERATIONAL INFORMATION
Principles of Meeting Conduct
1) Focus attention on the speaker (no side
conversations)
2) Be specific, but succinct, in questions and
comments
3) Participate fully, but don t dominate the discussion4) Respect others' contributions, and learn from them5) Challenge ideas, not people
6) Be on time
7) Turn cell phones, pagers or other electronic
devices off or inaudible during meetings
Definitions
Demand Side Management (DSM): Management
tools and actions that are designed to result in
decreases or shifts in customer energy demand and/or
consumption.
Performance-Based Incentives (PBI): Mechanisms
that allow a utility to share and retain benefits gained
from energy efficiencies, as well as provide
consequences for failing to meet efficiency goals.
Decoupling: Severing the link between a utility s kWh
sales and its recovery of revenues to cover fixed costs.
True-Up: A decoupling mechanism where a periodic
adjustment in electric rates is used to correct for
disparities between a utility s actual fixed cost recovery
and its authorized fixed cost recovery.
Workshop Series-Purpose and Products
(excerpts from Operational Protocol , adopted 9/27/04)
Workshop Purpose:
1) To investigate the nature and extent of financial
disincentives to investment in energy efficiency by
Idaho Power Company and customers;
2) To investigate decoupling and performance-based
ratemaking (incentives) as mechanisms to address
financial disincentives (IPUC Order #29558
8/10/2004). Other mechanisms can be
subsequently explored if the participants agree that
this would be useful.
Workshop Products: A written report to the Idaho
Public Utilities Commission to update the Commission
on the status of the investigative workshops. This
report will include a summarized assessment of:
1) The nature and extent of financial disincentives to
investment in energy efficiency by Idaho Power
Company;
2) Recommendations regarding specific decoupling
and/or performance-based mechanisms that may
reduce/remove these financial disincentives;
3) Recommendations for next steps.
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 5-ANDERSON'S RECALCULATION OF FIXED COST REVENUE Loss USING
IRP INFORMATION AND THREE INTERIM RATE CASES
IPC OSM F.e Fb),,'I1i!1~ l(l$$.' IRPwith 3 rOi!te ~5~ (ReNtSED1-o.-'2'ih'04~
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WiIMI e~ ~~~g1b t~Qf ~Riftrp.J~,,~.e~~~e;e.b,
nil: B;e~iXI~1 ~1!aKt~ Iflu:l1!lOO!t ~\Js.Ifi~Iot~iI M'A'b2006 1,070 3a'ti 5.7'67 ~;427 16,2000 2.-1~L 534 1'l~3 OQ,2007 4 193 1 900 17 300 282M 51,674
2!X1a 5 134 2 810 2'3 007 :H 1O6 69,31372000 7 397 3,601 2S.8a;.1 41.133 1662010 9,~ 4,~' -34,001 ~.5'S-9 1OS l21$2011 11 028 5 980 ~a 3C8. 65;006 123
2012 1V~72. 149 46,1 a;.1 150.412 141.5/58;;;! IRP' ~O13 14.134 IU5il 51 ,001 e,um 1!it-i~Pitfkd .MW,~ 1ffIPp. 13.T~I 6-6.008 3-6.3;17 2:~.500 424,1$)~ 1~,
rMkl M'ffll . 200:3 4 141 39:3
!iR-P,-.'1'2 ~htY_9'%
:t932 7'12 1 J320J;)31 2.325 8753. ~% () 2%
"11 000 9111
2'-%1
(Nl,JlTIOOf$ by IPC ~.t.21fO4~
P"I;!i\:; ~~iW:~ tMY\!')
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2006 81 005 1 0 54i1 10'04i,959 62';215 2:59,i()27
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Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 7-CAVANAGH'S RESPONSE TO ANDERSON'S ANALYSES
__mnm_m Forwarded Message: ---_____m_n
From: "Cavanagh, Ralph" .c:::rcavanagh(fYnrdc.org)-
To: "Lynn Anderson" .c:::landers(E)puc.state.id.us)-, .c:::north country(fYattnet)-
, "
Randy Lobb"
.c:::rlobb~puc.state.id.us)-
, "
Brad Purdy" .c:::bmpurdy~hotmail.com)-
, "
Mike Youngblood"
.c:::myoungblood~idahopower.com)-
, "
Greg Said" o(gsaid~idahopower.com)-
, "
Bart Kline
.c:::bkline~idahopower.com;:'
, "
Ric Gale" .c:::rgale~idahopower.col11;:'
, "
Dave Schunke
o(dschunk~puc.state.id.us;:'
, "
Alden 1101m" .c:::aholm~puc.state.id.us;:'
, "
David Hawk"
o(david.hawk~simplotcom)-
, "
Bill Eddie" o(billeddie~rl11ci.net)-
, "
Scott Woodbury
.c:::swoodbu~puc.state. id. us)-
, "
Peter Richardson" o(peter(fYrichardsonandoleary .com)-
, "
Darlene
Nel11nich" o(dnemnich~idahopower.com)-
, "
Laura Nelson" .c:::lnelson(fYpuc.state.id.us;:.
, "
Maggie
Brilz" .c:::mbri1z~idahopower.com;:'
, "
Terri Carlock" .c:::tcarloc~puc.state.id.us;:'
, "
Nancy Hirsh"
o(nancy~nwenergy .org;:', .c:::ttatum~idahopower.com;:', o(dreading~mindspring.com)-
Subject: Comments on Lynn s Analysis
Date: Wed, 3 Nov 2004 23:32:04 +0000
COLLEAGUES:
I am grateful to Lynn for timely circulation of his revised analysis, and (after a
discussion with him) offer these additional thoughts:
1. The NWPCC energy efficiency projections, although more aggressive than the
Company s current IRP, is not by any means the upper bound of the possible; as
a fraction of system electricity use, for example, the Council targets are only
about half the targets that California s utilities are plam1ing to meet (equivalent to
about one percent of their systemwide retail consumption annually). I would
never suggest to this group that Idaho should copy California, but neither would I
want to imply that it's impossible for Idaho to OUTPERFORM California.
2. On the question of whether potential revenue losses from increased DSM
investments are material, I think that the point is now well established even with
Lynn s revised numbers ($54.5 million over nine years sure gets my attention
and for that matter so does $3 million). But I want to emphasize that Lynn
new, somewhat lower numbers reflect a crucial assumption with which I do not
agree. As Lym1 forthrightly says, his analysis assumes that every time you have
a rate case
, "
forward-looking revenue losses from past DSM efforts are
eliminated
" "
even though past DSM savings are assumed to persist in the
future." Here is the difficulty: those persisting DSM savings continue to inflict
revenue losses on the Company even after the rate case, in the sense that the
unsold kWh return no fixed costs to the Company, and the Company clearly
would be better off financially if those old savings disappeared instead of
persisting. The only sense in which anything is "eliminated" is that each rate
case resets rates based on actual consumption in the year closest to the rate case
so that the sales base for that test year incorporates the impact of previous years
energy efficiency investments in that year. But in subsequent years, if the
savings persist, the Company continues to lose revenues COMPARED TO A
SCENARIO UNDER WHICH THOSE SAME SAVINGS DISAPPEARED, and
Lynn s analysis isn t picking those incremental losses up at all- it's disregarding
them (unlike his initial analysis, which counted them). So, in my view, Lynn is
understating the losses to the company from persistent savings and missing a
Summary of the November 8, 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
perfectly perverse feature of the status quo: the Company is rewarded for
installing short-lived efficiency measures and penalized for finding durable
savings. TillS IS ANOTHER VERY GOOD REASON TO ADOPT A
TRUE-UP MECHANISM THAT ELIMINATES THE LINKAGE
BETWEEN RETAIL ELECTRICITY CONSUMPTION AND IDAHO
POWER'S FIXED COST RECOVERY.
-----
Original Message-----
From: Lynn Anderson (mailto:landers(Q)puc.state.id.us)
Sent: Wednesday, November 03 20041:04 PM
To: north country(Q)att.net; Randy Lobb; Brad Purdy; Mike Youngblood; Greg Said; Bart Kline; Ric
Gale; Dave Schunke; Alden Holm; David Hawk; Cavanagh, Ralph; Bill Eddie; Scott Woodbury;
Peter Richardson; Darlene Nemnich; Laura Nelson; Maggie Brilz; Terri Carlock; Nancy Hirsh;
ttatum(Q)ida hopower .com; dread i ng (Q)m indspri ng .com
Subject: Rate Cases Effects on F-C Rev. Losses
Hello, Decoupling Workgroup,
Attached is a two-tab, two-scenario worksheet that calculates fixed-cost revenue losses
assuming rate cases occur every three years. (Idaho Power s last rate case test year
was 2003.) Under both scenarios, forward-looking revenue losses from past DSM
efforts are eliminated (except for an assumed 6-month lag between the end of the rate
case test year and rate implementation) even though past DSM savings are assumed to
persist into the future. DSM efforts that occur after each rate case test year result in
new fixed-cost revenue losses that accrue until the next rate case. Each rate case is
assumed to result in the loss per MWh unsold increasing by the IRP-projected average
MWh sales growth rate for each customer class.
The first tab shows results under Idaho Power s IRP-Ievel of DSM (which excludes
NEEA). The IRP rate-case adjusted, 9-year total fixed cost revenue loss is $3 million
compared to $6.2 million shown in the IRP worksheet we reviewed at the September 27
workshop. The present value of the $3 million is about $2 million and the levelized loss
is $0.3 million per year.
The second tab shows results under Idaho Power s 6.5% share of the NWPCC-Ievel of
DSM (which includes NEEA, fuel conversions, building codes, appliance standards and
other DSM for which utilities have limited, little or no control.) The NWPCC rate-case
adjusted, 9-year total fixed cost revenue loss is $54.6 million compared to $114.2 million
shown in the NWPCC worksheet we reviewed at the September 27 workshop. The
present value of the $54.6 million is about $39 million and the levelized loss is $6 million
per year.
The analyses in both scenarios are admittedly very simplified, but fairly straightforward.
I doubt that adding complexity for greater accuracy would change the results
significantly. A brief recap from September s workshop: Ralph Cavanagh pointed out
that adding demand-related revenue losses could increase the losses by about 10%, but
I countered that accounting for income taxes would reduce them by a greater amount
and Greg Said reminded us that if lost revenues are recovered then the taxes have to
also be recovered. In short, I think the two scenarios represent a low-side and a high-
side of potential fixed-cost revenue losses, although the possible range is even wider.
Lynn Anderson, IPUC
208-334-0353
Summary of the November 2004, Workshop
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Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 9-FIXED COST LOST REVENUE PER MWH BY CUSTOMER CLASS
Fixed Cost Lost Revenue per MWh by Customer Class
Base Rate Components ($/MWh)
Residential Commercial*Irrigation Industrial**
Total Base Energy Cost (1)$51.$29.$32.$21.45per MWH
Variable Cost per MWH (2)$20.$20.$23.$18.41Class
Variable Cost per MWH (3)$1.$0.($5.72)$0.Subsidy
Fixed Cost per MWH -(4)$28.$7.$22.$1.Class
Fixed Cost per MWH -(5)$1.$1.($7.33)$0.Subsidy
Total Fixed Cost per (6)$30.$8.$14.$2.44MWH (Class & Subsidy)
) Commercial rate is a weighted avg. of schedules 07 & 09 S , & T based on energy use.
(**
) Industrial rate is a wghtd. avg. of schedule 19 S, P & T based on energy use.
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 10-FLIP CHARTS REGARDING MIKE YOUNGBLOOD'S PRESENTATION
Rate Impacts by Class
NWPCC/weather adjusted with true-up
Residential
1) If energy sales faster than forecast and
DSM = growth, brings back to base.
(Ralph's perspective) It is not trying to reward
company for increased growth-provides for
status quo in rate case
2) For DSM, % class increase still relatively small on
an annual basis in short term. Regular rate case
would adjust recovery so that effect in long term
wouldn t be as high as modeled.
3) With increase kWh use (and increased number of
customers), may result in refund to customers plus
additional cost for more facility investment.
Customer Count Model
(Revenue side only)-Recoupling to revenue per
customer
1) Number of customers doesn t affect recover (when
use per customer does not change)
2) For high, refund in first few years while use is
higher, then positive return to company after first
few years.
3) For low case, collecting more than DSM
4) 1.2% over time period in fixed cost recovery
5) For industrial customers, change in number of
customers has greater effect (irrigation customers
are problematic)-served better by forecast
energy
6) Residential, small group-served better
customer count
Results with True-up
1) In high growth , company may be refunding
customers and investing in capital/infrastructure.
2) Trends of true-up effects similar between rate
classes.
Summary of the November 2004, Workshop
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Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 13-FLIP CHART REGARDING TIM TATUM'S PRESENTATION
11 Power Supply Costs from Increased Energy
Conservation
(Excludes fixed costs, but includes higher levels of
DSM-43% total)
1) Reduction in cost every year except year 7
(deferred CHP resource that year)2) Fixed cost-increases except in 2 years of
deferred resource (does not include DSM)
3) What does increasing level of DSM do to power
supply costs?
By increasing DSM and deferring some CHP
resources, shows reduction ($36 million) (now
through 2033) in power supply costs. Net
benefit does not occur until 2022-would
require investment by company.
ApPENDIX 14-FLIP CHARTS REGARDING COMMISSION REPORT
II.
Commission Report
History of issue that generated work group-IPUC
What did work group do?
Studies -problems analysis, assumptions
why we did studies we did
What mechanisms explored
Results of investigation (possible
solutions/details)
III. Conclusions and recommendations
Questions on wall
IV. Figures and tables, studies, workshop summaries
Report Review
Drafts circulated to all
Replies go to "report coordinator" from parties
IPC
NWEC
Industry
IPUC
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 15-Fup CHARTS REGARDING QUESTIONS TO ANSWER
Are there financial disincentives to energy
conservation?
If there are financial disincentives, where are they
(nature) and what is their extent?
What other information do we need?
Are there financial disincentives.to energy
conservation?
IPUC-yes (loss of revenue associated with every
kWh unsold)
IPC
ICIP
NWEC
How much lost revenue (recovered) will cause the
company to do something otherwise?
IPC
Re-energizing DSM program
Out-of-pocket expenses is bigger concern
than lost revenue recovery at this time
Bin
1) Is the fixed cost recovery the issue or some other
specific way to address DSM?
2) How much lost revenue (recovered) will cause
company to do something otherwise?
If there are financial disincentives, where are they
(Nature), and what is their extent?
In loss/fixed margin associated with unused kWh
needed to recover fixed cost set in a rate case.
Magnitude of company energy efficiency
effort
The more effective energy programs are, the
less fixed cost lost margin
Residential and small commercial ratepayers most
affected. Rates would affect this.
Is fixed cost recovery the issuelbest way to
address DSM
(Cannot be answered at this time)
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 16-FLIP CHARTS REGARDING NEXT MEETING AND ACTION ITEMS
What Who When
1) . Check with commission Randy
regarding scope of PBR
discussion (DSM
related only)
Talk with Bill about Nancy 11/09
report coordination-
reply to Susan to
distribute to work group
Coordinate timing for Susan Next
the draft report to work meeting
group for review/status or e-mail
report
Develop PBR strawman IPUC Next
well suited for Idaho meeting
done elsewhere
Complete Analysis For IPUC Next
PBR-I PC-Defer meeting
Refined Cavanagh
True-
Refine Cavanagh true-Ralph Nextup strawman meeting
December 1 meeting (9:30 to 3:30)
Strawmen presentations
Evaluation criteria
Status update
December 13 (alternative or next date)
Summary of the November 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities
(Corrected 041213)
Workshop
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES, WORKSHOP
DECEMBER 1 2004 9:30 A.M. TO 3:00 P.
CONFERENCE ROOM 9 EAST, IDAHO POWER CORPORATE HEADQUARTERS , BOISE, ID
Facilitation Susan Hayman, North Country Resources , Inc.
Documentation Natalie Chavez, Chavez Writing & Editing, Inc.
WORKSHOP OBJECTIVES
1) Confirm criteria to evaluate the applicability and desirability of potential mechanisms to remove
disincentives/provide incentives for utility investment in DSM programs
2) Review two potential mechanisms:
a) Refined true-up mechanism
b) Performance-based ratemaking mechanism
3) Confirm the type of report that will be submitted to the IPUC on December 15 and assignments for
preparation and review
WORKSHOP DECISIONS AND OUTCOMES
Participants agreed to a set of evaluation criteria for potential disincentive/incentive mechanisms. The
purpose of the evaluation would be to compare and contrast different mechanisms to determine their
applicability and desirability.
Participants also decided to recommend a pilot of the performance-based mechanism proposed by I PUC
staff for one program until the next rate case. They also want to simulate the true-up mechanism during
the same period, based on real numbers , to consider it further and refine the mechanism. The next
meeting is scheduled for December 13, 9:00 am to 12:00 pm at IPC to discuss the details of these
recommendations. The final report and an application for the pilot program will be submitted to the IPUC
some time in January (dates to be determined December 13).
ACTION ITEMS
What?
1) Draft and distribute status report for review and comment
Who?
Susan Hayman and
Scott Woodbury
IPC
(Darlene Nemnich)
When?
December 3
2) Prepare the outline and anything else necessary for
developing the proposal for a pilot performance-based
incentive mechanism; bring to the next meeting
3) Design the simulation for the true-up mechanism; bring to
the next meeting
December 13
IPC
(Mike Youngblood)
December 13
WORKSHOP INTRODUCTION
Susan Hayman, North Country Resources, welcomed participants (Appendix 1), reviewed workshop
objectives (above), and then reviewed the agenda (Appendix 2). She also reviewed posters with the
principles of meeting conduct, purpose and products of the workshop series, and important definitions.
Summary of the December 2004, Workshop
MECHANISM EVALUATION CRITERIA
Hayman distributed a handout with potential mechanism evaluation criteria (Appendix 3). She compiled
these criteria after telephone conversations with many of the participants prior to the November 8
workshop. Hayman said that the list served as a starting point for developing a final list of criteria against
which to evaluate potential disincentive and incentive mechanisms. Participants first clarified their
understanding of the criteria, and then revised criteria until they were acceptable to all. Appendix 4
includes flipchart notes taken during the discussion. However, most changes were captured on the wall
poster of the preliminary criteria during group discussion. The final revised list is included in Appendix
POTENTIAL MECHANISMS
Refined True-Up Mechanism
Ralph Cavanagh , Natural Resources Defense Council, spoke about the requested revision to the
strawman proposal for an Idaho Power true-up mechanism (introduced at Workshop #2 on
September 27 2004). A handout summarized points of the original proposal as well as the proposed
revisions (Appendix 6). These proposed revisions included true-up based on actual customer counts for
residential and commercial customers (rather than on forecasted sales for all customer classes as
originally proposed).
Cavanagh, in cooperation with Idaho Power staff, looked into how often a true-up tied to actual customer
counts would have increased or reduced rates for the residential and commercial classes since 1990. For
any year during which such a mechanism would have been in effect, rates would have gone down if the
class s retail sales had grown more rapidly than the class s customer count, and vice versa. For the
commercial sector, electricity use grew more rapidly than the customer count in 10 of the 14 years since
1990. For the residential sector, electricity use grew more rapidly than customer count in 2 of the 14
years, while rates of growth were essentially identical in 3 years (including 2003). These findings confirm
the potential for rate decreases as well as increases for both classes under a true-up mechanism
although based on historical data, the likelihood of a rate decrease is substantially greater for the
commercial sector than for the residential sector. Cavanagh emphasized that annual class-specific rate
increases necessary to ensure recovery of the authorized fixed-cost revenue requirement would never
have exceeded 2% under the true-up mechanism. In most years, for both classes , rates would have
shifted up or down by 1 % or less.
During his presentation , Cavanagh shared the following:
. A bar chart showed the net benefit of expanded energy-efficiency efforts for the Idaho system. The
high case indicated the greatest net benefit to the system at just over a $100 million (Appendix 7).
Given the net benefits , financial disincentives need to be removed so that Idaho Power is encouraged
to promote energy efficiency through conservation programs.
This true-up mechanism provides symmetry in that it addresses both lost revenues and found
revenues. Therefore , it discourages "perverse incentives" and DSM programs that "look good on
paper but aren t effective in practice.
The revised strawman proposal avoids cross subsidies and is fundamentally fair to the customers.
. A second bar chart showed the annual household energy use (in kWh) for entertainment electronics
that will likely be typical of households in about 10 years (Appendix7). It's expected that combined
energy use for plasma TVs, DVDNCRs, and set top box/satellite receivers will be about 1 200kWh
annually, up from about 500 kWh now with analog TVs. Workshop participants were cautioned
through this example that technological advances and changes in customer habits do not necessarily
lead to reduced per-customer electricity usage. This underscores the importance of well-designed
energy efficiency incentives, as well as and the merits of the revised NRDC true-up proposal (which
ties any increases in fixed cost recovery for the residential and commercial classes to increases in the
number of residential and commercial customers).
. A performance-based mechanism could be used in conjunction with the true-up mechanism.
Summary of the December 2004, Workshop
Follow-up discussion among participants focused on how big the impacts of implementing a true-up
mechanism would be to residential and commercial customers and how rate adjustments would be
calculated. Flipchart notes made during this portion of the workshop are included in Appendix 8.
Perlormance-Based Ratemaking Mechanism
Lynn Anderson, IPUC, distributed a two-page strawman proposal for a performance-based mechanism
(Appendix 9). Before talking about the proposal summarized on the second page, he asked that
participants review the hypotheses included on the first page. Until he compiled this list, he had been
unable to draft the proposed mechanism. The following issues were raised during discussion of
hypotheses:
Cavanagh questioned the exclusion of increased gas market share from fixed...cost losses in
hypothesis #7. Idaho Power may be motivated to retain electric market share for water heaters if the
company is unable to recover the fixed-cost revenue losses resulting from customers' conversion to
more efficient gas water heaters. This approach seems to penalize the company for these
conversions and encourage inefficiency. IPUC staff pointed out that Idaho Power could implement a
DSM program that reimburses customers for converting to energy-efficient gas water heaters.
Some workshop participants see some inconsistency in the IPUC's view on factors outside Idaho
Power s control. For example, the strawman proposal disallows Idaho Power from collecting fixed-
cost revenue losses unless incurred through DSM efforts. Yet reimbursement of fuel costs through
the company s Power Cost Adjustment (PCA) mechanism does allow for factors outside the
company s control.
The means for verifying savings resulting from DSM programs are likely to be "complex, tedious, and
expensive.
Following discussion of the hypotheses, Anderson explained the actual proposal, found on the second
page of the handout. The IPUC staff's strawman proposal would implement a mechanism to remove
financial disincentives by allowing specific fixed-cost revenue recovery for all verified DSM savings with a
bonus financial incentive for exceeding cost-effective DSM targets. He pointed out that the financial
incentives component of the proposal could also be implemented as a stand-alone approach or with a
true-up mechanism. This mechanism , as proposed, would be implemented as a trial restricted to the
Residential New Construction program. Residential energy rates have a relatively high fixed-cost recovery
component, which means that Idaho Power s financial disincentive for DSM in this class may be higher
than for other customer classes. It's also a relatively small program , so effects of any mistakes made in
the trial would be minimized. The following points were made during discussion of the performance-based
proposal:
According to Darlene Nemnich , IPC , Idaho Power rewards customers $750 when they exceed
building code on energy efficiency by 30% on new construction. Ideally, builders would want to make
homes as energy efficient as possible, but they are unlikely to want to change codes. Therefore, code
enforcement and training of code officials is important, and it is reasonable to credit utilities with work
they do with code enforcement beyond typical DSM programs.
Because of the trial nature of the mechanism , no penalties are included. Quality control is relatively
straightforward, and the targeted customer group is narrow, but the potential for perverse incentives
cannot be dismissed.
Flipchart notes pertaining to the performance-based mechanism are included in Appendix 10.
Adwuonal Suggesuon
David Hawk, J.R. Simplot Co., suggested that the group conduct an 18-month simulation of the two
proposed mechanisms based on real numbers. He believed that all parties and participants had invested
too much time discussing concerns with financial disincentives and potential corrective mechanisms for
nothing to happen. Because participants may not be comfortable implementing one or both of the
proposed mechanisms right now, an 18-month simulation would allow proposals to be studied further and
problems worked out before the group forwarded a firm recommendation to the IPUC. The flipchart
regarding Hawk's suggestion as well as other modeling options is included in Appendix 11.
Summary of the December 2004, Workshop
NEXT STEPS
Mechanism Analysis/Evaluation
Ric Gale, IPC , requested that the interest groups (IPUC , Idaho Power, Northwest Energy Coalition , and
Industrial Customers) caucus before presenting their views on each of the three proposals: true-up
mechanism , performance-based pilot, and 18-month simulation of the two proposals. Hayman allotted 15
minutes for caucusing. Afterwards, she asked that group spokesmen share their groups' views on the
three proposals and next steps. Industrial Customers felt that David Hawk's previous suggestion for a
simulation adequately represented their view. Flipchart notes from the three interest reports are included
in Appendix 12.
Idaho Power Company
Gale reported the following Idaho Power perspectives regarding the proposals:
Idaho Power is concerned about disallowance of program costs. The company endeavors to manage
program costs as effectively as possible. But disallowance of program costs and prudence reviews by
the IPUC significantly deters DSM investment.
In the intermediate or long term , the company may want to implement a true-up mechanism. In the
next couple of years, Idaho Power wants to undertake the activities in the IRP but is probably unable
to ramp up DSM any more than that. They are, however, amenable to simulating the true-up
mechanism until the next rate case to at least identify unintended consequences. Gale isn t sure how
much influence results of the simulation will have, but it could eliminate a degree of the uncertainties.
The company is intrigued by IPUC staff's incentive mechanism and supports piloting it with one
program until the next rate case and then evaluating its applicability to others.
Northwest Energy Coalition
Ralph Cavanagh shared the following viewpoints for Northwest Energy Coalition representatives:
They are not convinced that a simulation will change people s minds. Therefore, the coalition isn
interested in pursuing a simulation unless the group is truly committed to moving forward, the
simulation/test is credible, and the exercise establishes an architecture that can be used in the next
rate case.
The simulation mayor may not be effective in evaluating how Idaho Power Company s appetite for
conservation programs would change if a true-up were implemented. Rather, the simulation will give
an indication of the rate impact of the true-up under hypothetical scenarios of conservation activity.
Their commitment to the true-up mechanism hasn t diminished. Although they can forward the
proposal directly to the IPUC, they prefer to continue working with this group. Gale commented that
the simulation allows the group to refine the mechanism before the next rate case so that they can
give the IPUC something feasible.
Idaho Public Utilities Commission
Randy Lobb reported the following points of view for IPUC representatives:
They understand Idaho Power s concern about cost recovery and prudence reviews. But the IPUC
will continue these reviews, and the company will likely continue to do a good job. They believe that
because of the Energy Efficiency Advisory Group (EEAG), the company is actually at less risk now
regarding disallowances than it has been in the past.
The IPUCis interested in piloting the performance-based mechanism on a single program. This pilot
allows everyone to see whether the complexity can be worked out and the mechanism is feasible.
The IPUC is also amenable to the 18-month simulation of the true-up mechanism if the other groups
support it. The main purpose of the mechanism is to see how it changes company activities. A
simulation may have some value. If nothing else, it keeps a mechanism that the IPUC staff is unlikely
to suggest adopting at the moment on the table for future consideration. Working through it now may
Summary of the December 1 2004, Workshop
provide the company information it needs when it starts making decisions for the next two-year IRP
cycle.
Commission Reports and Timelines
Hayman directed participants to discuss the two reports-status and final-to the IPUC and timelines for
continued activities. The following decisions were made:
Scott Woodbury, IPUC , and Hayman will collaborate on the status report and send it out Friday,
December 3, for review.
This group will meet Monday, December 13 , to discuss details of the pilot performance-based
mechanism and simulation of the true-up mechanism.
Idaho Power staff will prepare an outline for the pilot program and a design for the simulation for
discussion and finalization at the December 13 meeting. The company would like to see the pilot start
January 1 (or as soon as possible thereafter) when the DSM program begins. The pilot application
does not have to be submitted with the final report, although the report will be supportive of the filing.
The group agreed that the final report may precede the application filing unless they were submitted.
concurrently. The group decided to talk specifically about the timing of the filing and the report at the
December 13 meeting.
Bill Eddie, Advocates for the West, will coordinate the final report, which will likely be a
recommendation to implement the pilot and simulation until the next rate case. The draft outline for
the report was developed at the November 8 meeting.
WRAP-UP AND WORKSHOP EVALUATION
Hayman reviewed action items to be completed before the next workshop (Appendix 13). This workshop
is scheduled for December 13, 2004 , from 9:00 am to 12:00 pm. Mike Youngblood agreed to check on
the availability of Conference Room 9 East for this workshop. During the workshop, participants will
discuss details of the pilot performance-based mechanism and simulation of the true-up mechanism.
Hayman also requested that participants evaluate the workshop. She recorded positive items and
possible changes on flipcharts (Appendix 14). Though feelings were mixed on preferable room size and
temperature, for the most part, participants are pleased with the honest and frank discussion, facilitation
and documentation , and refreshments.
Summary of the December 2004, Workshop
ApPENDIX 1-PARTICIPANTS
(Shading indicates work group participants unable to participate in person or by phone.
Name and Affiliation Name and Affiliation
Terri Carlock, IPUC
Ralph Cavanagh , Natural Resources Defense Council
Peter Richardson, Industrial Customers of Idaho
Bill Eddie, Advocates for the West
Ric Gale, Idaho Power
Don Reading, Ben Johnson Associates
Greg Said, IPC
David Hawk, J.R. Simplot Co.
Nancy Hirsh, NW Energy Coalition
Bart Kline, Idaho Power
Randy Lobb, IPue
Tim Tatum, Idaho Power
Mike Youngblood , Idaho Power
Scott Woodbury, IPUC
Summary of the December 1 2004, Workshop
ApPENDIX 2-AGENDA
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES
WORKSHOP #4
December 1 , 2004
9:30am-3:00pm
Conference Room 9 East
Idaho Power Corporate Headquarters
Boise, Idaho
Objectives:
1) Confirm criteria to evaluate the applicability and desirability of potential mechanisms to remove
disincentives/provide incentives for utility investment in DSM programs
2) Review two potential mechanisms:
a. Refined true-up mechanism
b. Performance-based ratemaking mechanism
3) Confirm the type of report that will be submitted to the IPUC on December 15 , and assignments
for preparation and review
Final Agenda
(breaks will be taken when most convenient for the group)
Time Topic Process
9: 15am CoffeelTea available in meeting room
9:30am Welcomellntroductions/Meeting Overview - Susan Hayman Information
9:45am Mechanism Evaluation Criteria - Susan Hayman Exercise
Discussion
10:30am Potential Mechanism Presentation /
Refined true-up mechanism - Ralph Cavanagh Discussio n
11 :30pm Lunch (on your own)
12:30pm Potential Mechanism Presentation /
Performance-based ratemaking mechanism - Lynn Discussion
Anderson
1 :30pm Next Steps - Group Discussion
Mechanism analysis/evaluation to be completed
(using criteria, other?)
Nature of the December 15 IPUC report
Timelines
2:45pm Wrap-up and Evaluation - Susan Hayman Discussion
3:00pm Adjourn
Summary of the December 1 2004, Workshop
ApPENDIX 3-POTENTIAL MECHANISM EVALUATION CRITERIA
Potential Mechanism Evaluation Criteria
1 ) Balanced (fair) allocation of program costs across
shareholders and ratepayers
2) Cross-subsidization of program costs across ratepayer
groups are minimized
Removes financial disincentives to themax
Positive financial benefit (at least less negative
effect), measured over time
5) Ratepayers are better off than they would be without
the mechanism
Promotes rate stability
Simple mechanism
Costs easily tractable
Mechanism adjustments are predictable and easily
understood
10) Monitors short and long term effects to customers
and company
11) Incentives to manipulate the mechanism are not
present
12) Close link between mechanism and desired DSM
outcomes
13) Provides adequate incentive for the acquisition of all
cost - e ffecti v eO SM
Summary of the December 2004, Workshop
ApPENDIX 4-FLIPCHARTS REGARDING EVALUATION CRITERIA
Criteria
#4 Needs clarification
. "
Benefit to all stakeholders from where they
would have been otherwise
Drop "less negative -should be net benefit
#10 Process needs to monitor mechanism
Ratepayers" are "customers" (change
throughout)
Stakeholder =
company and customers
includes everybody
#8 Tractable
Want mechanism that is affordable
Costs known and manageable , not subject to
unexpected fluctuations
not talking about program cost recovery
#5 Difficult to know benefits to all stakeholders
until after the fact
#5 is the bottom line
#11 Avoid "perverse" incentives
Summary of the December 2004, Workshop
ApPENDIX 5-REVISED VERSION OF POTENTIAL MECHANISM EVALUATION CRITERIA
Potential Mechanism Evaluation Criteria
Stakeholders are better off than they would be
without the mechanism
2) Minimize cross subsidies across customer classes
3 ) Removes financial disincentives
4) . Optimizes the acquisition of all cost-effective DSM
5) Promotes rate stability
6) Simplemechanism
7) Administrative costs and impacts of the mechanism
are known, lnanageab Ie, and not subj ect to
unexpected fluctuation
8) M-onitors short and long terlTI effects to customers
and company
9) Avoids perverse incentives
10) Close link between mechanism and desiredDSM
Summary of the December 2004, Workshop
ApPENDIX 6-REVISIONS TO THE STRAWMAN PROPOSAL FOR AN IDAHO POWER
TRUE-UP MECHANISM
PROPOSED REVISIONS TO STRA WMAN PROPOSAL FOR AN IDAHO
PO WER TR UE- UP MECHANISM
Submitted by Ralph Cavanagh
For discussion at 12/1/04 workshop
I. ORIGINAL PROPOSAL, DISCUSSED AT 9/22/02 WORKSHOP
1. Starting point: fixed-cost revenue requirement and retail rates approved by Idaho
PUC in latest Idaho Power rate case.
2. If, after initial year, changes in retail electricity use lead to under- or over-
recovery of fixed cost revenue requirement, a rate true-up would occur in the
following year on the same schedule as the Company s currentPower Cost
Adjustment.
3. Until reestablished in the next Idaho Power rate case, the currently approved fixed
cost revenue requirement would be automatically adjusted annually to reflect the
same rate of increase (or decrease) shown for retail electricity sales, net of any
DSl\11 programs, in Idaho Power s latest IRP. True ups would occur annually
based on any divergence between the total fixed-cost revenue recovery that
forecast sales would have delivered and the fixed-cost revenues actually
recovered (so if, for example, sales were forecasted to increased by 2 percent and
actually increased by a larger percentage, Idaho Power would refund the
difference at the time of the next Power Cost Adjustment; if retail sales increased
by a smaller percentage than forecast, Idaho Power would get back the lost
revenues at the time of the next Power Cost Adjustment).
4. True-ups would occur by customer class based on divergence between actual and
forecast sales to each customer class.
5. Idaho Power would continue to absorb the risk or benefits of purely weather-
related effects on fixed-cost revenue recovery, as it does now. This would mean
weather normalizing actual sales before making the annual true-up calculation.
MAXIMUM ANNUAL AVERAGE RATE IMP ACT OF THE TRUE UP
MECHANISM, UP OR DOWN, UNDER EXTREME CONDITIONS = 1.5 PERCENT.
II.PROPOSED REVISIONS AND ANSWERS TO SUBSEQUENT
QUESTIONS
A. CHANGES IN CALCULATION OF ANNUAL FIXED
COST RECOVERY: Without a true-up, fixed cost recoveries
grow in direct proportion to growth in total retail sales, averaging
Summary of the December 1 2004, Workshop
about 2 percent per year over the past decade. The initial
proposal called for growth in fixed cost recovery to be tied to
annual growth in the forecast of retail sales adopted in the
Company s most recent IRP. Concerns were raised that, in the
residential and commercial sectors particularly, growth in
customer counts could substantially exceed growth in forecast
sales, resulting in undeffecovery of costs prudently incurred to
serve new customers. PROPOSED SOLUTION: Tie growth in
fixed cost recovery to actual measured changes in annual
customer count for the residential and commercial seCtors. This
should allow a closer convergence between the fixed cost
revenue requirement and actual costs of service.
B. RETROSPECTIVE ASSESSMENT: In co,?peration with the
Company, I looked into how often a true-up tied to customer
counts would have increased and reduced rates, respectively, for
the residential and commercial classes since 1990 (concerns had
been raised that rates would always go up under such a
mechanism). For any year during which such a mechanism had
been in effect, rates would have gone down if the class s retail
sales had grown more rapidly than the class s customer count
and vice versa. So we looked at how often the residential and
commercial customer counts increased more rapidly than class-
wide electricity use in each year, starting in 1990. For the
commercial sector, electricity use grew more rapidly than the
customer count in ten of the fourteen years from 1990-2003. For
the residential sector, electricity use grew more rapidly than
customer count in two of the fourteen years, and the rates of
growth were essentially identical in three other years (including
2003). This confirms the potential for rate decreases as well as
increases for both classes under a true-up mechanism, although
based on historical data the likelihood of a rate decrease is
substantially greater for the commercial sector than the
residential sector. Finally, it should be emphasized that annual
class-specific rate increases needed to ensure recovery of the
. authorized fixed-cost revenue requirement would never have
exceeded two percent under the true-up mechanism. In most
years, for both classes rates would have shifted up or down by
one percent or less.
Summary of the December 2004, Workshop
ApPENDIX 7-BAR CHARTS DISTRIBUTED BY CAVANAGH
Exhib'J,rS..
Present Va tllt?- Costs and Benefits
,.
Addeva.ble P'otel.tN~d SceJ~ari;O-$
5450
---.
$4;00 r*""'~N;rS efiis
"",
' E!J I':. 0'0' ..!:J otal oeneufl5
1iII:~m 'InCMiifM.
.~~
.N~me:ll!'lm' Panh::iip~t"U Co$I:$ ,
OM a dte11 rig 8Mml'1islranon
. . ...
.............. T.
, ., . .- . . -
n. -
. - . .-. -
5350
I iaoo
...
:; $250,
1iEi
::)
1200
i $'$,0.
.. '" ..
SUJO
. " ", ,. , ,., .
$00",....
Low M CKh) ~ tiJ'HiOI'1.MiWliI. A(:hle"~
Household Energy Use for iEnt'8rt8inl1'M!nt Electronics;
Primary TV. plasma liD-TV
VDlVCR
P ~lrnary
OVQNC
Set'top box/satellite receiver
SecondsIY TV, analoQ
SacordafJ 1V
Ss,f lop' boxIsatelJitIJ fees/vet
Combinedenergry use'
1200 kWh pe.ryeart
250.500. 750.
Annual Energ, u.e (k.Wh)
Summary of the December 1 2004, Workshop
ApPENDIX 8-FLIPCHARTS REGARDING CAVANAGH S REVISED STRAWMAN
Assumptions for True-
Last year s consumption plus 2% to calculate
the rate increase spread over kWh the next
year.
Clear every year don t want to carry
significant over/underages/year
If kWh sales exceed customer count in a
class, there would be a rate decrease.
Question: How to resolve true-up within
schedules for irrigators and industrial? (how
to true-up with subclasses to the classes)
Rate impacts could be more volatile under
multiple true-up values
Summary of the December 2004, Workshop
ApPENDIX 9-PROPOSED STRAWMAN FOR A PERFORMANCE-BASED MECHANISM
Strawman Proposal for DSM Performance Incentive
For Discussion at IPC Decoupling Workshop, 12/01104
Hypotheses:
1) The primary DSM financial disincentives in question are those that affect shareholders
rather than managers. These disincentives are primarily "fixed-cost" revenues that are not
collected when electricity is not sold; i.e. those portions of energy and demand prices that are
based upon utility costs that do not vary with energy usage in the short run.
2) Idaho Power will fail to maximize demand-side management (DSM) potential benefits
for its customers unless the primary financial disincentive is removed through a regulatory
mechanism.
3) Idaho Power s customers will be het beneficiaries if the company provides more cost-
effective DSM as a result of customers paying to remove the primary financial disincentive.
4) Rate cases will occur too infrequently to sufficiently mitigate the primary financial
disincenti ve.
5) The company is legitimately entitled to recover fixed-cost revenue losses caused by its
DSM efforts regardless of the absence of rate case examinati on of overall costs and revenues.
6) Idaho Power is incurring new fixed costs due to customer growth and its incremental
fixed costs exceed its incremental fixed-cost revenues. In other words, customer growth does not
mitigate fixed-cost revenue losses.
7) It is unacceptable to the IPOC Staff to adopt a financial mechanism that would simply
allow Idaho Power, without a rate case, to automatically collect all fixed-cost losses" associated
with all kWh per customer sales reductions, much of which is caused by factors not associated
with the company s DSM., e.g. increased gas market share. The 10-year lapse between Idaho
Power s last two rate cases, in spite of reduced sales per customer, is an indicator that profitability
is largely independent of sales per customer.
8) It is unacceptable to Idaho Power to adopt a financial mechanism that considers only
total sales; i.e. that does not account for growth in the number of customers.
9) Removing the primary financial disincentive for DSM can be reasonably accomplished
through a mechanism that targets only DSM-caused sales reductions. There are two ways to do
this: a) The financial disincentive could be removed by allowing specific fixed-cost revenue
recovelY for all verified DSM savings; b) The financial disincentive could be removed by
providing other financial rewards for verified DSM accomplishments. Method b)'s financial
rewards could be stand-alone or used in conjunction with method a) or with decoupling.
Summary of the December 2004, Workshop
Strawman Trial Proposal
Unlike decoupling, both methods a) and b) above require precise measurement and
verification of DSM program implementation details, baselines and DSM results, and, as such, are
inherently complex, subject to measurement error, and require significant regulatory oversight.
Thus, it is reasonable to implement either of these methods on a trial basis.
For a strawman trial, we have selected a proposal that combines methods a) and (b) above;
e. recovery of DSM-caused fixed-cost revenue losses with a bonus financial incentive for
exceeding cost-effective DSM targets. We suggest that the trial be restricted to the Residential
New Construction program. Residential energy rates have a relatively high fixed-cost recovery
component, which means that Idaho Power s financial disincentive for DSM. for this class may be
higher than for other customer classes. This is a comparatively small program, thus minimizing
the effects of any mistakes made in the trial. Nevertheless, this program is projected to be very
cost-effective for both energy and peak demand savings and "lost opportunity" will occur if it is
not vigorously pursued.
The table below illustrates some of the projections for the Residential New Construction
program as contained in the IRP. Also shown are discussion starting points for financially
rewarding Idaho Power for significantly outperfonning its projections. Whatever combination of
indicators and incentives are used, the program must remain cost etIective to customers.
Possible Indicators Annual Fixed-Cost g. Bonus Bonus Financial Incentive
Targets Rev. Recovery Threshold (for illustration only)
MW reduction 10% ? target 200/0 of net $ savings
MWh reduction 661 actual MWh 10% ? target "10% of net $ savings
saved x $31.20
Idaho Power $/peak k W 10% .c target 5% of program costs
Idaho Power $/kWh 036 10010 .c target 5% of program costs
Total Resource $/peak kW "10% .c target 5% of total costs
Total Resource $/k Wh 058 10% .c target 5% of total costs
Participant Payback 5 yr.0% .c target 5% of patticipants' costs
Number of Participants 10% ? target 5% of program costs
Market Transfonnation 5% of program costs
Summary of the December 2004, Workshop
ApPENDIX 1Q-FLIPCHARTS REGARDING PERFORMANCE-BASED MECHANISM
. PBR/Hypothesis Discussion
1) Managers = utility company managers
2) This proposal does not address "found"
revenues and has a narrow view of "lost"
revenues (DSM-related only)
3) #7 Concern about not linking advantages of
true-up with issues about increased gas
market share
Staff wants fixed-cost recovery for DSM-
related programs (utility co. control) ~ NOT
consensus with group on this
ApPENDIX 11-ADDITIONAL SUGGESTIONS
Bin
1) 18-month financial simulation of proposals-
. real, documented numbers for FCR
Options
1) Model period of 10 years
a) "Council level" of conservation against
I PUG staff proposal
b) True-up with "Council levels" of
conservation
Use maximum net benefit scenario:
rate impacts
IRP baseline
4) Energy savings calculations would be difficult
and problematic
5) Cost recovery may be a bigger issue than
lost revenues
6) Proposal is for residential construction only
(Energy Star program-exceeding building
codes)
7) Some potential for perverse incentives-
need to monitor closely
Summary of the December 2004, Workshop
ApPENDIX 12-INTEREST REPORTS
Interest Reports
IPC
1) Disallowance of program costs will kill
DSM-first and foremost disincentive
2) Problem of lost revenues will have
a... material impact on amount of load-
reducing activities we undertake in short and
long term
3) Next couple years, company will undertake
DSM identified in IRP-can t take on any
additional in this period (ramp-up ability
limited)
4) 18-month simulation of TU. mech. would
help relieve uncertainties (unintended
consequences) prior to next rate case
5) Intrigued with staff incentive mechanism, and
piloting with one program then determining
applicability to others
I PUC-Staff
1) Staff will continue cost-effectiveness/
prudence review
2) Interested in pilot incentive based program.
Can work on measurement and evaluation to
see if doable.
3) 18-month simulation-main impact of T.
mechanism is to see how it changes
company s behavior. Wouldn t oppose
proceeding with this, though unsure of real
value of simulation. May be best we can do
now to keep alive without killing it.
NWEC
1) Not convinced simulation will change
minds-not interested in pursuing unless
group is really committed to moving forward
and simulation/test is credible with everyone
and materially improve likelihood of approval
by Commission
2) Retain right to bring proposal to Commission
directly, but would rather work as a group
Summary of the December 2004, Workshop
ApPENDIX 13-NEXT STEPS AND ACTION ITEMS
Next Steps
1) Status report on 15th
2) Flesh out concept of pilot and simulation on
13th (9:00-Noon)
3) Provide full report in January with
recommendation , what we discussed and
why we re proposing this approach. Decision
at end point.
Action Items
What Who When
1) Draft status report Scott 12/03/04
for review and and
comment Susan
2) Bring what is IPC 12/13/04
necessary for pilot (Darlene)
proposal-outline
for filing
3) Bring simulation IPC 12/13/04
design (Mike)
4) IPC would submit application for pilot to
commission-projected date by end of
January (simultaneous with filing or at least
final report first)
5) Assuming model can be set up, could
possibly start accounting after first of year
(January 1 if possible)
Summary of the December 2004, Workshop
ApPENDIX 14-WORKSHOP EVALUATION COMMENTS
1) Good job!
2) Frankness of
conversation useful
& appreciated
3) Like smaller room
4) Like facilitating
5) Like someone
ramrodding it"
6) Appreciate
deadlines and
follow-up
7) First class job
1 ) Room is too
small and too
warm
13) Appreciate cheese
and celery!
14) Appreciate
comprehensive
summaries
. 15) Enjoyed open and
honest discussion
and movement in
positions
16) Like follow-up with
meeting summary-
that it is right
8) Like smaller room
9) Like fruit!
10) Like summaries-
timely and well-
structured
11) Nice to get prework
discussion items
ahead of time
12) Very important that
everyone is here-
adds to the process
Summary of the December 1 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES, WORKSHOP
DECEMBER 13, 2004, 9:00 A.M. TO 12:00 P.
CONFERENCE ROOM 6 EAST, IDAHO POWER CORPORATE HEADQUARTERS, BOISE, ID
Facilitation
Docu mentation
Susan Hayman , North Country Resources, Inc.
Natalie Chavez, Chavez Writing & Editing, Inc.
WORKSHOP OBJECTIVES
1) Review and finalize proposals for
a) Refined true-up mechanism simulation
b) Performance-based mechanism pilot program
2) Finalize the status report for submission to the IPUC by December 15, 2004
3) Determine the final report timelines and responsibilities
ACTION ITEMS
What?
Prepare the application for the pilot project and
circulate it to the work group for review and
comment.
Who?When?
Lynn Anderson , IPUC, and
Idaho Power
February
Refine the simulation proposal (and retrospective
analysis) and circulate it to the work group for review
and comment.
Draft final report and circulate it to the work group for
review and comment.
Mike Youngblood , Idaho
Power; Bill Eddie
Advocates for the West;
and Ralph Cavanagh
NRDC
Bill Eddie, Advocates for
the West
January 14
January 14
File pilot application with the IPUC Idaho Power Mid-February
WORKSHOP INTRODUCTION
Susan Hayman , North Country Resources , welcomed participants to Workshop #5 (Appendix 1),
reviewed workshop objectives (above), and then reviewed the agenda (Appendix 2). Because Bill Eddie
Advocates for the West, was expected to be a little late, presentations for the true-up mechanism
simulation and performance-based mechanism pilot were switched on the agenda.
Before participants movedon to the first presentation , David Hawk, J.R. Simplot Coo , congratulated
Ralph Cavanagh for being chosen to sit on the National Commission on Energy Policy. Hawk also shared
that two natural gas utilities in the Pacific Northwest were looking into decoupling approaches, a situation
that he found interesting given the context of these workshops.
PROPOSAL REVIEW
Performance-Based Mechanism Pilot
Susan Hayman distributed the draft proposal from Darlene Nemnich, Idaho Power, regarding the DSM
fixed-cost revenue recovery and performance incentive pilot. Nemnich reviewed the document, which is
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
included as Appendix 3. Essentially, Idaho Power proposes to use the Energy Star Homes Northwest
program for the pilot. This program, which is already included in the Integrated Resource Plan will be
implemented by three parties: the Northwest Energy Efficiency Alliance, Idaho Energy Division (a state
office), and Idaho Power. Idaho Power provides an incentive to a builder for meeting a standard set at
approximately 30% above existing Idaho residential building codes , lED qualifies that homes are built to
the standard and conducts quality assurance, and NEEA provides the builder outreach and training
components of the program. This program was started at a very small scale in 2003-2004 (30 to 40
homes), but this implementation of it is 10 times the size (430 homes).
Nemnich also reviewed how savings would be established and verified, how the fixed-cost revenue
requirement would be calculated , and then how the DSM incentive would be calculated. Establishing and
verifying savings would be a two-step process. At the beginning of the pilot, a review would look at
assumptions and identify original savings estimates based on engineering estimates derived from a 2004
Idaho Power study by Ecotope. The review group would also determine any studies to be conducted to
firm up uncertainty and get closer to validating savings by the end of the pilot. Evaluation costs would be
included in program costs but would not exceed 5% of these costs. The second step would be to do any
evaluations that the review group deemed necessary and determine the validated savings estimates. If
the validated savings estimates differed from the original savings estimates, a new cost-effectiveness
analysis would be completed and the program ended, modified , or extended. The validated savings
estimates would feed into calculations of the fixed-cost revenue requirement. Then DSM incentives could
be calculated. These incentives would be earned when at least 110% of the applicable DSM threshold
was met. She showed three possibilities for thresholds. Nemnich proposed that the pilot be conducted for
calendar year 2005. Validated energy savings and DSM incentives would be calculated by March 31
2006, and submitted to the IPUC for review. Then the total fixed-cost revenue requirement and incentives
could be collected from June 2006 through May 2007.
Following her explanation , she answered questions and addressed comments. Flipchart notes regarding
the discussion are included in Appendix 4. The following issues were raised during the discussion:
Calculation of incentive-The second threshold listed in the proposal should be "10%
-:::
target"
rather than "1 0% ~ target." Participants preferred the option for MWh reduction , with the threshold
being 10% greater than target and the incentive calculated as 10% of net annualized savings.
Persistence of the net benefit-Cavanagh suggested an approach that would enable evaluation of
the durability of savings. For example , Idaho Power could be paid 10% of the first year s annualized
savings, with an additional incentive paid at year three to reflect the annualized net benefit for the
additional 2 years of savings. It is important to verify that savings are ongoing and energy
improvements are still in place.
Maximum incentive-It may be beneficial to know the "maximum hit" and consider whether a cap is
needed. The incentive is a percentage so it can increase with additional success.
Effect to other OMS programs-The incentive might cause Idaho Power not to pursue other
programs as aggressively as it could. On the other hand, incentives are designed to motivate. If this
pilot works while other programs do not, it's safe to say that incentives work.
Basis for program budget-Incentives were not originally calculated into the program budget since
this program was already planned for implementation. Nemnich thought that the evaluation costs
could remain roughly the same, at $25 000.
Adequacy of existing building codes-To earn the $750 incentive, program participants have to
show that the house meets the prescriptive building standard. These codes are relatively new and
therefore hopefully adequate. However, enforcement is a problem , which is why utilities should be
involved. Their involvement through DSM programs provides incentives for builders to meet or
exceed code.
Inclusion of manufactured housing-The program as is may favor higher income households.
Inclusion of manufactured housing would likely broaden the economic scope of the program. Different
building codes .and standards apply to "stick built" homes than to manufactured homes. Nemnich
commented that another DSM program was aimed at manufactured homes. She will look into
combining the two programs for the pilot.
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Collaboration between the IPUC and Idaho Power-Much of the discussion focused on details that
need to be worked out for filing regarding the pilot program. Ric Gale, Idaho Power, suggested that
IPUC and Idaho Power. staff collaborate on the filing, work out the details , and e-mail the proposal for
review and comment.
True-Up Mechanism Simulation
Simulation Spreadsheet
Mike Youngblood distributed copies of two handouts: an Excel spreadsheet set up to simulate the fixed-
cost recovery true-up mechanism and a table showing fixed-cost lost revenue per MWh by customer
classes (Appendix 5). The first page of the Excel spreadsheet included those schedules of customer
classes that would be trued up according to customer counts, while the second page included those
customer classes trued up according to forecast sales in the IRP. On the first page, Youngblood had split
large commercial and small commercial because the total fixed-cost loss per MWH differed for these two
schedules (see the table in Appendix 5). Large commercial customers have demand meters in place and
a demand component in their bills. So more of the fixed costs associated with these customers are
captured somewhere besides variable costs. Cavanagh commented that Eddie s proposal trues up
demand revenues as well as kWh revenues. Youngblood agreed to think more about the issue of truing
up demand revenues.
Youngblood then explained how the simulation is set up. using residential customers on the first page and
industrial on the second page as his examples. Blue zeroes will eventually be substituted with real
numbers. On the first page, the actual customer count (column 2) is multiplied by $371.92 (fixed-cost
recovery per customer) to calculate the authorized fixed;.cost recovery (column 3). To calculate the actual
fixed-cost revenue recovered (column 5), weather-normalized energy (column 4) is multiplied by $30.
(fixed-cost recovery per MWh). Column 6 shows the difference between amounts in columns 3 and 5.
This is the amount of true-up. Actual customer count may be year-end or average, depending on which
approach was used in the rate case. Youngblood will look that up, although he used year-end customer
count for this spreadsheet.
For industrial and irrigation customers, forecasted energy (column 2) is multiplied by $2.44 (the fixed-cost
recovery per MWh) to calculate the allowed fixed-cost recovery. Once known , weather-normalized energy
use (column 4) is multiplied by the same amount to calculate the actual fixed-cost revenue recovered.
Again, the difference between columns 3 and 5 constitutes the amount of true-up needed. Although the
simulation was originally intended for 2005 , Youngblood included 2004 in the spreadsheet since those
numbers will soon be available (March 2005). Per Bill Eddie s proposal, he will include 1994 to 2004
numbers to see what would have happened to customers' rates over the last 10 years with a true-up
mechanism in place.
Simulation Proposal
Bill Eddie spoke about the proposal he had e-mailed to participants on behalf of the Northwest Energy
Coalition. The proposal is included in Appendix 6, while flipchart notes regarding the simulation are
included in Appendix 7.
The first page is a recap of information provided in earlier meetings. Cavanagh commented that truing up
demand charges is not explicit on this page but should be. The second page spelled out details of the
simulation. For item 2, they used the Northwest Power and Conservation Council number of about 0.
sales annually for assumed level of efficiency savings. Although that number is not accurate for 1994, it is
fairly close and can be applied retroactively. Item 4 identifies some parameters to analyze to illuminate
results of the simulation. Eddie said that other parameters could be looked at as well if people had ideas.
Items 5 and 6 are procedural in nature. He would like to see the retrospective analysis included in the
final report in January. Eddie added that he d like to see more frequent analysis of the true-up simulation
but given that only the year-end numbers would be "truth numbers " monthly checks may not be possible
or informative.
Don Reading asked how the simulation would account for the state s efforts at buying water and retiring
land. Eddie didn t believe that these actions would manifest during the simulation. The next IRP would
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
consider those activities in its forecasted sales. Anomalies will run through the system, and the simulation
may show the effects of these anomalies.
Eddie, Youngblood , and Cavanagh will refine the simulation proposal, run the retrospective analysis, and
send both out for review and comment in time for inclusion in the January report.
IPUC REPORTS
Status Report
Bart Kline, Idaho Power, provided copies of the redlined status report to the Idaho Public Utilities
Commission (Appendix 8). He commented that a word in the first full paragraph of page 2 ("believes ) will
be changed to "stated." Hayman added that numbered agreements listed in the "Progress" section have
been revised for wording only: the content is the same. Other changes include the following:
In the list of participants, Greg Said's affiliation should be identified as "Idaho Power.
Laura Nelson should be identified as "IPUC Advisor" or something rather than "IPUC Staff." The
Commissioners know that she is coming to the meetings, but she would like it clarified that she is not
entering into any agreements on behalf of the IPUC.
The document will be signed and ready for submission by Wednesday, December 15.
Final Report
At the December 1 workshop, Bill Eddie agreed to coordinate work on the final report. The deadline for
submission is January 31 , 2005. Eddie will e-mail the draft to participants two weeks in advance
(January 14) for review and comment. Participants reviewed the outline developed at the November 8
workshop (see Appendix 9). IPUC staff will help with the first section (history of the issue). The third
section (conclusions and recommendations) will have next steps and discuss the pilot and simulation.
Summaries of the workshops will be included to support the report. The filing for the proposed pilot
program will be submitted in mid-February, but the final report will "lay the groundwork" for the filing. Lo~b
agreed to see whether the Commissioners had any additional concerns that might need to be addressed
in a presentation.
NEXT STEPS
Follow-Up Workshop
Participants decided that no follow-up workshop is necessary for January. However, they tentatively plan
to meet again in midsummer to review the status of the pilot and simulation.
Monitoring Plan for Pilot and Simulation
Hayman asked that people forward ideas about evaluation and monitoring to those participants charged
with developing the final documents. She also reminded them about the evaluation criteria that the group
had developed at the December 1 workshop. For the simulation, monitoring means communicating
results to work group members. Ultimate conclusions from the simulation will be worked out in the rate
case.
WRAP-UP AND WORKSHOP EVALUATION
Hayman reviewed action items (Appendix 10). She also reviewed information in the bin: a couple of gas
utilities in the Northwest looking at decoupling and a suggestion to poll customers for their "appetite" for
conservation. Idaho Power is willing to let David Hawk provide details about such a poll.
Hayman also requested that participants evaluate the workshop series. She recorded what worked and
what concerns still exist (Appendix 11). For the most part, participants felt that the process worked well
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
members were open and honest, and more headway was made than people expected. People did feel
that this series of workshops was just the beginning, and efforts needed to continue into the future.
ApPENDIX 1-PARTICIPANTS
(Shading indicates work group participants unable to participate in person or by phone.
Name and Affiliation
Lynn Anderson, IPUC
Maggie Brilz, Idaho Power
Name and Affiliation
Laura Nelson, IPUC
Darlene Nemnich, Idaho Power
Peter Richardson, Industrial Customers of Idaho
Ralph Cavanagh, Natural Resources Defense
Council
Bill Eddie, Advocates for the West Don Reading, Ben Johnson Associates
Greg Said , Idaho Power
David Schunke , IPUC
Ric Gale, Idaho Power
David Hawk, J.R. Simplot Co.
Bart Kline, Idaho Power
Randy Lobb, IPUC
Tim Tatum, Idaho Power
Mike Youngblood , Idaho Power
Scott Woodbury, IPUC
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 2-AGENDA
ASSESSING FINANCIAL DISINCENTIVES AND
RESOLUTION OPPORTUNITIES
WORKSHOP #5
December 13, 2004
9:00am-12:00pm
Conference Room 6 East
Idaho Power Corporate Headquarters
Boise, Idaho
Objectives:
1) Review and finalize proposals for:
a. Refined true-up mechanism simulation
b. Performance-based mechanism pilot program
2) Finalize the status report for submission to the IPUC by December 15, 2004.
3) Determine the final report timelines and responsibilities
Final Agenda
(breaks will be taken when most convenient for the group)
Time Topic Process
8:45am CoffeelTea available in meeting room
9:00am Welcomellntroductions/Meeting Overview - Susan Hayman Information
9:15am Proposal Review Presentation
. True-up mechanism simulation - Mike Youngblood Discussion &
Decision
Performance-based mechanism pilot - Darlene Nemnich
Timeline and process for submission to IPUC - Idaho
Power
0:30am IPUG Reports Discussion
Update on the status report - Bart Kline
Final report preparation - Bill Eddie
Timelines
Responsibilities
11 :OOpm Next Ste ps Discussion
Follow-up workshop in January - Susan Hayman
Is it needed?
Monitoring plan for pilot and simulation - Group
When should this be prepared?
Who should be assigned this task?
11 :45pm Wrap-up and Evaluation - Susan Hayman Discussion
12:00pm Adjourn
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 3-D RAFT PilOT PROGRAM
DRAFT
Proposal for DSM Fixed-cost Revenue Recovery and Performance Incentive Pilot
12/13/04
Proposed Program for Pilot
The Energy Star Homes Northwest program is the program proposed to acquire
the resources identified in the Residential New Construction Option in the 2004 IRP and
is proposed as the program for this pilot. This program was developed by the EP A/DOE
the Northwest Energy Efficiency Alliance and PNW electric utilities. Idaho Power
piloted this program with the Alliance in 2004. There are three implementation partners
for this program in the Idaho Power service territory; the Alliance, Idaho Energy Division
(rED) and Idaho Power.
The essential feature of this program is a prescriptive building standard, also
called a builder option package or BOP, that is set at approximately 300/0 above existing
Idaho residential building codes. Idaho Power provides an incentive to the builder for
each home built to the standard and provides marketing for the program. lED qualifies
that homes are built to the standard and conducts a quality assurance process. The
Alliance provides the builder outreach and training components of the program.
Idaho Power s program budget for 2005 is $502,400
Estimated 2005 kWh savings is 1 070 000.
2005 participation estimated at approximately 430 homes.
Establishing and verifying savings
Original Savings Estimates
As close to the beginning of the pilot as possible, Idaho Power proposes to
establish an Original Savings Estimate. This estimate, measured in kWh per month per
qualified house, represents the estimated reduction in customer usage between a program
house and a non-program house. This estimate will be determined through a
collaborative, peer-review process. The Energy Efficiency Advisory Group or a sub-set
of the EEAG could be used for this purpose. Engineering estimates will be the primary
method for determining savings estimates. An engineering simulation study, conducted
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
for Idaho Power in early 2004 by Ecotope to estimate program savings in Idaho will be
used as a basis for the collaborative review.
This review group will also determine what assumptions should be tested, if any,
during or at the end of the pilot to validate the savings estimates. Cost-effectiveness of
the program will be calculated using these estimates. Evaluation costs of the pilot
program will be recovered by the DSM rider, will be included in the cost-effectiveness
calculation and will not exceed 50/0 of total program costs.
Idaho Power will review the program costs with the review group. Program costs
shall include the cost of planning, developing, implementing, monitoring and evaluating
DSM programs.
Validated Savings Estimates
At the end of the pilot period the collaborative review group will review any
evaluations compiled during or at the end of the pilot and determine a Validated Savings
Estimate per home. Total program savings will be determined by multiplying Validated
Savings Estimate per home by the actual program participation. If the Validated Savings
Estimates are different than Original Savings Estimates, a new cost-effective analysis will
be completed and the program may be ended, modified or extended.
Calculation of Fixed-cost Revenue Requirement
For the pilot period, the Validated Savings Estimates (in MWh) will be
multiplied by the total fixed-cost per MWh for purposes of determining the total fixed-
cost revenue requirement to be recovered. For this pilot the residential total fixed-cost
perMWh is estimated at $30. 14/MWh. Total fixed-cost revenue requirement will be
calculated using the Validated Savings Estimates irrespective of whether program goals
are met.
Calculation of DSM Incentive
DSM Incentives are earned by Idaho Power when at least 110% of the applicable
DSM threshold is met. Energy savings thresholds are calculated by multiplying the
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Original Savings Estimate by original participation goals in the calculation of an
incentive. There are three possibilities for this program:
Threshold Incentive
MWh reduction 10%:?target 10% of net $ savings
Idaho Power $/kWh 10%:?target 5% of program costs
Number of part.O%:?target 5% of program costs
The total fixed-cost revenue requirement and incentives will be quantified and
submitted for Commission review in a time frame that allows for collection during a 12-
month June 2006 through May 2007 timeframe.
Timeframe for Pilot
Idaho Power proposes the pilot timeframe be calendar year 2005. Determination
of Original Savings Estimate will be determined soon after approval of this pilot by the
Idaho PUC. Determination of Validated Energy Savings, fixed-cost revenue requirement
and DSM Incentive will be calculated by March 31 2006.
ApPENDIX 4-FLIPCHARTS REGARDING THE PILOT PROGRAM
Pilot Program Discussion
1) What is expected payment and max payments?
2) How much incentive is paid , and how much fixed
costs recovered. This is focus of pilot. Cost
effective is considered too.
3) For pilot, incentive % is fixed , but payments based
on total savings.4) Incentives are included in program budget
($750/home)-much of program budget is
devoted to builder incentives.
Refinements to Pilot Proposal
1) First incentive
Pay 10% of first year s annualized savings
then 3-year evaluation again to test
persistence of program (2 payments in this
scenario)
Base payment on a single point in time
year period between rate cases could be
used to true-up fixed cost recovery
Refinements to Pilot Proposal (cont.)
2) Include manufactured housing in with "stick
built"though codes not the same , still incent to
build above code (look at 2 different validated
estimates, etc.
3) IPC-IPUC staff will work to refine incentives , and
look at durability incentive-joint application
Summary of the December 2004, Workshop
Assessing Financial Di$incentives and Resolution Opportunities Workshop
ApPENDIX 5-DRAFT SIMULATION SPREADSHEET
Fixed Cost Lost Revenue per MWh by Customer Class
Base Rate Components ($/MWh)
Small Large
Residential Commercial.Commercial"Irri ation Industrial.**
Total Base Energy Rate
(b+c+d+e)(a)$51.$62.$26.$32.$21.45
Variable Cost - Class (b)$20.$21.$20.$23.$18.41
Variable Cost - Subsidy (c)$1.$1.25 $0.($5.72)$0.
Fixed Cost - Class (d)$28.$38.$4.48 $22.$1.
Fixed Cost - Subsidy (e)$1.$1.$0.($7.33)$0.
Total Fixed Cost Loss/MWh
(d + e)(f)$30.$40.$5.47 $14.$2.44
) Small Commercial rate is schedules 07
(*.
) Large Commercial rate is a wghtd. avg. of schedule 09 S, P & T based on energy use.
(*..
) Industrial rate is a wghtd. avg. of schedule 19 S, P & T based on energy use.
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Fixed Cost Recovery True-up Mechanism
(Simulation for Case No. IPC-O4-15)
RESIDENTIAL
Rate Case Constants:
141 393 Energy
335 605 Customers
$124 816 934 Class Fixed Costs
$371 .92 Fixed Cost Recovery per Customer
$30.14 Fixed Cost Recovery per MWH
Allowed Fixed Actual Fixed
Cost Recovery Weather Cost
Actual Customer Based on Actual Normalized Revenue Amount of
Year Count Customer Count Energy (MWH)Recovered True-
(1 )(2)(3)(4)(5)(6)
2003
2004
2005
335,605 $124 816 934 141,393 $124,816,934
~AI..Lp~:M~J.~I:..
. . '
Rate Case Constants:
265 336 Energy
32,316 Customers
$10,694 989 Class Fixed Costs
$330.95 Fixed Cost Recovery per Customer
$40.31 Fixed Cost Recovery per MWH
Allowed Fixed Actual Fixed
Cost Recovery Weather Cost
Actual Customer Based on Actual Normalized Revenue Amount of
Year Count Customer Count Energy (MWH)Recovered True-
(1 )(2)(3)(4)(5)(6)
2003
2004
2005
32,316 $10,694 989 265,336 $10,694,989
dJ\%IM'A'
...
!IJ 'D.
"'-
:i~R..'r-
..",,"
W.
". .
i~.~SJ::!'j\,~..
:.;+, .
I:::o:;.J!::,~I'\:.I:I:
Rate Case Constants:
3p14,427 Energy
17,415 Customers
$16,499 592 Class Fixed Costs
$947.44 Fixed Cost Recovery per Customer
$5.47 Fixed Cost Recovery per MWH
Allowed Fixed Actual Fixed
Cost Recovery Weather Cost
Actual Customer Based on Actual Normalized Revenue Amount of
Year Count Customer Count EnerQV (MWH)Recovered True-
(1 )(2)(3)(4)(5)(6)
2003
2004
2005
17,415 $16 499 592 014,427 $16,499,592
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Fixed Cost Recovery True-up Mechanism
(Simulation for Case No. IPC-O4-15)
INDUSTRIAL
Rate Case Constants:
1 ,978 824 Energy
105 Customers
821 154 Class Fixed Costs
$45 916 Fixed Cost Recovery per Customer
$2.44 Fixed Cost Recovery per MWH
Actual Fixed
Cost
Revenue
Recovered
(5)
Amount of
True-
(6)
Year
(1 )
2003
2004
2005
978 824
035 043
104 294
$4,821,154
$4,958,125
$5,126,846
978,824 821,154
958 125
126 846
IRRIGATION
Rate Case Constants:
620 931 Energy
517 Customers
$23 925 859 Class Fixed Costs
770 Fixed Cost Recovery per Customer
$14.76 Fixed. Cost Recovery per MWH
owe axe
Forecasted Cost Recovery Actual Fixed
Energy from 2004 Based on Weather Cost
IRP Forecasted Normalized Revenue Amount of
Year (MWH)Energy Energy (MWH)Recovered True-U p
(1)(2)(3)(4)(5)(6)
2003 620,931 $23 925,859 620,931 $23,925,859
2004 670 717 $24,660,729 $24 660 729
2005 677 923 $24 767,100 $24 767 100
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 6-DRAFT TRUE-UP SIMULATION PROPOSAL
PROPOSAL FOR SIMULATION OF AN IDAHO POWER TRUE-
MECHANISM
Submitted by Bill Eddie, Ralph Cavanagh, Nancy Hirsh
For discussion at 12/13/04 workshop
Per the discussion at the December 1 2004, workshop,NRDC and NWEC propose the
following simulation to illuminate impacts of the revised true-up mechanism proposed by
NRDC and NWEC.
Recap of true-up. The key points of the revised true-up mechanism proposal are:
1. Starting point is fixed-cost revenue requirement and retail rates approved by
Idaho PUC in latest Idaho Power rate case.
2. For the Industrial and Agricultural sectors, until reestablished in the next Idaho
Power rate case, the currently approved fixed cost revenue requirement would be
automatically adjusted annually to reflect the same rate of increase (or decrease)
shown for retail electricity sales, net of any DSM programs, in Idaho Power latest
IRP.
3. For the Residential and Commercial sectors, until reestablished in the next Idaho
Power rate case, the currently approved fixed cost revenue requirement would be
automatically adjusted annually to reflect the actual changes in annual customer count
for the residential and commercial sectors (in other words, the fixed cost revenue
requirement per customer would remain fixed until the next rate case).
4. True ups would occur annually by customer class based on any divergence
between the total fixed-cost revenue recovery that forecast sales (for Agricultural and
Industrial sectors) or actual customer growth (for Residential and Commercial)
would have delivered versus the fixed-cost revenues actually recovered through
actual sales.
5. Idaho Power would continue to absorb the risk or benefits of purely weather-
related effects on fixed-cost revenue recovery, as it does now. This would mean
weather normalizing actual sales before making the annual true-up calculation.
6. The maximum annual average rate impact of the true up mechanism for any
customer class would be capped at 2% annually, with any additional amounts carried
over to the next year s true up.
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Proposed simulation. The proposed simulation would study this mechanism both
retrospectively (1994-2004 rate case) and prospectively (2004-next rate case):
1. Starting points are the fixed-cost revenue requirement and retail rates approved in
the 1994 and 2003-04 rate cases, including subsequent Commission-approved
adjustments to such revenue requirements.
2. Apply an assumed level of efficiency savings of 0.50/0 annually (roughly
equivalent to the level of savings achievable in Idaho Power s territory per the NW
Power Planning Council's draft 5th Plan) each year starting in 1994 and 2004. For
simplicity, efficiency savings can be zeroed-out after the 2003-04 rate case.
3. Load forecasts for agricultural and industrial sectors will change with each IRP
issued throughout the simulation periods.
4. Simulation should calculate the true-up mechanism s impacts in the following
aspects: (1) annual rate impact to each customer class for the true-up alone, and the
true-up together with the PCA; (2) annual and total impact to average customer bill
amounts (assuming the 0.5% annual efficiency savings and the annual net benefit
estimates developed in the recent Quantum consulting energy efficiency assessment),
(3) total impact to IdaCorp shareholders if true-up mechanism were not in place.
5. Idaho Power will provide the results of the retrospective simulation to the
workshop participants so they may be included in the final report to the Commission
regarding this workshop proceeding. Idaho Power will provide the results of the
prospective simulation to workshop participants and the Commission
contemporaneously with each annual PCA filing.
6. Idaho Power will work with workshop participants as they prepare their next rate
case tiling to analyze the results of the simulation and evaluate incorporation of a
true-up mechanism into the rate filing.
ApPENDIX 7-FLIPCHARTS REGARDING THE TRUE-UP SIMULATION
Simulation
1) Would use same method of determining customer
counts as in the last rate case (residential and
commercial)
2) Suggest including 2004 figures with 2005 figures
in simulation
3) NWEC proposal includes demand and kWhcharges
4) Simulation will also test anomalies that occur in
next year
5) Testing period
1994-2000 (back)
2004-next rate case (about 18 months)
(forward)
Both for actualized (IRP) and NWPPC
projections
Also look at 1994-2004 period
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX a-DRAFT STATUS REPORT
.- ---..-.-- -.------...- - .-..--.---.-.----...-.-----------...-.---.-.. -..--- --.---- -. --. --.-.- -....-------..--.---- - -. -.... -. -.-
BARTON L. KLINE ISB #1526
Idaho Power Company
D. Box 70
Boise, Idaho 83707
Phone: [phone]
FAX: [phone]
Attomey for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
OF FINANCIAL DISINCENTIVES TO
INVESTMENT IN ENERGY EFFICIENCY BY
IDAHO POWER COMPANY
INVES TIGATIVE
WORKSHOP
STATUS REPORT
CASE NO.IPC- E-04-
BACKGROUND
On May 25, 2004, The Idaho Public Utilities Commission (Commission) in Order No.
29505 (Idaho Power Company general rate case No. IPC-03-13) determined that a separate
proceeding to assess financial disincentives inherent in Company-sponsored conservation
programs is appropriate and should proceed by informal workshops." The Commission s Order
provided in relevant part as follows:
The Commission specifically directs the parties (Idaho Power, NW Energy
Coalition, Industrial Customers of Idaho Power (ICIP) and Commission Staft) 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) pelformance-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
INVESTIGATIVE WORKSHOP STATUS REPORT, Page
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
benefits gained from efficiencies, especially technologies... In short, the
Commission believes 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 aH/orkshop schedule and initiate a proceeding. (emphasis
added)
Order No. 29505 at pp. 68, 69.
As a follow up to the Commission s Order, the NW Energy Coalition on June 18, 2004
formally requested that a proceeding be initiated and that a workshop schedule be established.
The Commission in Order No. 29558 established this docket to investigate the financial
disincentives which hinder Idaho Power s investment in cost-effective energy efficiency
resources. The Commission believes that the scope of the investigation should be focused on
decoupling and performance based ratemaking. The Commission directed the participating
parties to provide a written report to the Commission no later than December 15, 2004 to update
the Commission on the status of the investigative workshops.
PROCESS
The parties have participated in five fettf workshops to date: August 24, September 27
November 8, aR4-December 1 2004, and December 13 2004. These workshops have included
presentations by participants, group discussion, and sensing for areas of agreement and
disagreement. Workshops are designed and facilitated by Susan Hayman, North Country
Resources, Inc., a Boise-based facilitation/mediation firm. Workshops are designed in
cooperation with four designated workshop coordinators representing each of the four major
interests at the table (Idaho Power Company, Idaho Public Utilities Commission Staff, Industrial
Customers of Idaho Power, and Northwest Energy Coalition). Copies of all workshop
summaries are provided as attachments to this Status Report.
PARTICIPANTS
The following people have attended one or more workshops, receive meeting materials
and summaries, and are considered active workshop participants:
INVESTIGA TlVE WORKSHOP STATUS REPORT, Page 2
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
Name and Affiliation Name and Affiliation
Lynn Anderson, IPUC Staff
Maggie Brilz, Idaho Power
Terri Carlock, IPUC Staff
Ralph Cavanagh, Natural Resources Defense
Council
Bill Eddie, Advocates for the West
Ric Gale, Idaho Power
David Hawk, J.R. Simplot Co.
Nancy Hirsh, NW Energy Coalition
Bart Kline, Idaho Power
Randy Lobb, IPUC Staff
Laura Nelson, IPUC Staff
Darlene Nemnich, Idaho Power
Peter Richardson, Industrial Customers of Idaho
Brad Purdy, Community Action Partnership
Associ ation of Idaho
Don Reading, Ben Johnson Associates
Greg Said, TPC
David Schunke, IPUC Staff
Tim Tatum , Idaho Power
Mike Youngblood, Idaho Power
Scott Woodbury, IPUC Staff
PROGRESS
Since the inception of the workshops on August 24, participants have reached the
following agreements:
1) Agreed on a set of operational principles that guide the workshops.
2) Clarified the nature and extent of financial disincentives to Idaho Power for
investment in energy conservation through demand-side management programs
(DSM).
3) Agreed that material financial disincentives do exist and ~viU increase as PSJ'vl
expenditures increase. ,though nNot all participants agree that restoration of lost
fixed cost revenues would directly result in additional investment in DSM programs
by Idaho Power.
4) Agreed on a set of evaluation criteria by which to compare and contrast potential
mechanisms for removing financial disincentives and/or providing incentives for
DSM programs.
5) Agreed to continue exploring two specifically proposed mechanisms: A true-up
mechanism (referred to as a decoupling mechanism in early workshops) and a
performance-based incentive mechanism.
6) Agreed to design a true-up mechanism simulation and a pilot program performance-
based incentive mechanism to evaluate the effects of these two mechanisms. The
INVESTIGATIVE WORKSHOP STATUS REPORT, Page 3
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
simulation and pilot program win be the subject of further review and discussion at
the next workshop.
TIMELINE
Participants established the following timeline at the December 1 workshop:
1) Provide this a-status report to the Commission on or before December 15, 2004, as
specified in Order No. 29558.
2) Provide a full report to the Commission no later than January 31, 2005, including
participant recommendations and rationale.
This Status Report to the Commission has been reviewed and approved by Idaho Power
Company, Northwest Energy Coalition, the Commission Staff and the Industrial Customers of
Idaho Power.
Date Barton L. Kline
Attorney for Idaho Power Company and on behalf
of Northwest Energy Coalition, the Commission
Staff and the Industrial Customers of Idaho PO\ver
ApPENDIX 9-FLIPCHARTS REGARDING THE FINAL REPORT
Commission Report
January 31 Deadline-Bill Eddie Lead
History of issue that generated work group (with
help from IPUC staff)
II.What did the workgroup do?
Studies undertaken
Mechanisms proposed
Results of investigation
III. Conclusions and recommendations
Schedule/timeline fqr addressing pilot and
simulation findings-final recommendations
IV. Figures and tables, studies , workshop summaries
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 10-FLIPCHARTS REGARDING NEXT STEPS AND ACTION ITEMS
Next Steps
1) If Randy gets feedback from Commissioners that
there is something of concern, Randy will let the
workgroup know-could possibly meet with them
as a group
2) Possible mid-summer workgroup check-in (TBD)
Action Items
What Who When
1) IPC-IPUC staff will
prepare pilot
application and
circulate for review
and comment (include
monitoring
mechanism)
Lynn-February
2) IPC and NWEC refine
simulation proposal
(and retrospective
analysis) for review
and comment by
workgroup (include
monitoring mechanism
for March)
Mike, Bill
Ralph
January
Bin
1) Gas utilities -7 decoupling mechanism2) Still interested in evaluation customer "appetite
for conservation at higher levels. (David Hawk to
bring proposal to I PC)
Action Items
What Who When
Draft final report to Bill January
workgroup by mid-
January for R&C
File pilot application IPC Mid-
with IPUC February
Summary of the December 2004, Workshop
Assessing Financial Disincentives and Resolution Opportunities Workshop
ApPENDIX 11-FLIPCHARTS REGARDING THE WORKSHOP SERIES
What's Worked
1) Open , honest
discussion and
bringing to table
2) Quality of recordir;1g-
capturing essence of
meetings
3) Appreciate
organization of
meetings/tracking
what happened
quality of info
presented
4) Very successful
workshop
5) Facilitation helpful
6) Interchange
forthright-advanced
issue further than
thought we would
Outstanding What's Worked Outstanding
Concerns Concerns
Feels like we Pleased with results Language in
have just of workshop order about
begun-need to Good solution PBR" that we
take next steps reached fairly quickly didn t get to.
seriously-need with good deliberation Hope it meets
to accomplish Appreciated everyone needs of
something Commissioners
together attending Easy to do pilots
Need to monitor 1 0) Appreciated and simulation-
and carefully openness of everyone hope we have
evaluate results-to hear other enough
issue IS not perspectives information to
dropped 11) Always ha9 goals in make follow-up
sight-,..-felt movement decisions
and progress towards Being able togoalscapture how we
12) Impressed with us all!really will
Came a long way.evaluate these
things as we go
along-ability to
modify evaluation
criteria
What's Worked Outstanding
Concerns
13) IPC participation and
get numbers out that
people could
understand
14) Not everyone got
what they wanted , but
lots accomplished
15) Candid discussion
16) Appreciate IPC going
along with this in a
positive way
17) Ralph and Bill'
analysis and numbers
6) What
Commissioners
will say about the
group s work/
agreements
(curious)7) Establishing
program
evaluation criteria8) Proof is in the
pudding
9) Building codes/
enforcement
What's Worked Outstanding
Concerns
18) Group has had form
and substance
19) Frank and fair
20) Possible solution to
issue, and
conservation as a way
to get at issue
21) IPC collaborative
involvement
10) Asking IPC to do
additional things
to an already "full
plate
11) Look for results to
sell" process
Summary of the December 2004, Workshop