20041207Tatum Exhibits.pdf

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Idaho Public Utilities Commission
, Office of the Secretary -
RECEIVED
DEC - 6 2004
Boise. Idaho
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
IDAHO POWER COMPANY
CASE NO.IPC-O4-
EXHIBIT NO.
T. TATUM
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1
Idaho Public Utilities Commission
Office of the SecretaryRECEIVED
DEC - 6 200~
Boise, Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY
CASE NO.IPC-E-04-
EXHIBIT NO.
T. TATUM
DSM Program Development. The demand-side resource options were developed using
a combination of internal engineering estimates and external consulting services. The
residential and commercial program options were designed by Quantum Consulting of
Berkeley, California, and Idaho Power s engineering staff developed the remaining
programs. Each of the energy efficiency programs were designed to maximize the
potential energy benefits of the resource while remaining cost-effective from' a total
resource perspective. The demand response options were designed to maximize the load
impact achieved while remaining cost-'effective from the utility s perspective. During this
process, two to four program levels were developed to allow for the determination of the
optimum program level to be included in the IRP.
The demand-side management options were all designed using similar cost components.
The demand response options include some additional costs not contained in the energy
options due to the need for ongoing operation of the programs by the utility. Each of the
energy and demand response program options contain the following cost components:
Administrative costs
Marketing and advertising costs
Incentive or rebate payments
Participant costs
The demand response program cost structure contains the following additional costs not
included in the energy program options:
Capital costs
Operating and maintenance costs
Increased supply costs (resulting from the energy shifted from on-peak to off-
peak periods)
Once the program design phase was completed, each new program was put through a
series of static screening analysis prior to being included in the IRP dynamic portfolio
analysis.
Screening Criteria. The DSM screening criteria were designed to assess a program
potential to maximize benefits at the lowest cost for all stakeholders.
There are four general categories of criteria taken into consideration when looking at
selecting DSM programs.
Programs will be cost-effective. From a total resource perspective, estimated
program benefits must be greater than estimated program costs. As shown by the
2002 Idaho Power Integrated Resource Plan, programs that decrease summer peak
demand will be valuable because they reduce the need for new peak resources.
Programs that capture cost-effective, lost-opportunity DSM resources will be
encouraged.
Exhibit No.
Case No, IPC-O4-
T. Tatum , IPCo-Dir
Page 1 of 9
Programs will be customer-focused. From the participants' perspective,
programs will offer real benefits and value to customers. The Idaho Public
Utilities Commission stated in Order No. 29026, "It is our hope that the programs
created by the DSM rider will empower customers to exercise control over their
energy consumption and reduce their bills.
Programs will be equitably distributed. From the customers' perspective,
programs will be selected to benefit all groups of customers. Over time, programs
will be offered to customers in all sectors and in all regions of the company
service tenitory.
Programs will be as close to earnings-neutral as possible. From the utility
perspective, programs will be selected to minimize the negative impact on
shareowners.
These criteria are used as guidelines in selecting a new program or initiative. A program
that doesn t meet all of these criteria is not excluded from consideration, but would have
to be further evaluated for other valued characteristics. Ultimately, all programs must be
cost-effective in order to be considered as ordered by the IPUC.
Static Cost-Effectiveness Analysis: The cost-effectiveness analysis is the primary focus
of the screening criteria. The static cost-effectiveness analysis of DSM programs at Idaho
Power is performed using the methods described in the EPRI End-Use Technical
Assessment Guide Manual as well as The California Standard Practices Manual:
Economic Analysis of Demand-side Programs and projects.2 The proposed DSM
programs considered for inclusion into the 2004 IRP are evaluated from Utility Cost Test
and Total Resource Cost test perspectives.
Total Resource Cost Test (TRC)
The TRC test is a measure of the total net resource expenditures of a DSM program from
the point of view of the utility and its ratepayers as a whole. Costs include changes in
supply costs , utility costs, and participant costs. (Transfer payments between ratepayers
and the utility are ignored).
The following are the calculations performed by this test:
Net Present Value: A net present value of zero or greater indicates that the
program is cost-effective from the total resource cost perspective.
~ Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is
cost-effective from the total resource cost perspective.
Levelized Cost: This measurement makes the evaluation of potential demand-side
resources comparable to that of supply side resources. The cost stream of DSM
resource (in this case, the stream of utility costs and participant costs) is
1 IPUC Order No. 29026, May 20, 2002
2 http://www ,cpuc .ca, gOY / static/industry /electric/ energy+efficiency /rulemakinglresource5 ,doc
3 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals and Methods,
Barakat and Chamberlin, Inc, April 1991
Exhibit No, 6
Case No. IPC-04-
T, Tatum , IPCo-Dir
Page 2 of 9
discounted and then divided by the stream of discounted kW or kWh that is
expected from the program.
Utility Cost Test
The Utility Cost test is a measure of the total costs to the utility to implement a DSM
program.
The following are the calculations performed by this test:
Net Present Value: A net present value of zero or greater indicates that the
program is cost-effective from the Utility Cost perspective.
~ Benefits-Cost Ratio: A benefit-cost ratio of 1.0 or greater indicates the program is
cost-effective from the Utility Cost perspective.
Levelized Cost: This measurement attempts to put demand side resources on
equal ground with supply-side resources. As with supply-side resources, the cost
stream of DSM resource is discounted and then divided by the stream of kW and
kWh that is expected from the program.
DSM Analysis Calculation Definitions:
Net Present Value:Calculated as the discounted stream of program benefits
minus the discounted stream of program costs using the Company s weighted
average cost of capital (W ACC) for resource planning.
Program Benefits (minus) I Program Costs
T=l (1+ W ACC) t-T=l (1+ W ACC) t-
Where: N = the total number of years , t = the incremental year, and W ACC = the
Company s weighted average cost of capital.
Benefits-Cost Ratio:Calculated as the discounted stream of program benefits
divided by the discounted stream of program costs.
Program Benefits
t=l (1+ W ACC) t-
...
Program Costs
t=l (1+ W Accf-
Levelized Costs:The present value of total costs of the resource over the
life of the program in the base year divided by the discounted stream of
energy or demand savings, depending on how the resource size has been
defined.
4 EPRI End-Use Technical Assessment Guide (End-Use TAG), Volume 4: Fundamentals and Methods,
Barakat and Chamberlin, Inc, Apri11991
Exhibit No.
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 3 of 9
Program Costs
T=l (1+ W ACC) t-
...
Energy Savings
T=l (1+ W ACC) t-
Discounted Payback:Number of years from the initial program participation
to the point at which the cumulative discounted benefits exceed the
cumulative discounted costs for participants. (Usually calculated for an
average customer who joins the program in its 1st year)
Undiscounted Payback:Number of years from the initial program
participation to the point at which the cumulative undiscounted benefits
exceed the cumulative undiscounted costs for participants.
Free riders : Program participants that would have implemented the energy
efficiency measure without the program or incentive.
Incremental Costs:The additional cost incuITed by choosing to select one
option over another.
Total Installed Cost of Energy Efficient Option
Total Installed Cost of a Non-Energy Efficient Option
= Incremental Cost
To quantify the "benefit" portion of the calculation , five costing periods were created for
the year that are consistent with the proposed industrial time-of-use rate pricing periods
Each costing period contains a price that reflects the alternative cost of energy and
capacity at the associated time period. The alternative cost represents the cost of energy
resources that would most likely be the alternative at that time period. Each time segment
has a different alternative cost associated with it depending on the expected price for that
period.
The following is tables are illustrate the time of day and time of year costing period
definitions used in the static program screening analysis:
5 General Rate Case No. IPC-O3-13,Exhibit No.
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 4 of 9
June 01- August
SOFP = Summer Off-Peak
SMP = Summer Mid-Peak
SONP = Summer On-Peak
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SOFP" 'SaFE' 'SQRP ,: " S()FP"S0FR ,SORB 'SCTI)FP'
8MP" 8MP "8MP 'SMP SMP "SMP SMR
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SOFP 'SOFP SOFP "SOEP "SOFP SQFP ':SOFP"
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 5 of 9
September 01 - May31
NSOFP = Non-Summer Off-Peak
NSMP = Non-Summer Mid-Peak
Jo...
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Forward market prices are used for the segmented alternative cost periods in all periods
except in the "Summer On-peak" period. Forward market prices are forecasted in two
categories
, "
heavy load" and "light load". The heavy load and light load prices are
forecasted by month for 10 years . For measures with lives beyond ten years, the forecast
is extended by escalating the final year of the forward market price schedule for the
additional years needed for the analysis using the Company s escalation rate for capital
investments.
, '. ,; ," '...,, '.'
i1)i::
. '. ~
. i'
6 The forward price curve was taken from the 2002 Idaho Power Integrated Resource Plan,
Exhibit No, 6
Case No. IPC-04-
T. Tatum, IPCo-Dir
'-'---
c: ,..4= Q
The costing period prices are calculated using the following method:
.:.
NSMP = Average of heavy load prices in Jan. - May. And Sept. - Dec.
.:.
NSOFP = Average of light load prices in Jan. May. And Sept. - Dec.
.:.
SOFP = Average of light load prices in Jun. - Aug.
.:.
SMP = Average of heavy load prices in Jun. - Aug.
.:.
SONP = Idaho Powers variable energy cost of a 162MW Simple Cycle
Gas Turbine plus the marginal capacity cost of that Gas Turbine in
$/kW/Year.
The benefit values for the AlC Demand Response and Irrigation Demand Response
programs were calculated under the assumption that these programs will result in no
energy savings. It was assumed that the energy saved during the down time would be
shifted from the high price summer on-peak time period to the lower price summer mid-
peak time period.
The following table shows the schedule of alternative costs used to calculate the benefit
value of each program in the static analysis:
Year
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
68.
70.
71.
73.
75.
77.
79.45
81 .45
83.
85.
87.
89.
92.
94.
96.
99.40
101.
104.47
1 07.1 0
109.
SMP
$ 35.
$ 36.
$ 37.
$ 68.
$ 73.
$ 76.
$ 79.
$ 82.
$ 84.
$ 86.
$ 88.
$ 90.
$ 93.
$ 95.
$ 97.
$ 100.
$ 102.
$ 105.
$ 108.
$ 110.
SOFP
$ 29.
$ 29.
$ 30.
$ 35.
$ 36.
$ 37.
$ 38.
$ 39.
$ 40.
$ 41.
$ 42.
$ 43.
$ 44.
$ 45.
$ 47.
$ 48.
$ 49.
$ 50.
$ 52.
$ 53.
, ," ,.... '..,...... ,.. ,.. ..,""'.. .. ..',.... ..,.., ,
NSM,
$ 34.
$ 35.
$ 36.
$ 37.
$ 40.
$ 40.
$ 42.
$ 45.
$ 47.
$ 48.
$ 49.
$ 50.
$ 51.
$ 53.
$ 54.
$ 56.
57.41
$ 58.
$ 60.
$ 61.
$ 28.
$ 29.
$ 29.
$ 30.
$ 32.
$ 34.
$ 35.
$ 37.
$ 38.
$ 39.
$ 40.
41 .
$ 42.
$ 43.
$ 44.
$ 45.
$ 46.
$ 47.
$ 49.
$ 50.
Exhibit No.
Case No, IPC-04-
T, Tatum, IPCo-Dir
Page 7 of 9
Year SMP SOFP
2004 $ 59.$0.$0.$0.$0.
2005 60.$0.$0.$0.$0.
2006 $ 62.$0.$0.$0.$0.
2007 $ 63.$0.$0.$0.$0.
2008 65.$0.$0.$0.$0.
2009 67.$0.$0.$0.$0.
2010 68.$0.$0.$0.$0.
2011 70.44 $0.$0.$0.$0.
2012 $ 72.$0.$0.$0.$0.
2013 $ 74.$0.$0.$0.$0.
2014 $ 75.$0.$0.$0.$0.
2015 $ 77.$0.$0.$0.$0.
2016 $ 79.$0.$0.$0.$0.
2017 81.$0.$0.$0.$0.
2018 83.$0.$0.$0.$0.
2019 85.$0.$0.$0.$0.
2020 88.$0.$0.$0.$0.
2021 $ 90.$0.$0.$0.$0.
2022 $ 92.$0.$0.$0.$0.
2023 $ 94.$0.$0.$0.$0.
Notes:
1 IPCo Variable Energy Cost includes fuel and O&M for a 162MW Simple Cycle CT.
(Calculated on "Gas Worksheet"
2 The Market Price Forecast includes capacity cost. (Refer to "Electric Prices" for detail)
3 Escalation rate is 520/0 as stated in the 2002 IRP.
4 Time of Day segments are defined on the "TOO Segments" worksheet.
For all energy programs it is assumed that the energy savings will continue beyond the
measure life time period for each program participant. It was felt that it is reasonable to
assume that once a person participates in the program, they will not revert back to a less
efficient behavior after the measure life expires. As a result, the energy savings schedule
for each program shows a ramp-up period followed by a sustained maximum level for the
entire analysis period.
Dynamic Modeling. The programs that were determined to be cost effective using the
static analysis were then put through the Aurora dynamic modeling process to detennine
the impacts to the overall resource portfolio. The hourly energy savings associated with
each program was valued within the Aurora simulation model. The model output is the
present value dollar impacts to the overall resource portfolio revenue requirement. If the
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 8 of 9
present value reduction of overall revenue requirement exceeds the present value
program costs, the program is determined to be cost effective.
The two demand response options were analyzed outside of the Aurora model due to the
complexity of modeling the hourly load reduction of a time constrained resource. The
two demand response programs were analyzed using the static analysis and shown to be
cost-effective. These two programs were also compared against the other supply-side and
demand-side options using a 30-year levelized cost measurement. The two programs
were among the lowest levelized costs of all the portfolio resources and were selected
based on those criteria.
Exhibit No.
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 9 of 9
Idaho Public Utilities Commission
Office of the Secretary
RECEIVED
DEC - 6 2004
Boise, Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY
CASE NO. IPC-E-04- 2!L
EXHIBIT NO.
T. TATUM
Program
Description
Program Size
Description
Irrigation Efficiency Program
This program is designed to reduce peak demand and energy of irrigation customers. The
program is targeted at all customers in Rate 24. Idaho Power will pay customers direct
incentives for modifications to existing or new irrigation systems, Incentives will be based on
kW or kWh savings, Measures eligible for incentive payments include low-pressure pivot or
linear packages, larger mainline to reduce friction loss, variable speed drives, and high
efficiency motors, Marketing and education will be accomplished through direct mail pieces
irrigation workshops and articles in irrigation publications, The primary ramp up of this
program takes place in the first five years. Idaho Power has been operating a small-scale
version of this program since the fall of 2003.
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
Seasonality
Dispatchability
Target Market
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (10 Years)
Net Benefits
Benefit/Cost Ratio
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial 30-Year ($/Peak kW/Mo)
28.
668
Summer Only
All Irrigation Customers
2005
Utility Cost
Test
$90,690
$18,257
$72 433
$0.039
$6.
Total Resource
Cost Test
$90,690
$24 053
$66,637
$0.051
$8.
Exhibit No.
Case No, IPC-04-
T. Tatum, IPCo-Dir
Page 1 of 8
Program
Description
Program Size
Description
Industrial Efficiency Program
This program is designed to reduce peak demand and energy of large industrial and
commercial customers. The program is targeted to all new and existing Rate 19 and Rate 09
customers with a basic load capacity of 500 kW or greater. Idaho Power will provide direct
incentives and assist with audit costs. Incentives will be based on kW or kWh savings.
Measures eligible for incentive payments include refrigeration efficiency, variable speed
drives, lighting and control upgrades. Potential marketing and education activities include
direct mail pieces, newsletters, demonstrations of efficient technologies, workshops, case
studies and articles in industrial publications, Idaho Power will leverage the industrial efforts
of the Northwest Energy Efficiency Alliance to enhance participation. Idaho Power has been
operating a small-scale version of this program since the fall of 2003.
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
10.
12.
265
Seasonality
Dispatchability
Target Market
Summer Focus
Industrial Customers w/BLC
:::-
500 kW
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
Utility Cost
TestCosts and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (10 Years)
Net Benefits
Benefit/Cost Ratio
$79,324
$15,348
$63,976
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial 30-Year ($/Peak kW/Mo)
$0.020
$12.
Total Resource
Cost Test
$79,324
$24,413
$54 911
$0.032
$20.
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 2 of 8
Commercial Efficiency (New Construction)
Program
Description This program is designed to reduce peak demand and energy of new commercial customers
in Rate 07 and Rate 09. T~is program targets new commercial building owners/developers
and architects/engineers, Energy efficiency information, access to technical and financial
resources, and linkages to other relevant information sources are included. The focus is on
business and technical assistance, entering the design and construction process early on to
influence initial design considerations and equipment selection. Information on building
design and construction best practices will be provided. Financial incentives can include cash
rebates or customer incentives. High profile demonstration projects can be used to prove the
viability of energy efficient changes in design and construction practices. Idaho Power will
leverage the efforts of the Northwest Energy Efficiency Alliance Commercial Program Initiative
to enhance participation,
Program Size
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)605
Description
Seasonality
Dispatchability
Target Market
Summer Focus
Commercial New Construction
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (10 Years)
Net Benefits
BenefiVCost Ratio
Utility Cost
Test
Total Resource
Cost Test
$19,309
$3,788
$15,521
$19,309
$5,027
$14 282
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial 30-Year ($/Peak kW/Mo)
$0.051
$10.
$0.068
$14.
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 3 of 8
Commercial Efficiency (Existing Construction)
Program
Description
This program is designed to reduce peak demand and energy of commercial customers on
Rate Schedules 07 and 09. Although a firm program design has not been determined, initial
assumptions include payment of direct incentives for modifications to commercial customers
categorized in 11 different building types including, retail, small office and hospitals.
Incentives will be based on kW or kWh savings. Measures eligible for incentive payments
include those that have summer peak impact; lighting, OX Tune up/advanced diagnostics, OX
packaged systems. Marketing and education will be a large component of this program.
Program Size
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
10.
16.
88,395
Description
Seasonality,
Dispatchability
Target Market
Summer Focus
Commercial Existing Construction
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (1 0 Years)
Net Benefits
Benefit/Cost Ratio
Utility Cost
Test
Total Resource
Cost Test
$76,120
$17 699
$58,421
$76,120
$32 791
$43,329
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial 30-Year ($/Peak kW/Mo)
$0.024
$10.
$0.044
$20.
Exhibit No, 7
Case No. IPC-04-
T, Tatum, IPCo-Dir
Page 4 of 8
Residential Efficiency (New Construction)
Program
Description
This program is designed to reduce peak demand and energy of new residential customers
under Rate 01. The Idaho Power service territory includes some of the fastest-growing
markets for new residential construction in the Pacific Northwest. Over 90% of all new homes
are built with central air conditioning, It is anticipated that this program will be patterned after
the Energy Star Homes Northwest program, partnering with regional and state organizations,
Direct incentives will be provided to builders and possibly homebuyers. Incentives will be
based on kW or kWh savings, Primary eligible measures include high-efficiency air
conditioners, duct sealing, shell measures, efficient lighting and efficient appliances. Potential
marketing and education activities include direct mail pieces, newsletters, participation in
home shows and home parades. Idaho Power will work with builders and trade allies to
provide training. Idaho Power was one of three regional utilities to offer this program as a
quick start" pilot in early 2004.
Program Size
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)16,612
Description
Seasonality
Dispatchability
Target Market
Summer Focus
Residential New Construction
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (1 0 Years)
Net Benefits
Benefit/Cost Ratio
Utility Cost
Test
Total Resource
Cost Test
$19,282
725
$14 557
$19,282
615
$11 667
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial 30-Year ($/Peak kW/Mo)
$0.036
$5.
$0.058
$8.
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 5 of 8
1 j
~) ., ;~,: -
f:'~, : I .
Program
Description
Program Size
Description
Residential Efficiency (Existing Construction)
This program is designed to reduce peak demand and energy of residential customers on
Rate Schedule 01. Although a firm program design has not been determined, initial
assumptions include payment of direct incentives for modifications to existing single- family
homes, multifamily homes or manufactured homes. Incentives will be based on kW or kWh
savings. Measures eligible for incentive payments include those that have summer peak
impact; high-efficient air conditioners, HV AC O&M measures, duct repair, insulation and
lighting. Marketing and education will be a large component of this program.
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
20.
86,144
Seasonality
Dispatchability
Target Market
Summer Focus
Residential Existing Construction
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
Utility Cost
Test
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (1 0 Years)
Net Benefits
Benefit/Cost Ratio
$73,419
$23,001
$50,418
Levelized Costs
Nominal 30-Year ($/kWh)
Nomial30-Year ($/Peak kW/Mo)
$0.034
$12.
Total Resource
Cost Test
$73,419
$37,657
$35,762
$0.055
$19.
Exhibit No.
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 6 of 8
Air Conditioning Demand Response
Program
Description This program is designed to provide a dispatchable resource by cycling residential air
conditioners off during times of heavy peak load. The target market is residential customers
under Rate 01 that have central air conditioners. The final design of this program will depend
upon findings of a pilot program being conducted in 2003-2004 in the Boise/Meridian area.
The pilot will help determine costs, kW reduction, recommended program design and
recommended technologies, Idaho Power is testing both radio-controlled thermostats and
radio-controlled compressor switches. Air conditioners are cycled off and on every 15
minutes for four hours, 10 times per month. Participants receive a $10 reduction on their
electricity bill during the three months they are cycled: June, July and August. The pilot
program will be finished early winter 2004.
Program Size
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
45,
Description
Seasonality
Dispatchability
Target Market
Summer only
Yes
Residential Customers with Central AlC
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
N/A
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (30 Years) *
Net Benefits
Benefit/Cost Ratio
Utility Cost
Test
Total Resource
Cost Test
$44 094
$34 271
823
$44,094
$26,317
$17 778
Levelized Costs
Nominal 30-Year ($/kWh) N/A N/A
Nomial 30-Year ($/Peak kW/Mo) $5.50 $4.
* Demand response program costs include increases supply costs associated with energy shifted from on peak
to off peak periods.
Exhibit No.
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 7 of 8
': "
. i'
; "
, 1
Irrigation Peak Demand Response
Program
Description
This program is designed to provide a temporary reduction in demand by turning off irrigation
pumps during times of summer peak. The target market is irrigation customers under Rate
24. The final design of this program will depend upon findings of a pilot program being
conducted in summer of 2004 in four areas across the Idaho Power service territory. The pilot
will determine costs, kW reduction and recommended program design. Each participating
customer offers to have their irrigation pump turned off either once, twice or three times per
week between the hours of 4 and 8 pm. Pumps are installed with automatic electronic timers.
Participants receive a billing credit on their electric bill during the three months they are turned
off: June, July and August. The pilot program will be finished early winter 2004.
Program Size
Average Demand (MWa)
Peak Reduction (MW)
Annual Energy (MWh)
30.
Description
Seasonality
Dispatchability
Target Market
Summer only
Irrigation Customers (no yield reduction allowed)
First Year Available
Program Duration (Years)
Measure Life (Years)
Customer Participant Payback (Years)
2005
N/A
Costs and Benefits (thousands of dollars)
Discounted Present Values
Benefits (30 Years)
Costs (30 Years) *
Net Benefits
Benefit/Cost Ratio
Utility Cost
Test
Total Resource
Cost Test
$35,151
$25,190
$9,961
$35,151
$13,016
$22,135
Levelized Costs
Nominal 30-Year ($/kWh) N/A N/A
Nomial 30-Year ($/Peak kW/Mo) $4.22 $1.
* Demand response program costs include increased supply costs associated with energy shifted from on-
peak to off-peak periods.
Exhibit No.
Case No. IPC-04-
T. Tatum, IPCo-Dir
Page 8 of 8
BEFORE THE
Idaho Public Utilities Commission
Office of the SecretaryRECEIVED
DEC - 6 2004
Boise, Idaho
IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY
CASE NO.IPC-E-O4-
EXHIBIT NO.
T. TATUM
Figure 13 Supply-Side Resources and Demand-Side Programs
30- Year Nominal Levelized Fixed Costs
Irrigation Demand Response (30 MW)
Bennett Mtn CT 2nd Unit (162 MW)
AlC Demand Response (45 MW)
Danskin Adv CT 3rd Unit (43.7 MW)
Idaho CCCT (540 MW)
Irrigation Efficiency (29 MW)
Residential Efficiency New (9 MW)
Danskin CC Conversion ( 69 MW)
Combined Heat & Power (5.5 MW)
Idaho Wind (100 MW)
Commercial Efficiency New (4 MW)
Idaho Pulverized Coal (500 MW)
\ Residential Efficiency Existing (20 MW)
Commercial Efficiency Existing (16
Industrial Efficiency (12 MW)
Valmy Unit 3 (130 MW)
Idaho - Geothermal (50 MW)
$/kW/Mo
0 Capacity 0 Fixed O&M
Figure 14 Supply-Side Resources 30-Year Nominal Levelized Cost of Production
Industrial Efficiency (12 MN)
\ .
' . kiaho '0"n d (100 MN)
! Comnerclal Efficiency ExISting (16 MN)
Irrigation Efficiency (29 MN)
kiaho - Geothermal (50 MN)
Corrbined Heat & Power (5.5 MN)
Residential Efficiency Existing (20 MN)
Residential Efficiency New (9 MN)
Idaho Pulverized Coal (500 MN) -
Valrny Unit 3 (130 MN) -
Idaho CCCT (540 MN)
Comnercial Efficiency New (4 MN) -
Danskin CC Conversion ( 69 MN)
Danskin Adv CT 3rd Unit (43.7 MN)
Bennett Mtn CT 2nd Unit (162 MN)
....- ,-
--- - - Pl m u- "-ur' --
- --- -, ,-,- -
-='1
,--------
$/MWh
100
0 Capacity 0 Fixed & Variable O&M 0 Fuel II Emission Adders
Exhibit No, 8
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 1 of 1
Chapter
Idaho Public Utilities Commission
Office of the SecretaryRECEIVED
DEC - 6 200~
Boise, Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
.,
IDAHO POWER COMPANY
CASE NO.IPC-E-O4-
EXHIBIT NO.
T. TATUM
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Office of the SecretaryRECEIVED
DEC - 6 2004
Boise, Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY
CASE NO. IPC-O4-
EXHIBIT NO.1 0
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Idaho Public Utmties Commission
Office of the SecretaryRECEIVED
DEC - 6 2004
Boise, Idaho
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY
CASE NO. IPC-O4-
EXHIBIT NO.
T. TATUM
DATE:
PARTIES:
RECITALS:
CONTRACT
February 1 2004
NOR THWESTENERGY EFFICIENCY ALLIANCE
(Hereafter referred to as "the Alliance
and
Idaho Power Company
(Hereafter referred to as "Idaho
The Alliance is a non-profit corporation that has been funded by utilities in
the NW Region since 1997. A new Memorandum of Agreement, dated February 1 , 2004
and incorporated herein by reference, has been signed by funding utilities in the region as
well as other key organizations supporting the continuation of the Alliance for the period
2005 through 2009, with a ramp-down in 2010 if funding is not renewed in 2009.
Based upon the mutual promises exchanged between them, the Alliance
and Idaho agree as follows:
AGREEMENT:
1. Total Funding Amount.Idaho shall provide funds to the Alliance under
the tenDS of this Contract in the total sum of $6,500 000. Therefore, the
average annual contribution for the five-year funding cycle provided by
this Contract is $1 300 000 (Average Annual Contribution). If Alliance
fails to secure renewed funding in 2009, Idaho shall pay the sum
$975,000 to Alliance in 2010 to allow Alliance to wind up its business.
Credits.Idaho is anticipated to have a credit of approximately $1,919 000
on deposit with the Alliance as of December 31 2004. The actual credit
shall be detennined by the Alliance by May 1 , 2005. The credit can
applied to any invoice after July 2004.
Fixed-Flat Invoice. The Alliance shall invoice Idaho $325 000 December
, 2004, which represents 250/0 of its Annual Contribution, which is due
and payable within 30 days of receipt. Quarterly invoices equivalent
1/4 of the Annual Contribution will continue through the contract period
with an invoice date of30 days prior to the quarter and due date of the 1st
of each quarter.
True Up of Funds through 2009 or 2010. If the Alliance has not expended
the entire amount covered in this contract at the end of the funding cycle
billings will be reduced or funds will be credited to a future funding
agreement.
Holding of Funds Funds will be held in an interest bearing account in the
name of the Alliance consistent with the financial policies of the Alliance.
Exhibit No. 11
Case No. IPC-O4-
T. Tatum , IPCo-Dir
Paae 1 of 7
Interest accruing to such account is owned by Idaho and will offset
invoices to Idaho from the Alliance beyond any fees the bank may charge.
Exceptions to Funding Commitments The following exceptions shall
apply to Idaho s funding commitments:
a. Idaho shall not have an obligation to provide funding for the Alliance
if Idaho and Oregon Public Utility Commissioners do not authorize
recovery of Alliance funding in a manner acceptable to Idaho.
b. Changes to funding shall be revisited by both parties should a public
purpose charge be enacted, implemented or significantly altered in the
service area served by Idaho.
c. Funding by Idaho may be discontinued with sixty days notice to the
Alliance if there is a change to the Bylaws of the Alliance to which
Idaho does not agree.
Representation on the Alliance Board. Idaho will have the right to appoint
one voting member to the Alliance s Board of Directors under this
contract for as long as funding continues.
Alliance Evaluation. The Alliance will complete an independent
evaluation of the value brought by the organization to the region prior to
December 2008.
10.Additional Funds. Nothing in this Contract shall limit the Alliance
ability to solicit funds from third party sources that may pennit the
Alliance to expend amounts in excess of $20 million per year.
11.Miscellaneous.
d. No amendment or modification of this Contract shall be valid unless
set forth in a written document hereafter signed by Idaho and the
Alliance.
e. In the event of any conflict between (i) this Contract and (ii) the
Articles of Incorporation or Bylaws of the Alliance, the provisions of
this Contract shall prevail as between Idaho and the Alliance.
f. The provisions of this Contract are intended to be for the exclusive
benefit of Idaho and the Alliance, and nothing in this Contract shall be
interpreted or construed as conferring upon any third party any right or
claim against Idaho or the Alliance or entitling any third party to
enforce any of the tenDS of this Contract on Idaho, the Alliance or
otherwise. This Contract shall not be interpreted or construed to create
or evidence a partnership between Idaho and the Alliance, or as
imposing any partnership obligation or liability on Idaho or the
Alliance.
(Signature Page Follows)
Exhibit No. 11
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 2 of 7
IDAHO POWER COMPANY
Date
~~
'2..~'-\.
Dan B. Minor, Vice President, Delivery
Name and Address for Notices to Idaho:
Idaho Power Company
, Attention: Darlene Nemnich
O. Box 70
Boise, ID 83707
NORTHWEST ENERGY EFFICIENCY ALLIANCE
Date
Margaret Gardn
Name and Address for Notices to the Alliance:
Executive Director
Northwest Energy Efficiency Alliance
529 SW Third Avenue, Suite 600
Portland, OR 97204
Exhibit No, 11
Case No, IPC-O4-
T. Tatum, IPCo-Dir
Page 3 of 7
9rl emo rand u m cif Jl ore emen t
jlmong Wort/iwest ~giona( Parties in Support
t/ie Wort/iwest P,nergy CEfficiency jl((iance
February 1 , 2004
WHEREAS the Northwest Energy Efficiency Alliance (Alliance) is a regional, not-for-
profit corporation committed exclusively to bringing affordable, energy efficient products
and services to the marketplace;
WHEREAS the Alliance and its market partners have secured about 100 average
megawatts of electricity savings (in addition to the rebate efforts of local utilities) in the
Northwest during it's first six years of operation- These savings have come at a cost of
approximately one centlkWh;
WHEREAS significant changes that result in energy efficiency have been documented in
key markets in which the Alliance is operating;
WHEREAS these electricity savings have been returned to each of the four Northwest
states;
WHEREAS Alliance project budgets have been allocated reasonably among residential
commercial, industrial and agricultural sectors;
WHEREAS the Alliance has a strong track record and future commitment to evaluate the
effects of its projects in the marketplace and adjust project strategies accordingly;
WHEREAS Alliance operating costs have been a small portion of its costs;
WHEREAS the undersigned parties want to see low-cost energy savings brought to
customers throughout the Northwest;
THE UNDERSIGNED PARTIES AGREE to cooperatively fund the Alliance for a five-
year period starting January 2005. Total average annual funding covered in this
Memorandum will be $20.345 million per year for the Northwest Region and the portion
of Northwestern Energy s service territory east of the continental divide. It is allocated
by the shares found in table 1 , which are based on historic contributions to the Alliance.
Should the Alliance not receive continued funding in 2009, the undersigned parties agree
to contribute up to 750/0 of their share in table 1 in 2010 for a ramp-down period for the
organization.
Funding from a Party may be reduced or discontinued if cost-recovery is not provided by
that Party s appropriate regulatory body or budget is not approved by its public governing
body.Exhibit No. 11
Case No. I PC-O4-
T. Tatum, IPCo-Dir
Page 4 of 7
Funding by the affected Parties may be readjusted if a public purpose charge is enacted
implemented or significantly altered in the service territory of the funder.
Funding by the Parties may be discontinued with sixty days notice if there is a change to
the Bylaws of the Alliance to which that Party does not agree.
Parties funding their fair share as found in table 1 will have the right to appoint one
voting member to the Alliance s Board of Directors.
THE ALLIANCE AGREES to work to catalyze Northwest markets to embrace energy
efficient products and services and will work to secure at least 100 average megawatts
cost-effective electricity savings over the period covered.
The Alliance will complete an independent evaluation of the value it produces for the
Region prior to December 2008, and disseminate its findings to the Parties.
This Agreement shall not limit the Alliance s ability to solicit and expend funds from
other sources.
TABLE
Average Yearly Shares from the Parties to the Alliance
F or the period 2005 through 2009
Part trib fu Ion ercen
Avista Utilities 800 000 93%
Bonneville Power Administration 861 210 48.47%
Clark Public Utilities 257 120 26%
Public Utility District No.1 of Cowlitz County, W A 300 260/0
Energy Trust of Oregon 320 000 16.32%
Eugene Water and Electric Board 117,080 58%
Grant County Public Utility District 180 530 89%
Idaho Power Company 300 000 6.390/0
Northwestern Energy 545 000 68%
P acifi Corp 780 000 83%
Puget Sound Energy 100 000 10.32%
Seattle City Light 633 500 11 %
Snohomish County PUD 128 000 630/0
Tacoma Power 270 260 1.330/0
Total Average Annual Cycle 3 Funding 345,000 100.00010
Exhibit No. 11
Case No, IPC-O4-
T. Tatum, IPCo-Dir
Page 5 of 7
THE FOLLOWING ORGANIZATIONS AGREE to provide funds to the Northwest
Energy Efficiency Alliance in accordance with this Memorandum.
VISTA UTILITIES IDAHO POWER COMPANY
BONNEVILLE POWER
ADMINISTRATION
NORTHWESTERN ENERGY
ACIFICORP
CLARK PUB LI C UTILITIES
PUGET SOUND ENERGY
PUBLIC UTILITY DISTRICT No.1 of
COWLITZ COUNTY, WASHINGTON SEATTLE CITY LIGHT
ENERGY TRUST OF OREGON SNOHOMISH COUNTY PUD
EUGENE WATER AND ELECTRIC
BOARD
TACOMA POWER
GRANT COUNTY PUBLIC UTILITY
DISTRICT
SUPPORTING RESOLUTION:
THE FOLLOWING ORANIZATIONS ENDORSE the actions of the above-listed
parties to contribute to the Northwest Energy Efficiency Alliance for the purpose of
developing energy efficiency through marketplace mechanisms.
KOOTENAI ELECTRIC IDAHO GOVERNOR'S OFFICE
SALEM ELECTRIC NORTHWEST ENERGY COALITION
MONTANA GOVERNOR'S OFFICE NORTHWEST POWER AND
CONSER V A TION COUNCIL
NORTHWEST ENERGY EFFICIENCY
COUNCIL OREGON GOVERNOR'S OFFICE
NATURAL RESOURCES DEFENSE
COUNCIL
WASHINGTON GOVERNOR'
OFFICE
if"J ,
Exhibit No, 11
Case No, IPC-O4-
T. Tatum, IPCo-Dir
Page 6 of 7
Idaho Power Company agrees to provide funds to the Northwest Energy Efficiency
Alliance in accordance with this Memorandum of Agreement dated February 1 2004.
IDAHO POWER COMPANY
By: M~.:.
Title:
Date: ~fr 30 , 2.Do~
Exhibit No. 11
Case No. IPC-O4-
T. Tatum, IPCo-Dir
Page 7 of 7