20040624Responses of Avista to CAPAI Part IIC.pdf

Triple-E Report
January 1 , 2002 to December 31 , 2002
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A vista Demand-Side Management Team
J on Powell
Renee Coelho
Chris Drake
Catherine Bryan
Tom Kliewer
Sheri Butterfield
Rob Gray
Eric Lee
Mike Littrel
Bruce Folsom
Lori Koberstine
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Introduction
This is the eighth in a series of Triple-E Reports in fulfillment of Avista Utilities commitment to enhanced
analysis and reporting.
This report covers demand-side management (DSM) activities during calendar year 2002. The
methodology employed to arrive at these calculations is consistent with that represented in previous reports
except as otherwise noted. A full copy of the previous seven Triple-E Reports is available upon request.
The Company has taken efforts to streamline this reporting process in consideration of reduced staff
resources. Feedback on the quality, quantity and timeliness of these reports is always appreciated.
Overview
To place the events of 2002 into historical perspective it is important to remember that the northwest
experienced a regional energy crisis during the summer and fall of 2001, only a few short months prior to
the period covered by this report. Though the crisis ultimately did not effect availability of energy, it did
result in unprecedented wholesale price increases. Though the primary impact was upon electric prices,
there was a substantial escalation of natural gas prices as well.
Media coverage of the energy crisis was equally extraordinary. From April to September 11 th of 200 1 the
energy crisis was literally on the front page nearly every day.
The confluence of media and public interest and the extraordinarily energy costs led to a dramatic
emergency response on the part of A vista Utilities. This response included a series of emergency DSM
programs. By the close of the calendar year A vista Utilities had acquired three times the electric-efficiency
goal specified in Schedule 90. This extraordinary effort did come at a cost, specifically a $12.4 million
negative balance in the combined fuel and jurisdiction DSM tariff riders. This amount represents
approximately 1.5 years of revenue received under the tariff rider.
A business plan was developed in November and December 2001 for the 2002 to 2005 (inclusive) time
period. This business plan was based on returning the DSM tariff rider balance to zero by the close of 2005
while continuing to deliver energy savings that are proportionate to the percentage of incoming DSM tariff
rider revenues that are being expended. The business plan was premised on three priorities; (1) meet all
regulatory and legal requirements, (2) field a cost-effective DSM portfolio and (3) aggressively move the
tariff rider balance towards zero.
This Triple-E Report covers the first full year of the implementation of that business plan.
As will be detailed in the narratives associated with each of the tables in this report, Avista has delivered a
strongly disproportionate quantity of energy savings with a cost-effective portfolio. The aggregate tariff
rider balance has simultaneously improved by $3.7 million over the course of this year.
The 2002-2005 DSM business plan is under continual review, but has not substantially changed since it's
original presentation to the Triple-E board. It is our expectation that we will continue to see the same
progress towards eliminating the tariff rider balance and disproportionately high energy savings from both
the gas and electric tariff riders.
Disclosures
A vista had committed to disclose, within the limits imposed by customer confidentiality requirements,
projects that (1) involved granting incentives to Avista or any Avista subsidiary and (2) progress of any
project with incentives of over $100,000.
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During 2002 there was one lighting efficiency incentive for $12,
704 paid to Avista Corporation.
Below is a list of the nine projects with an expected incentive payment of $100,
000 or more. This listing
does not necessarily capture customers who have multiple projects in progress that may sum to $100,
000.
All of these projects have had activity of some sort in 2002.
That activity may be simply updating cost-
effectiveness data or may be as significant as contracting or completing a project. Confidential data of non-
governmental customers has suppressed.
Customer Measure kWh'therms Total incentive Customer cost note
18818 office shell 338,039 13 7,450 $ 439.393 $ 1,291.000
10409 health care HVAC 295,270 98,653 $ 319,581 $ 745.624
107 Spokane County Lighting 574.259 298,434 $ 596.870
18782 manufacturing Ind. Process 95,271 $ 239,135 $ 478,270
17923 health care HVAC 79.919 $ 138,750 $ 277,500
18346 City of Spokane Motors 160.000 129,600 $ 514,173
13191 forest products Ind. Process 1,187,900 $ 120,487 $ 318,440
7534 hospitality New tech.652,358 15.688 $ 117,453 $ 188,160
18618 food production Ind. Process 51.700 87.200 $ 102.720 $ 205,440
Note 1: Project did not move in phase during 2002 but there were revisions to project data (cost, energy savings etc.that impact cost-effectiveness.
Note 2: Project moved from the contracted to the completed phase.
Note 3: Project moved from the stUdy to the construction phase.
Note 4: Project moved to the scope phase.
Note 5: Project moved to the study phase.
Notes on Project Scheduling
In 2002 Avista began scheduling commercial
industrial projects for incentive payment upon contracting in
order to better control cash flow. It has been our objective to ensure payment within 6 months of the
completion of a fairly easy project (e.
g. within about 9 months of the contracting of the project).
At the
close of 2002 this delay was actually in the range of zero to 12 months delay after completion. depending
on the amount of time that the customer spent in construction.
The 2003 DSM budget is signifIcantly above that which we were subject to in 2002 and will permit us to
close this gap. This will not effect our overall plan to
reduce the tariff rider balance to zero since we will
simply be moving incentives contractually scheduled for 2004 into 2003.
We intend to continue this
process in 2004 as well. However. if the problem persists into 2005 we
will not be able to move up
contracted incentives in that year without adversely effecting our goal of returning the tariff rider balance to
zero by the close of 2005.
. .. .. .
Guide to Table Narratives
The remainder of this report is dedicated to 15 tables covering
the critical diagnostic and cost-effectiveness
data for 2002. Those tables ending with an "
E" relate to electric DSM activities only. Similarly those
ending with a "G" relate to natural gas DSM only. Table designations ending
with an "EG" are combined
gas and electric DSM results.
Unless otherwise noted dollar amounts are based upon "
de-rated" calculations as projects move through the
pipeline towards completion. Projects that have been contracted are
captured at 75% of their expected
value upon full completion. construction is captured at 95% and completed projects are valued at
100%.
These de-rations approximate the utility implementation investment in a project as it moves towards
completion and are slightly less than the ultimate realization rate for projects of that phase, based upon two
prior measurement & evaluation studies.
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It is possible for projects to dropout of any phase (except completed) and possible for the values of any
project to change at any time due to changes in the scope of the projects or as the result of revised
engineering estimates, cost estimates or actual measurement & evaluation results. On occasion this results
in a negative number appearing in a cell of the following tables.
Other specific information and notable conclusions are detailed in the narrative associated with each of the
tables.
Narrative for Table 1
This series of three tables represent the distribution of the $4 268,107 in 2002 utility expenditures across
customer segments, temporary programs, regional programs and general expenses on a cash basis. These
expenditures are further broken out by incentives and implementation and by gas and electric.
Consistent with the focus within the DSM business plan on streamlined implementation, nearly 70% of
total utility cash expenditures were returned to customers in the form of direct cash incentives. There was a
significant difference by fuel in this percentage (58% electric vs. 94% gas).
Temporary programs accounted for 6.5% of total utility expenditures during 2002 (9.5% of electric and 0%
of gas expenses). These expenses were almost exclusively related to the payment of incentives on projects
initiated during 2001 but not receiving payment until 2002. The account numbers for these temporary
programs were closed out in early 2002.
Regional expenditures during 2002 were not typical. A vista changed the accounting methodology under
which it is billed for participation in the Northwest Energy Efficiency Alliance (or the ..Alliance ). As a
result there was a significant period of time when Avista did not have cash payments due. This period of
time ended in 2002. At the close of the year A vista had two Alliance invoices totaling $387,762 in
Accounts Payable, in addition to the $96,386 that cleared during the year. On average Avista will pay
approximately $800,000 to the Alliance (4.0% of total regional Alliance expenditures). The current
funding contract extends through the close of 2004 with cash payments under that contract likely to extend
beyond that date.
The small regional gas expenditure of $1,025 is associated with labor to review gas-efficiency opportunities
with the Alliance.
During 2002 Avista completed our contractual responsibilities under the Pulse Electric Field (PEF)
pasteurization project contract. This was a cooperative project to advance the development of energy-
efficient pasteurization techniques. The final payment of $100,000 is included in the general
implementation category of Table 1. The Company is assisting the venture proponents in their search for
funding for the next phase of research.
Notably over 70% of the cash expenditures for residential sector direct incentives were funded by gas
DSM. With the discontinuance of washing machine rebates in 2002 this amount was projected to move
even higher, although the launch of an electric-funded electric to gas conversion program may offset this
amount. It is the Company s intent to periodically rotate measures through the residential portfolio to
maintain interest in the offerings and reduce the potential for customer procrastination. It is likely that we
will use these rotations to reduce the proportion of gas funding within the residential portfolio.
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Table 1 Electric Utility Costs Aggregated by Programs and Customer Segments
Incentives Implementation TOTAL
SEGMENTS
Agricultural 156 677 32,833
Government $216 226 146,228 362,453
Food Service 33,538 14,099 637
Health Care 46,644 546 64,190
Hospitality 813 15,972 785
Limited Income 658,745 51,041 709,785
Manufacturing 133,074 93,401 226 475
Office 79,518 32,288 111,805
Residential $144,928 018 161 946
Retail 106 43,931 71,037
GENERAL
General (Implementation)655,8531\ $655,853
OTHER EXPENDITURES
NEEA3 $96,38611 $96,386
OTHER PROGRAMS
Rooftop program (1,650) $(1,650)
Residential CFL promotion 703) $(1,703)
Non-residential CFL promotion 080 080
Enhanced incentive program 278,658 447 280,105
Exit Sign Promotion (210)(210)
Residential water heater program 500 500
EMS Re-Commissioning
TOTAL 1 ,698,342 217,966 916,308
BROKEN OUT BY CATEGORY
Total assigned to segments 422,747 463,201 885,948
Total assigned to general 655 853 655,853
Total assigned to other 96,386 96,386
Total assigned to temp. programs 275,594 527 278,121
TOTAL 698,342 217,966 916,308
CATEGORY AS A PERCENT
Total assigned to segment 48.15.64.
Total assigned to general 22.22.
Total assigned to other pgms.
Total assigned to old programs
TOTAL 58.41.o/~1 100.
NOTES:
1) Incentives are accounted for on an de-rated accrual basis and will not match cash incentive expenditures.
2) The Government segment includes educational institutions as well as federal, state and local governments.
3) Costs associated with membership in NEEA are included in this table, but are excluded from all other tables.
4) Incentives attributable to emergency programs have been allocated to the appropriate customer segment
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Table 1 Gas Utility Costs Aggregated by Programs and Customer Segments
Incentives Implementation TOTAL
SEGMENTS
Agricultural 40,648 947 595
Government $45,108 45,108
Food Service 887 887
Health Care 300,833 300,833
Hospitality 65,167 65,167
Limited Income 392,348 392 348
Manufacturing 16,582 16,582
Office 46,370 359 729
Residential $348 177 670 348 846
Retail 33,225 179 33,404
GENERAL
General 58,274\\ $58,274
OTHER EXPENDITURES
Regional3 $0251\ $025
OTHER PROGRAMS
Rooftop program
Residential CFL promotion
Non-residential CFL promotion
Enhanced incentive program
Exit Sign Promotion
Residential water heater program
EMS Re-Commissioning
TOTAL 272,763 79,036 351,799
BROKEN OUT BY CATEGORY
Total assigned to segments 272,763 19,737 1 ,292 500
Total assigned to general 58,274 58,274
Total assigned to other 025 025
Total assigned to old programs
TOTAL 272,763 79,036 351,799
CATEGORY AS A PERCENT
Total assigned to segment 94.95.
Total assigned to general
Total assigned to other pgms.
Total assigned to old programs
TOTAL 94./~1 100.
NOTES:
1) Incentives are accounted for on an de-rated accrual basis and will not match cash incentive expenditures.
2) The Government segment includes educational institutions as well as federal, state and local governments.
3) Costs associated with gas programs in support of regional initiatives appear in this table but are excluded from other tables.
4) Incentives attributable to emergency programs have been allocated to the appropriate customer segment
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Table 1 Electric Utility Costs Aggregated by Programs and Customer Segments
Incentives 1m plementation TOTAL
SEGMENTS
Agricultural 41,804 33,625 75,429
Government $261,334 146,228 407,561
Food Service 425 14,099 48,524
Health Care 347,477 546 365,023
Hospitality 146,980 15,972 162,952
limited Income 051 093 51 ,041 102,133
Manufacturing 133,074 109 983 243,057
Office 125,888 647 158,534
Residential $493,104 688 510,792
Retail 60,331 44,110 104 442
GENERAL
General (Implementation)714 12711 $714,127
OTHER EXPENDITURES
NEEA3 $97,41211 $412
OTHER PROGRAMS
Rooftop program 650) $(1,650)
Residential CFL promotion 703) $703)
Non-residential CFL promotion 080 080
Enhanced incentive program 278,658 447 280,105
Exit Sign Promotion (210)(210)
Residential water heater program 500 500
EMS Re-Commissioning
TOTAL 971,105 297,003 268,107
BROKEN OUT BY CATEGORY
Total assigned to segments 695,510 482 937 178 448
Total assigned to general 714 127 714 127
Total assigned to other 412 97,412
Total assigned to temp. programs 275,594 527 278 121
TOTAL 971,105 297,003 268,107
CATEGORY AS A PERCENT
Total assigned to segment 63.11.74.
Total assigned to general 16.16.
Total assigned to other pgms.
Total assigned to old programs
TOTAL 69.30.o/~1 100.
NOTES:
1) Incentives are accounted for on an de-rated accrual basis and will not match cash incentive expenditures.
2) The Government segment includes educational institutions as well as federal, state and local governments.
3) Costs associated with membership in NEEA are included in this table, but are excluded from all other tables.
4) Incentives attributable to emergency programs have been allocated to the appropriate customer segment
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Narrative for Table 2
Table 2E and 2G illustrate the distribution of non-regional cash expenditures across the ten customer
segments. This involves assigning general expenditures to individual customer segments. These costs are
generally assigned on the basis of electric-efficiency savings acquisition on the belief that this is the
measure that is the most correlated to general implementation activity.
In the past the accuracy of the assignment of general costs was a more significant factor in determining the
overall cost-effectiveness of segments or technologies. With implementation cost falling as a percentage of
total utility cost the sensitivity to this allocation has become less important.
Regional costs are not allocated to customer segments and are consequently excluded from this table.
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Narrative for Table 3
Table 3E and 3G further allocate utility cost into the ten customer segments and fourteen measures. The
resulting 140-cell matrix represents the utility cost (excluding regional expenses) of serving these
technology applications.
Later tables will incorporate these costs into overall utility cost test and non-participant cost-effectiveness
calculations.
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incentive payments during 2002.
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Narrative for Table 5
Table 5E and 50 breakout the total electric savings resulting from electric DSM programs and gas DSM
programs into the 140-cell technology application matrix.
Table 5E distributes the electric-efficiency savings and all interactive effects of the targeted measure upon
other electric end-use consumption. This would include, for example, the favorable benefits of a lighting
efficiency project on space cooling requirements as well as the detrimental effects that the same measure
would have upon electric space heating, if applicable. Therefore electric-efficiency savings claimed in this
table represent the total amount that the customer electric meter would measure barring any change in
customer operations.
Similarly gas programs occasionally contribute electric savings (or negative savings) as well. This could
be the result of interactive impacts of gas-efficiency projects (e.g. an HV AC efficiency measure that
reduces electric fan consumption) or incidental electric savings (e.g. the recommendation and adoption of
an electric-efficiency measure as part of a gas-funded DSM audit). Both negative and positive interactive
effects of gas-measures upon electric consumption are equally captured.
Not surprisingly 97.9% of the total electric savings are the result of electric DSM operations. Oas impacts
upon electric-efficiency were limited to HV AC and shell measures.
As is typical, lighting and HV AC are the largest contributors to the overall kWh acquisition, totaling 57%
between the two of them.
Resource management is a declining portion of the Company s portfolio due to saturation of efficiency
measures within participating school districts. This is in fact the last year that we will be able to claim any
savings from most of these participating school districts. However, the Company was able to bring the
largest school district in the service territory (School District 81) into the program in 2002.
As in the previous report savings resulting from domestic hot water appliance efficiencies are incorporated
into the "appliance" technology. The majority of these savings accrue in the residential and limited income
portfolios.
Shell measures are also predominately residential (and limited income) in nature. There are several large
non-residential shell projects in our 2002 portfolio, but few of them made much progress during 2002.
Industrial process, motor, monitoring, controls and compressed air measures are often closely related, and
are often difficult to distinguish from one another. In aggregate they accounted for about one-fourth of
total energy savings. We have attempted to further refine our distinctions between these differing
technologies, such as reaching the decision that controls related to a single end-use would be credited
towards that end-use and not to the controls measure itself, but there remains a significant amount of
imprecision in the assignment of these savings.
Assistive technologies remains an active measure, but energy savings is a secondary objective for that
activity. It did not realize and electric or gas savings in 2002.
Sustainable building measures are not a current targeted measure and did not achieve any savings in 2002.
The electric savings attributed to the renewables measure are associated with small generation units
offsetting utility grid power as defined within Schedule 90.
III
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f
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4
11
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9
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7
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6
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69
5
58
2
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1
72
7
15
6
58
7
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48
3
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57
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15
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41
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51
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9
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01
6
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69
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73
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59
3
56
4
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4
46
0
Ho
s
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76
7
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5
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25
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5
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3
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11
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4
44
7
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10
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5
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15
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58
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65
7
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4
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38
9
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t
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25
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0
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13
0
24
1
(7
9
,
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8
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68
4
65
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26
5
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4
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64
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32
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26
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30
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1
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:
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e
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s
a
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Ta
b
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5
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1
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7
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12
3
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7
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5
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5
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T
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s
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s
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p
h
a
s
e
s
.
Narrative to Table 6
Table 6E represents the interacti ve effect of electric DSM operations upon natural gas usage. For the most
part this is confined to the gas usage associated with (1) electric to natural gas conversion projects and (2)
the adverse impact of lighting efficiency projects upon natural gas-fired space heating requirements.
Incidental natural gas efficiency recommendations that have been adopted by the customer during an
electric-DSM funded audit are also eligible for inclusion in this table.
Table 6G contains the breakout of therm savings resulting from gas-efficiency activities. Gas-efficiency
savings are much more tightly confined to a few measures than was evident in the distribution of electric
savings. HV AC and shell measures account for 87% of all gas savings. This climbs to 94% when
appliances (domestic hot water) is included.
p1J 10
ab
l
e

6
E
All
o
c
a
t
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o
n

of
Ga
s

_
_
II
I
.

-

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06
2
)
90
6
(3
3
0
)
(4
7
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4
5
3
)
(4
5
,
93
9
)
11
.
Fo
o
d

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r
v
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c
e
51
3
)
(1
,
51
3
)
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a
l
t
h

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r
e
(1
4
,
40
5
)
(4
4
4
)
(1
4
,
84
8
)
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s
p
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t
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l
i
t
y
(1
8
2
)
(7
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)
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,
20
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)
(7
7
,
86
2
)
19
.
LI
m
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t
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d

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n
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e
(3
5
76
6
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)
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4
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6
)
21
.
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n
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f
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(6
,
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)
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1
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42
0
(1
2
3
,
83
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)
31
.
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f
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c
e
(9
6
)
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7
94
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)
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2
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51
2
)
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0
,
55
6
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10
.
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s
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(3
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t
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80
8
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k
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7
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6
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5
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80
8
(3
9
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24
5
)
10
0
.
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f

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41
.
29
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20
.
10
0
.
NO
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:
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s
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s

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c
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s
.
En
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c
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a
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m
a
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s

t
a
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a
s

t
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l
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(
a
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j
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e
f
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)
.
--
-
"-
J
Ta
b
l
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6
G
All
o
c
a
t
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n

of

Ga
s

S
a
v
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s

A
t
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t
o

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a
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P
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Re
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a
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TO
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Ag
r
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c
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18
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32
4
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4
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09
3
56
0
15
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0
16
,
38
8
71
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04
0
10
.
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d

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r
v
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c
e
12
,
97
3
12
,
97
3
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a
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57
6
16
1
70
,
73
7
10
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p
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73
0
40
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50
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51
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4
11
5
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84
4
17
.
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m
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d

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25
3
39
7
35
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16
7
36
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81
7
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g
51
9
20
,
81
6
64
8
22
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3
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43
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7
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25
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5
30
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46
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96
6
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25
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0
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Narrative to Table 7
A vista has committed to the Triple-E board to quantify non-energy benefits or non-benefits associated with
energy-efficiency projects to the extent possible. Unfortunately there are many such benefits that are not
adequately quantifiable to include in cost-benefit analysis. For the most part non-energy benefits
incorporated within these tables are the result of (1) identifiable maintenance savings and (2) adjustments
for measure life.
As part of the Company s implementation process the project engineer is prompted to calculate the
maintenance savings of a specific job for inclusion in the cost-effectiveness analysis. These maintenance
savings do not change the simple-payback calculations that determine the customer incentive under
Avista s tiered incentive formula established in Schedule 90 and 190.
Maintenance savings most often accrue from lighting projects and are the consequence of the longer period
between re-Iamping of most types of energy-efficiency lamps and the reduced cleaning required for new
fixtures. To a lesser extent HV AC measures do also occasionally contribute to the quantified maintenance
benefit.
The Company also recognizes that there is a capital value to the increased life of energy-efficiency
upgrades. Customers who replace an existing end-use with a remaining life of five years with an energy-
efficient measure with a life of fifteen years are buying more than energy-efficiency, they are also buying
ten years of additional end-use service. By comparing the present value of the future cost of replacing that
end-use in fifteen years vs. five years we are able to capture the present value of that life extension. This is
tallied as a non-energy benefit to offset the full customer cost of the measure and appropriately value only
that cost that is associated with the energy-efficiency measure. Such a quantification requires that the
measure have a well-defined remaining life, which largely limits it s application to HV AC and lighting
measures.
On rare occasions other non-energy benefits can be identified on a site-specific basis. However, as is
evident from the concentration of non-energy benefits in the lighting and HV AC measures, this was not a
contributing factor in 2002.
Ta
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Narrative for table 8
Customer costs are the driving factor behind the Company s Total Resource cost-effectiveness. As will be
seen in the final calculations of cost-effectiveness, 92% of the TRC costs are borne by the customer.
Calendar year 2002 saw both gas and electric retail rate increases. In the case of natural gas the PGA-
induced rate increases were rather dramatic. As a consequence the participant cost-effectiveness of energy-
efficiency projects substantially increased. Those measures that weren t undertaken in 2001 to take
advantage of Avista s temporary program enhancements were often captured in 2002.
As lesser ranked energy-efficiency measures became more cost-effective there was upward pressure on the
customer cost per kWh and per thermo Unfortunately from the standpoint of the cost-effectiveness
evaluation of the Company s DSM programs this was not reflect~d by an increase in the avoided cost
which we use to value those savings. Therefore the retail rate increases driving increased customer-cost per
kWh acted to reduce the cost-effectiveness of our programs.
A vista has continued to target low-cost no-cost and lost opportunity measures in order to deliver the
maximum value to our customers. This targeting has helped to mitigate the inadvertent impact of the retail
rate increases upon program cost-effectiveness.
The overall distribution of customer cost across technology applications largely follows that of the energy
savings. In interpreting the customer cost in total or on a per kWh basis it is important to realize that the
non-energy benefits in table 7 should be subtracted from the total customer cost to determine the cost of the
energy-efficiency measure alone. As indicated in the narrative to Table 7, those non-energy benefits adjust
the overall customer cost for the value of maintenance and increased measure life.
Jl)
--
-
-
-
-
Ta
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Narrative to Table 9 throu2h 13
The end-result of the previous calculations of customer cost, non-energy benefits, incentives, energy
savings and customer energy bill reduction yield a series of cost-effectiveness ratios and net benefits.
Tables 9 through 13 represent and break-out these into various categories.
Table 9E and 9G are a calculation of the four standard practice tests for each of the ten customer segments
as well as for the overall portfolio. Table 10E and lOG performs the same breakout for each of the 14technologies.
Tables liE and 11 represent the cost-effecti veness in the form of a net benefits calculation instead of as a
ratio for each of the ten customer segments. Table 12E and 12G performs the same breakout for each of
the 14 technologies.
Table l3E, l3G and l3EG summarize the overall cost-effectiveness of the electric, gas and combined
electric and gas DSM programs. These calculations also summarize the components of each of the
standard practice tests.
Additional calculations at the bottom of tables 13E, 13G and 13EG indicate the electric and gas-efficiency
savings and the levelized TRC and VCT cost per kWh or thermo These calculations use the Company
weighted average cost of capital and the weighted average measure life of each portfolio.
Both gas and electric programs pass the total resource cost, utility cost and participant cost test. The non-participant test (also known as the rate impact measure) will always be below one as long as the avoided
cost used in the calculations is less than the retail rate. A vista addresses this non-participant issue by
maintaining a portfolio with a broad opportunity to directly and/or indirectly benefit from the portfolio.
Vt1-
)2-
Table 9E Electric Cost-Effectiveness Statistics by Customer Segment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural
Government 1.84
Food Service
Health Care
Hospitality 1.13 2.43
Limited Income (7.38)
Manufacturing
Office 0.49
Residential
Retail
PORTFOLIO
NOTES:
Cost-effectiveness calculations do not include costs or benefits associated with regional programs.
N/Au is listed for segments with benefits, but no costs.
Table 9G Gas Cost-Effectiveness Statistics by Customer Segment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural
Government
Food Service
Health Care 1.35
Hospitality 1.96
Limited Income 0.42
Manufacturing 1.52
Office
Residential
Retail 1.29
PORTFOLIO 1.16
NOTES:
Cost-effectiveness calculations do not include costs or benefits associated with regional programs.
N/A" is listed for segments with benefits, but no costs.
~ Z3
Table 10E Electric Cost-Effectiveness Statistics by Technology
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliances 0.42
Assistive Technologies
Compressed Air
Controls
HVAC
Industrial Process
Lighting 1.46
Monitoring
Motors
New Tech
Renewables 0.49
Resource Management
Shell
Sustainable Building
PORTFOLIO
NOTES:
Cost-effectiveness calculations do not include costs or benefits associated with regional programs.
N1A8 is listed for segments with benefits, but no costs.
Table 10G Gas Cost-Effectiveness Statistics by Technology
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliances 1.69
Assistive Technologies
Compressed Air
Controls
HVAC 1.07
Industrial Process 1.39
Lighting
Monitoring
Motors
New Tech
Renewables
Resource Management 12.12.
Shell 1.35
Sustainable Building
PORTFOLIO
NOTES:
Cost-effectiveness calculations do not include costs or benefits associated with regional programs.
N/A8 is listed for segments with benefits, but no costs.
~- ;;;.
Table 11 E Electric Net Benefits by Customer Segment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural (33,174) $(43,847) $(72,105) $38,931
Government 416,145 822 429 533,994 (2,168,978)
Food Service 154 762 194,465 341 ,068 (188,001)
Health Care (635 662) $226 601 (412,369) $(226,209)
Hospitality 115,526 557 502 922,543 (821 141)
limited Income (100,014) $(213,933)954 994 160,528)
Manufacturing 253 462 653,800 945 480 (794 605)
Office 63,459 456,075 049,790 017,389)
Residential (147 356) $711 554 715 939 (863,328)
Retail 283,173 500,486 817 768 (545 836)
PORTFOLIO 370,320 865 134 797 102 747,086)
NOTES:
Costs and benefits included in each cost-effectiveness test are detailed in Table 13.
Costs associated with regional programs are excluded from all cost-effectiveness calculations.
Table 11 Gas Net Benefits by Customer Segment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural 740 78,562 90,400 (38,659)
Government 324 435 400 272 575 (179,920)
Food Service 016 247 42,883 (30,868)
Health Care 117 035 252 242 248,496 (131 461)
Hospitality 294 706 441 899 531,602 (236,726)
limited Income (71 192) $(71 192)265 792 (336,984)
Manufacturing 159 208 96,386 (90,227)
Office 56,912 220 160 229,803 (173,013)
Residential 63,953 888,011 621 260 (541,240)
Retail 70,707 140,690 180 784 (109 023)
PORTFOLIO 692 360 480,228 579,980 868,121)
NOTES:
Costs and benefits included in each cost-effectiveness test are detailed in Table 13.
Costs associated with regional programs are excluded from all cost-effectiveness calculations.
fk
Table 12E Electric Net Benefits by Technology
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliances (508,273)159 221 335 (790,104)
Assistive Technologies
Compressed Air (18,466) $(15,290) $(27 593) $127
Controls (15,125) $101 430 161 649 (174,908)
HVAC 32,897 783,329 397 543 (2,432.319)
Industrial Process 319.678 652,799 025.393 (807,414)
Lighting (559,831) $401 894 1,427.909 (2,079,857)
Monitoring
Motors 836,061 1,454,132 203.981 (367.919)
New Tech
Renewables (60,978) $19,201 (40,811) $(20,167)
Resource Management 175,745 175,745 893 958 (718,213)
Shell 168,613 264,735 533,739 (365,311)
Sustainable Building
PORTFOLIO 370,320 865 134 797 102 (7,747 086)
NOTES:
Costs and benefits included in each cost-effectiveness test are detailed in Table 13.
Regional program costs and benefits are excluded from all cost-effectiveness calculations.
! .
Table 12G Gas Net Benefits by Technology
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliances (38,013)58,410 99,072 (137,085)
Assistive Technologies
Compressed Air
Controls
HVAC 163,275 276,823 035,154 (853,596)
Industrial Process (21,713) $067 345 (106,057)
Lighting
Monitoring
Motors
New Tech
Renewables
Resource Management 20,047 047 564 (15 517)
Shell 568,764 075,881 1 ,325,845 (755,867)
Sustainable Building
PORTFOLIO 692,360 480,228 579.980 (1,868,121)
NOTES:
Costs and benefits included in each cost-effectiveness test are detailed in Table 13.
Regional program costs and benefits are excluded from all cost-effectiveness calculations.
Pert
-Ie 13E Summary of Electric Cost-Effectiveness Tests and Descriptive Statistics
\ .. ,
Regular Income Limited Income Regular Income Limited IncomeTotal Resource Cost Test portfolio portfolio Overall portfolio Utility Cost Test portfolio portfolio Overall portfolio
Electric avoided cost 701 269 791 724 10,492 993 Electric avoided cost 701,269 791,724 10,492 993
Non-Energy benefits $691 562 691,562 Natural Gas avoided cost 498,391) $(390,018) $888,409)
Natural Gas avoided cost (1,498 391) $(390 018) $(1,888,409)UCT benefits 202,878 401,706 604 584
TRC benefits 894,441 401,706 10,296,147
Non-incentive utility cost $047 077 138 123,215
Non-incentive utility cost 047 077 76,138 123,215 Incentive cost $076,734 539,501 616,236
Customer cost $377 029 425 582 802,611 UCT costs 123,811 615,639 739,451
TRC costs 424 106 501 720 925,826
UCT ratio
TRC ratio Net UCT benefits $079,067 (213,933) $865,134
Net TRC benefits $470 335 (100,014) $370,320
Regular Income Limited Income Regular Income Limited IncomeParticipant Test portfolio portfolio Overall portfolio Electric Non-Participant Test portfolio portfolio Overall portfolio
Electric Bill Reduction $164 016 336,613 $ 15 500,629 Electric avoided cost savings 701,269 791 724 10,492,993
Gas Bill Reduction (1,713,175)(495,538)(2,208,713)Non-Participant benefits 701,269 791 724 10.492 993
Non-Energy benefits 691 562 691 ,562
Participant benefits 142,403 841 ,075 14,983,478 Electric Revenue loss 14,164,016 336,613 15,500 629
Non-incentive utility cost 047,077 138 123,215
Customer project cost 377,029 425,582 802,611 Customer incentives $076,734 539,501 616,236
Incentive received 076,734) $(539,501) $616,236)Non-Participant costs 16,287 827 952,252 240,079
Participant costs 300 294 (113 919) $186,376
Non-Part. ratio
Participant Test ratio (7.38)Net Non-Part. benefits $(6,586,558) $(1,160,528) $(7,747,086)
Net Participant benefits $842,108 954,994 797,102
Regular Income
Descriptive Statistics portfolio
Limited
Income
portfolio Overall portfolio
Annual kWh savings
Annual therm savings
Levelized TRC cost per kWh
Levelized UCT cost per kWh
32,517 853
(312 708)
0357 $
0080 $
364 528
(84 536)
0244 $
0300 $
34,882,381
(397,245)
0348
0096
NOTES:
Costs associated with membership in regional programs are excluded from all cost-effectiveness calculations.
N/A" is listed for segments with benefits, but no costs.
P1t
e 13G Summary of Gas Cost-Effectiveness Tests and Descriptive Statistics
Regular Income Limited Income Regular Income Limited IncomeTotal Resource Cost Test Dortfolio portfolio Overall portfolio Utility Cost Test portfolio portfolio Overall Dortfolio
Electric avoided cost 287 289 287 289 Electric avoided cost 287,289 287 289
Non-Energy benefits $042,809 1 ,042,809 Natural Gas avoided cost 545,400 241 856 787,256
Natural Gas avoided cost 545,400 241 856 787 256 UCT benefits 832,689 241,856 074 546
TRC benefits 875,498 241 856 117 354
Non-incentive utility cost 587 449 79,036
Non-incentive utility cost 587 4,449 036 Incentive cost 206,682 308,599 515,281
Customer cost $037 359 308,599 345,957 UCT costs 281 269 313,048 594,318
TRC costs 111 946 313,048 424,994
UCT ratio
TRC ratio Net UCT benefits $551,420 (71 192) $480,228
Net TRC benefits $763,552 (71 192) $692,360
Regular Income Limited Income Regular Income Limited Income
Participant Test DOrtfolio portfolio Overall portfolio Gas Non-Participant Test portfolio portfolio Overall Dortfolio
Electric Bill Reduction $306,788 306,788 Gas avoided cost savings 545,400 241 856 787,256
Gas Bill Reduction 795,267 265,792 061 060 Non-Part benefits 545,400 241 856 787 256
Non-Energy benefits 042,809 042,809
Participant benefits 144 864 265,792 5,410,656 Gas Revenue loss $795,267 265 792 061 060
Non-incentive utility cost 587 4,449 79,036
Customer project cost 037,359 308,599 345,957 Customer incentives $206 682 308,599 515,281
Incentive received 206 682) $(308,599) $515,281)Non-Part costs 076,537 578,841 655,377
Participant costs 830,676 830,676
Non-Part. ratio
Participant Test ratio #DIV/OI Net Non-Part. benefits $(1,531,137) $(336,984) $(1,868,121)
Net Participant benefits $314,187 265 792 579,980
Regular Income
Descriptive Statistics portfolio
Annual kWh savings 733,667
Annual therm savings 617 166
Levelized TRC cost per therm $ 0.648 $
Levelized UCT cost per therm $ 0.202 $
Limited
Income
Dortfolio
36,817
827 $
827 $
Overall Dortfolio
733,667
653,983
658
237
NOTES:
Costs associated with membership in regional programs are excluded from all cost-effectiveness calculations.
N/A" is listed for segments with benefits, but no costs.
PCt d- B
.... -
'lIe 13EG Summary of Combined Gas and Electric Cost-Effectiveness Tests and Descriptive Statistics
Regular Income Limited Income Regular Income Umited IncomeTotal Resource Cost Test Dortfolio Dortfolio Overall Dortfolio Utilitv Cost Test Dortfolio Dortfolio Overall Dortfolio
Electric avoided cost 988 558 791 724 10,780,282 Electric avoided cost 988 558 791,724 10,780,282
Non-Energy benefits $734,371 734 371 Natural Gas avoided cost 047 009 (148 162)898.848
Natural Gas avoided cost 047,009 (148,162) $898 848 UCT benefits 12,035,568 643,562 12,679,130
TRC benefits 769 939 643,562 15,413 501
Non-incentive utility cost 121 664 80,587 202,251
Non-incentive utility cost $121 664 80,587 202,251 Incentive cost 283,417 848,100 131 517
Customer cost $12,414 388 734 181 148,569 UCT costs 3,405,081 928,687 333,768
TRC costs 13,536,052 814,768 350 820
UCT ratio
TRC ratio Net UCT benefits $630,487 (285,125) $345,362
Net TRC benefits $233,887 (171,206) $062,681
Regular Income Limited Income Gas and Electric Non- Regular Income Limited IncomeParticiant Test Dortfolio Dortfolio Overall Dortfolio Participant Test Dortfolio Dortfolio Overall Dortfolio
Electric Bill Reduction $14,470,803 336 613 $ 15,807,416 Gas avoided cost savings 545,400 241 ,856 787 256
Gas Bill Reduction $082,092 (229 745)852,347 Electric avoided cost savings 701 269 791,724 492,993
Non-Energy benefits 734 371 734,371 Non-Part benefits $13,246,669 033 580 280 249
Participant benefits 287 266 106,868 $ 20,394 134
Gas Revenue loss $795,267 265,792 061,060
Customer project cost $12,414 388 734 181 $ 13,148 569 Electric Revenue loss 164 016 336,613 15,500,629
Incentive received $(2,283 417) $(848 100)(3,131 517)Non-incentive utility cost 121 664 80,587 202,251
Participant costs 10,130 971 (113,919)$ 10 017,052 Customer incentives 283,417 848,100 131 517
Non-Part costs 364 364 531 093 23,895,457
Participant Test ratio (9.72)
Net Participant benefits $156 296 220 786 $ 10,377,082 Non-Part. ratio
Net Non-Part. benefits $117,695) $497,512) $(9,615 207)
Annual kWh savings
Annual therm savings
33,251 519
304,458
Limited
Income
Dortfolio
364 528
(47,719)
Overall Dortfolio
35,616 047
256 738
Regular Income
Descriptive Statistics portfolio
NOTES:
Costs associated with membership in regional programs are excluded from all cost-effectiveness calculations.
N/A" is listed for segments with benefits, but no costs.
fi
Narrative to Table 14
Table 14 is an outline of the Company s four separate tariff rider balances (Washington and Idaho, gas andelectric).
These balances began the year $12.4 million negative and ended the year $8.7 million negative,
representing a $3.7 million improvement. This was actually composed of a $4.1 million improvement in
the electric tariff rider balance and an unfavorable $0.4 million change in the gas tariff rider balance.
The lack of progress on the gas tariff rider balance was the result of a warm winter and the price elasticity
impact of PGA-induced retail rate increases. (The gas tariff rider is not levied upon the PGA portion of the
retail rate, but it does suffer from the reduction in consumption attributable to PGA increases). When the
business plan was originally developed it was believed that these PGA increases would begin a downward
trend in the fall of 2003. This would tend to bring the gas tariff rider balances towards zero as a result of
both increased gas usage (due to lower retail rates) and decreased demand for incentives (due to less
favorable participant economics). Given that these assumptions have not been and are not likely to be
realized we will be revisiting this portion of the business plan in 2003.
The electric tariff rider balance was considerably more negati ve than the gas tariff rider and is returning
towards zero fairly rapidly. The Idaho balance has been and is projected to continue to return to zero more
rapidly due to the higher tariff rider surcharge in that state.
In aggregate the tariff rider balances are returning towards zero more quickly than was originally projected
in our business plan. However there is a need to step into the next phase of the business plan, that being the
management of each of the four balances independently rather than in aggregate, during 2003.
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.
Narrative to Table 15
The Company committed to delivering energy savings (both electric and gas) that are at least proportionate
to the percentage of the tariff rider revenues that were being expended. In 2002 we delivered electric
savings that were 195% of proportionate and gas savings that were 160% of proportionate.
These amounts have been adjusted to remove the impact of lagged incentive payments from 2001 and.
projects scheduled for payment in 2003 that contributed to 2002 energy savings. An adjustment has also
been made to realize the full amount of regional expense invoiced to A vista during this time but not
recognized in cash expenditures until 2003.
It is uncertain whether this same level of proportionality can be sustained, but it is fairly certain that we will
be able to continue to substantially exceed the proportionality commitment that has been made. Individual
goals for account executives and engineers are based on a minimum of a 110% proportionality and a
stretch" goal of achieving the full 40 million kWh's identified in our Schedule 90 tariff in spite of the
reduced expenditures.
J?"
p% Sa-
Jle 15EG Calculation of Energy Savings vs. Utility Expenditure Proportionality
Actual 2002 cash expenditure
Less cash incentive
Add in derated incentive
Adjusted (for incentives) utility expenditur
Add in NEEA expenditures deferred to 200
Total adjusted utility expenditure
DSM reveneu
Adjusted utility expenditures divided by actual revenu
Energy savings from Triple-E Repo
Tariff go
% of goal achieve
Proportional!
With adjustments for derations and NEEA Without adjustment for derations and NEEA
Electric Gas Electric Gas
916,308 351 799 916,308 351,799
s $698,342) $272,763)
616,236 515,281
834 202 594,318 916,308 351,799
387,762
221 964 594 318 916,308 351,799
s $221 211 934,174 221,211 934,174
45%171%40%145%
)11 34,882,381 653,983 34,882,381 653,983
40,000,000 240,000 40,000,000 240,000
87%272%87%272%
195"10 160"10 216%188%
NOTES:
(1) Adjustments for the difference between cash incentives and those accrued as projects move through the "pipeline" (contracted to construction to
completed) remove the effect of scheduling cash payment of incentives to future dates.
(2) Avista had two NEEA incentives being processed for payment at the close of 2002