20140707Hymas Direct.pdf

RECEIVED
?0lt JUL -? Al,l 9: s8
ur*'B#bo&1ffi18*'o'n
BET'ORE TITE IDAHO PTJBLIC UTILITIES COMMISSION
IN THE MATTER OF TI[T'
APPLICATION OF ROCI(Y
MOUNTATN POWER REQUESTING
PRUDENCY DEIERMINATION ON
DEMAhTD.SIDE MANAGEMENT
DPEI\DITI]RES.
CASE NO. PAC.E.1+07
Direct Testimony of Kathryn C. Hymas
ROCI(Y MOT]NTAIN POWER
CASE NO. PAC.E-1+07
July 2014
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a. Please state your name and business address with PacifiCorp dba Rocky
Mountain Power (6'the Company").
A. My name is Kathryn C. Hymas, and my business address is 201 South Main,
suite 2400, Salt Lake city, utah 84111.
Qualifications
a. What is your current position at the Company, and what is your employment
history?
A. I am currently employed as the Vice President of Rocky Mountain Power Finance
and Demand-Side Management ("DSM") for PacifiCorp. I have been employed
by Rocky Mountain Power or its predecessor companies since 1983. My
experience at Rocky Mountain Power includes various positions within finance
and business services organizations at the Company.
What are your responsibilities as the Vice President of Rocky Mountain
Power Finance and DSM?
I am responsible for demand-side management for Rocky Mountain Power and
for Pacific Power. This includes, the planning, development, design, approval and
implementation of programs designed to reduce energy consumption through
energy effrciency and behavioral changes and to reduce consumption during peak
periods of usage through load control. I am also responsible for finance functions
for Rocky Mountain Power.
What is your educational background?
I received a Master of Accountancy from Brigham Young University in 1979 and
a Bachelor of Science degree in Accounting from Brigham Young University in
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Rocky Mountain Power
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1978. In addition to my formal education, I have also attended various
educational, professional, and electric industry-related seminars, including the
Utility Executive Course offered by the University of Idaho.
Have you appeared as a witness in previous regulatory proceedings?
Yes. I was the witness for the Company's depreciation study in2002.
What is the purpose of your testimony in this proceeding?
The purpose of my testimony is to demonstrate that the Company's DSM
invesfrnents made on behalf of Idaho customers were prudent. Specifically, my
testimony lays out the Company's request for a determination that DSM expenses
of $25,765,486 for program years 2010 through 2013 were prudently incurred.
This'amount includes $17,664,805 funded through Electric Service Schedule No.
l9l, Customer Efficiency Services Rate Adjustment ("Schedule 191") and
$8,100,681 of Irrigation Load Control program incentive payments which were
included in the Company's 2011 general rate case, Case No. PAC-E-ll-12, and
approved January 10, 2012, in Commission Order No. 32432. Expenditures by
year are summarized below.
Year
2010
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Total:
Expenditures
$7,515,026
$8,100,681 (load management incentives)
$2,8r5,694
s3,459,989
$3.874"096
s25,765,486
My testimony will also provide the following:
o A summary of the Company's previous request for prudency
determination.
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Rocky Mountain Power
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o Information on how this filing is consistent with the Memorandum of
Understanding ("MOU"). I
o An overview of the individual DSM programs and performance.
o A discussion of the DSM expenditures included in the filing and Schedule
191 balancing account.
o An overview of cost effectiveness and evaluations.
o A sunmary of changes that have occurred with the progftrms since the last
prudency determination.
Summary of the Previous Prudency Request
a. Please provide a brief description of the Company's previous prudency
determination request to the Idaho Public Utilities Commission
("Commission").
A. As part of Case No. PAC-E-10-07 (the "2010 general rate case"), the Company
provided supplemental testimony and exhibits on August 6, 2010, to support a
prudency determination from the Commission on DSM expenditures for 2008 and
2009. This was done as a result of Order No. 32023 in which the Commission
stated that it "reserves questions of the prudency and cost-effectiveness of the
Company's DSM programs and expenditures for the Company's pending rate
case" and encouraged parties "to address these issues in the rate case.o'
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Rocky Mountain Power
I Case No. GNR-E-I 2-01, Order No. 32788.
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In the 2010 general rate case, did the Commission find the 2008 and 2009
DSM expenses to be prudently incurred and approve recovery of the DSM
expenses?
Yes. Order No. 32196 issued February 28,2011, on page 59 states the following
with regards to the prudency of the Company's DSM expenditures for 2008 and
2009:
The Commission recognizes the Company's DSM Memorandum
of Understanding commitments and its compliance efforts;
accepts Staffs analysis of the Company's 2008 and 2009 DSM
progftrms and related expenditures; finds the expenditures to be
just, reasonable and in the public interest; and finds the costs to
be prudently incurred and appropriate for recovery in the
Company's Schedule 191 (Customer Efficiency Services Rate
Adjustment) tariff.
Why is the Company requesting a prudency determination at this time and
not during a rate case?
Historically, the Company has requested prudency determination for DSM
programs from the Commission in a general rate case. It has been four years since
the last determination and the next general rate case is not expected to be filed
until 2015. Third party program evaluations have recently been completed for
most of the programs and the Company wishes to receive prudency determination
from the Commission to ensure that the Company has prudently managed DSM
progrztm funds. This is the first request since the prudency determination in 2010.
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Rocky Mountain Power
1 Memorandum of Understanding Consistency
2 a. Is this prudency filing consistent with the MOU for prudency determination
3 of DSM expenditures that was signed by Rocky Mountain Power, Avista and
4 Idaho Power in December 2009 and by the IPUC staff in January 2010?
5 A. Yes, this filing and the Annual DSM reports are consistent with the MOU. Rocky
6 Mountain Power filed annual reports with the Commission for program years
7 2010, 2011, 2012, and 2013. These reports followed the format set forth in the
8 MOU and included: Table of Contents, Introduction, Cost Effectiveness, Program
9 specific sections, and Evaluations. Program performance, including expenditures,
10 savings and assessments of cost effectiveness, as well as the balancing account
l1 activity associated with Schedule 191 were included in the annual reports.
12 Overview of DSM Programs and Performance
13 a. Please provide an overview of the Company's Idaho DSM program portfolio.
14 A. The Company's DSM portfolio consists of seven distinct programs offering
15 incentives for a wide variety of energy efficiency measures to the Company's
16 residential, business and agricultural customers and participation in the irrigation
17 load management program to the Company's agricultural customers. The
l8 Company continues to work with customers and the Commission to provide a
19 comprehensive suite of DSM programs that provides the greatest opportunity for
20 participation by all customer sectors.
2l a. What DSM programs subject to Schedule 191 were available to Rocky
22 Mountain Power customers during the time period of 2010 through 2013?
23 A. The Company offered seven DSM programs from 2010 through 2013 that were
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Rocky Mountain Power
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subject to Schedule 191. Collectively, the programs offered a wide range of
services and financial incentives to assist customers with energy efflrciency
projects they wished to pursue. The DSM programs are as follows:
. Schedule2l - Low Income Weatherization/Low Income Education
o Schedule 72 & 72A - Irrigation Load Control (effective in 201 I these
program expenditures changed to a system-wide cost, no longer flowing
through Schedule 191.2 ScheduleT2 &Z2Lwere later cancelled as a
result of this change.3)
o Schedule 115 - FinAnswer Express
. Schedule 117 - Residential Refrigerator Recycling
o Schedule 118 - Home Energy Saver Incentive
o Schedule 125 - Energy FinAnswer
o Schedule 155 - Agricultural Energy Services
Please describe the DSM annual reports submitted as Exhibit No. L.
Exhibit No. I consists of the four Idaho DSM annual reports filed with the
Commission for program years 2010,2011,2012, and 2013. The annual reports
follow the format that was laid out in the MOU. Program performance, including
expenditures, savings and assessments of cost effectiveness, as well as the
balancing account activity associated with Schedule 191 are included in each
year's annual report.
What was the Company's DSM performance for 2010?
Energy efficiency program savings at the meter in 2010 were 11,963 MWH. The
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2 Case No. PAC-E-10-07, Order No. 32196.
3 Case No. PAC-E-12-14 Order No. 32760.
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Company's Irrigation Load Control program had participating loads under
management of 283 MW at meter in 2010.
What was the Company's DSM performance for 2011?
Energy efficiency program savings at the meter in 2011 were 8,688 MWH and
Irrigation Load Control program reported participating load under management of
258 MW at meter.
What was the Company's DSM performance for 2012?
Energy efficiency program savings at the meter in 2012 were 11,420 MWH. In
2011, the Irrigation Load Control program was treated as a system-wide benefit.
Performance results for 2012 were no longer included in the DSM annual reports
but were submitted as a confidential document to the Commission.
What was the Company's DSM performance for 2013?
Energy efficiency progrirm savings at the meter in 2013 were 18,324 MWH. A
sunmary of the Company's DSM perfofinance by year and by program are
provided in Table 1:
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Rocky Mountain Power
able I -of Prosram Perfomrance for 20 2011.20 2 rnd2Ol
20 0 20tt 2012 *20 3*
Pro.pnam
MW/Yr
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MWYr(* site)
MW/Yr
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MllYlYr
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{atisitC)
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Irrisation Load Control 28:30t 2s8 281
Iotal Load Control 283 308 258 281
MWl,/Y!
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Savings'
{at sitoli
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'il,*f ,,oerll
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{d,per)
Low Income Weatherization 7t 75 229 251 23(25'.,t0t 11
Low Income Education 23 2:2l 2:
Refriserator Recvclins 1.03(1"13!943 1.03:806 89!692 77i
Home Enersv Savinss J.JJ I 3.66'2.4|2.651 2.61',,2,91',,2,512 2,801
Total Residential 4.438 4,879 3.606 3.965 3.674 4.095 3.307 3.68(
Energy FinAnswer 1,47:t.60!48i s3t 3rt 34i 2.339 ) <)(
FinAnswer ExDress 3,535 3.8&) )2,t 2.441 4.47:4.88:5.35(5.83:
Apnicultural Enersv Services ? sl5 2.743 2.36{) <'7t ) Q\t 3.29i 1 7)a 8.16(
Total Commercial & Industrial 7.525 8.216 s.082 5.549 7.746 8.s20 t5-017 t6-52!
Iotal Energy Efficiency I 1.963 13.096 8.688 9-51 tl-424 t2-6ts t8,324 20.21
* lnigation Load Control MW savings for 2012 and 2013 were reported as confidential and therefore are not captured in this
summary.
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DSM Expenditures and Schedule L9L Balancing Account
a. What is the amount of DSM expenditures that the Company
Commission to find prudently incurred?
A. The Company is requesting that the Commission find DSM
$25,765,486 from 2010 through 2013 were prudently incurred.
includes $17,664,805 funded by the Schedule 191 and $8,100,681
Load Control program incentive payments.
is asking the
expenses of
This amount
of Irrigation
a.
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Has the Company provided a breakdown of the expenditures by category as
requested by Commission staff?
Yes. The Company has broken down the yearly expenses into the following
categories: program delivery administration, Company administration, customer
and dealer/trade ally incentives, engineering, evaluation, marketing and program
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development. Expenditure breakdown by program for each year can be found in
Exhibit No. 2.
In Exhibit No. 2 the Company has included $44,238 in 2012 for Irrigation
Load Control. Please explain why this expense is applied towards Schedule
191.
In September of 2012, the Idaho State Tax Commission completed its audit of the
Company's sales and use tax retums for the period from December 2008 through
November 2011. As a result of this audit, the tax department determined that the
sales tax on equipment purchased for the Irrigation Load Control program in 2009
was underpaid. The progftrm expenditures during this period were collected
through Schedule 191, so the sales and use tax for 2009 was included in Schedule
191.
In Exhibit No. 2 the Company included $6,477 in 2012 and $23,705 in 2013
for a Technical Reference Library. Please describe what this is.
In 2013, the Company completed development of the Technical Reference
Library which contains measure-level savings data, including the methods,
assumptions and sources for those assumptions used for reporting energy savings
and incentive payments to customers. This data will be used for program delivery,
evaluations, planning or reporting purposes.
In Exhibit No. 2 the Company has included $13,566 in 2013 for DSM
Central. Please describe what this is.
A. ln 2013, the Company upgraded of the tracking system used by the DSM
department to store information on customer projects. The system is known as
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DSM Central and integrates with the Technical Reference Library. This system
integration becomes a control to ensure measures are reporting the correct unit
energy savings values and that incentive payments are being issued to the
customers compliant with the DSM tariff.
When the Commission approved suspension of the prescriptive measures in
the Idaho Agricultural Energy Services programrn Staff expressed concern
over the administrative expenses. Did the Company include detail of the
expenditures to explain these costs?
Yes. The Company prepared Exhibit No. 3 to show the detail of services rendered
from the invoices paid to the third party administrator. The costs are categorized
to show progrurm administration and engineering services.
Did the Company incur program expenditures during 2010-2013 that
impacted the cost effectiveness of the Low Income Weatherization program?
Yes. On Apil29,2011, the Company filed an application, Case No. PAC-E-11-
13, requesting to suspend future obligations to perform program evaluations on its
Low Income Weatherizationprogram Schedule 21. In response to the many data
requests that resulted from this filing, the Company incurred additional program
cost in the amount of $37,143. This expense caused additional strain on the
program's cost effectiveness which was already below 1.0. The Commission, in
response to this filing, issued Order No. 32440 instructing all utilities to
participate in a public workshop to resolve the cost effectiveness issues with Low
Income Weatherization. This will be discussed further in the Cost Effectiveness
Overview section of my testimony.
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Rocky Mountain Power
a Case No. PAC-E-13-10, Order No. 32879.
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What was the 2010 through 2013 expenditure totals in Schedule 191
balancing account?
Schedule 191 expenditure totals for each year was:
Year
2010
20tr
2012
2013
Expenditures
$7,515,026
$2,669,984
$3,371,757
$3,815,665
Why are Schedule 191 expenditure totals from 2011 through 2013 different
than the totals stated earlier for the prudency request?
Beginning with the 2011 annual report, the Company changed its reporting of
program costs to match costs incurred with energy savings achieved in that
program year. This was completed as part of the year-end reconciliation. The
Company reviewed the line item cost details for each program and removed those
expenditures that should have been included as part of 2010 program year cost. In
addition, the Company added expenditures to the 2011 program year cost that
were processed in 2012 that were related to energy savings achieved in 201 1. This
process is applied to each year's reconciliation of program costs to reported
program savings. The 2010 expenditures that were removed from 2011 and were
not included in the 2010 DSM annual report due to the change in accounting
practice, totaled $233,536. This amount was reviewed and considered to be
reasonable and prudent for each program.
Besides year-end reconciliation, does the Company have other processes in
place to ensure expenditures are captured correctly to the Idaho programs?
Yes. On a daily or as needed basis, invoices are reviewed to contract/tariff terms
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for accurate billing including engineering services, third party administration and
incentive payments. Once review has been completed, the program managers
acknowledge services were rendered before it is routed for account coding. The
approving manager will review all prior steps completed, confirm the accounting
being charged based on description of invoice and approve the payment. At the
end of each month the expenditures are reviewed by a business analyst to ensure
labor charges are only from those authorized and text descriptions of expenditures
posted are in alignment with the program being charged. On a monthly basis,
management reviews performance of energy savings and expendifures of
programs for the month, year to date and against forecast, including the review of
Schedule 191 balancing account.
Has the Company reconciled the differences in expenditures submiffed for
prudency against Schedule 191 balancing account?
Yes. This reconciliation detail can be found in Exhibit No. 4. The first worksheet
is a summary of the prudency request and compares the deferred charges against
Schedule 191 balancing account. The remaining worksheets provide the detail by
year by program of the year end reconciliation broken down by category.
Were there any other accounting changes made during this prudency liling
period that impacted the Schedule 191 balancing account?
Yes. In December 2011 the Company changed from cash basis to accrual basis
when recording expenditures for Schedule l9l in the balancing account. The
Company determined the accrued expenses were a liability the Company would
be obligated to pay even if the program were to end, therefore needing to be
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I recognized in Schedule 191 balancing account. This accrued liability is not
2 included in the calculation of the carrying charge.
3 Cost Effectiveness Overview
4 a. How does the Company determine if a program was cost effective?
5 A. In assessing cost effectiveness, program costs and benefits are analyzed using
6 different benefit/cost tests as described in the California Standard Practice Manual
7 for assessing DSM programs' cost effectiveness. These tests include Total
8 Resource Cost Test ("TRC") which examines the programs' benefits and costs
9 from the Company's and participants' perspectives combined; Utility Cost Test
10 ("UCT") which looks at the benefits and costs from the Company's perspective;
1l and the Participant Cost Test ("PCT") which looks at the average participating
L2 customer's benefits and costs. The Company works towards having all programs
13 achieve a benefit/cost ratio of 1.0 or greater for these tests. Other tests the
14 Company looks at includes PacifiCorp Total Resource Cost Test ("PTRC") which
15 is a variant on the TRC, also called the Societal Cost Test, which expands on the
16 TRC by including a 10 percent adder to reflect non-energy benefits and the
17 Ratepayer Impact ("RIM") which examines the impact of energy efficiency on
18 utility rates due to changes in utility revenues and operating costs caused by an
19 energy efficiency program. Programs typically do not pass the RIM test due to the
20 financial impacts of reduced loads. As stated in the MOU all cost effectiveness
2l tests are analyzed but the Company places emphasis on the TRC and UCT as the
22 best metric for comparing demand-side resources to supply-side resources.
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What were the cost effectiveness results for 2010 through 2013?
The cost effectiveness results provided in Table 2 are summaized to show the ex-
ante results of the TRC, UCT and PCT for the energy efficiency and load
management programs. In addition, Table 2 also includes the results consolidated
at the sector and the portfolio level as applicable.
These results show that of the seven programs for which the Company reports
energy savings, five of the programs had a benefit/cost ratio greater than 1.0 for
both the TRC and UCT in all years. The Agricultural Energy Services program
was cost effective for both TRC and UCT for all years except in 2013 when the
benefit/cost ratio for the TRC was 0.84. These results were a result of increased
volumes of nozzle exchanges and pivot and linear equipment upgrades as a result
of customers leaming of the Company's application to the Commission for
program changes where prescriptive measures were being suspended. The Low
Income Weatherization program was not cost effective for the TRC or UCT in
any ofthe years.
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Table 2 - Cost Elfectiveness Summary for 2010 through 2013
2010 BenefiUCost 2011 Benefit/Cost 2012 BenefitlCost Test 2013 BenefiUCost Test
Bv Program TRC rlr*f,T'TAT TRC UCT PCT PTRC TRC I]CT PCT PTRC TRC UCT PCT
lrrieation Load Control 2.90 r.00 N/A Pass Pass N/A Pass Pass N/A Pass Pass N/A
Low Income Weatherization 0.66 0.66 N/A 0.74 0.74 N/A 1.06 0.70 0.70 N/A 0.8r 0.60 0.60 N/A
R efrioerstnr Recvclino 1.15 r.08 N/A 1.59 N/A 2.61 2.02 N/A 1.48 1.48 N/A
Home Enerw Savinss 2.14 2.26 3.76 2.0s 2.51 1.56 2.22 2.98 1.54 1.5 t 3.27
Energv FinAnswer 2.t9 2.5s 4.12 .51 1.93 2.62 t. l0 t.25 3.18 1.74 3.74 2.9
FinAnswer Exrress 1.99 3.26 2.93 07 1.87 1.62 1.56 3.37 1.76 1.44 2.16 2.63
Aericultural Enerey Services 1.07 1.33 1.81 .26 1.74 l.5l 1.34 1.84 2.20 0.84 l.14 0.86
Bv Sector
Resllential 1.93 2.01 4.09 1.07 1.38 3.34 1.39 l.(A 4.36 1.28 1.20 4.03
Commercial & lndustial 1.70 2.34 2.73 l8 l.8t r.6 l. l6 1.75 1.92 1.12 t.u 1.60
Enerpv Efficiencv Portfolio 1.80 2.18 3.30 l.l3 l.6l 2.r7 1.23 1.71 2.43 l.li l.5t | _95
At Portfolio 2.38 1.2s 7.01 3.9s 2.22 4.9t
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Please explain why the cost effectiveness results for lrrigation Load Control
program are only provided for 2010.
Per Commission orders approved on February 28, 2011, the treatment of the
Irrigation Load Control program costs changed from direct assignment to Idaho,
to a system-wide expense excluded from Schedule 191. The cost effectiveness
results from 2011 through 2013 were reported as confidential and therefore are
not captured in this table. Instead they were reported as Pass or Fail.
Please discuss what activities the Company has undertaken to address the
cost effectiveness for the Low Income Weatherization program.
The ex-ante cost effectiveness for 2010 was less than 1.0 for both the TRC and
UCT. At the same time the Company was in the process of having a third party
consulting firm complete the evaluation for program years 2007-2009. This report
was completed on April 20, 2011. As a result of the report, the Company filed an
application seeking authorization to remove future obligations to perform
program evaluation on its Low Income Weatherization program.6 The
Commission deferred any final decision whether to suspend program evaluations
and directed that public workshops examine the common issues with all utilities
and interested stakeholders and determine the appropriate mechanisms to measure
the cost effectiveness of low income weatherization progrirms. The Company
participated in these workshops and responded to many data requests in an effort
to determine how low income weatherization programs should be assessed. As a
5 Case No. PAC-E-I0-07, Order No. 32196.
6 Case No. PAC-E-I l-13.
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result of these workshops, participating parties identified 18 recommendations
that were approved on April 12,2013,by the Commission.T
Did the Company implement the recommendations for calculating the cost
effectiveness of the Low Income Program?
Yes. Starting in 2012 the Company implemented all recommendations that could
be applied towards the ex-ante cost effectiveness assessment. As listed in Table 2,
the PTRC results were inserted to show the benefiVcost ratios for the Low Income
Weatherization program for 2012 and 2013. ln 2012 the program was cost
effective looking at PTRC, which was approved as an appropriate test for this
program. However, in2013 the PTRC results decreased back below 1.0 to 0.81.
If the low income weatherization recommendations were all implemented,
why was the cost effectiveness for 2013 below 1.0?
The cost effectiveness falling below 1.0 in 2013 is largely due to a decrease in
number of homes served and measures installed by over 28 percent from the
program's 2012 results and a decrease in the Company's avoided costs.
What is the Company doing to improve the Low Income Weatherization
program's cost effectiveness?
On December 19,2013, the Company participated in a utility partnership meeting
sponsored by Community Action Partnership Association of Idaho to review,
summarize and provide clarity on the approved recommendations. Additional
discussion took place to offer a more cost effective low income weatherization
program approach. The Company is also investigating possible program
improvements while awaiting the results of the 2014 evaltation report for
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Rocky Mountain Power
7 Case No. GNR-E-12-01, OrderNo. 32788.
I program years 2010-2012 before making a determination on what broader actions
2 will be necessary to ensure program cost effectiveness.
3 Q. Are there any items that are included in the cost effectiveness assessments
4 that are not included in or collected through Schedule 191?
5 A. Yes. The Irrigation Load Control credits issued to the participants of the program
6 are not collected through Schedule 191; however, the credits issued in 2010 and
7 2011 were included in the portfolio level cost effectiveness. tn 2010, the amount
8 included for prudency request was $8,100,681. In 2011, the amount included in
9 the portfolio level cost effectiveness, but not included for prudency request, was
10 56,074,644. The program expenditures being requested for prudency in 2011 for
1l the Irrigation Load Control program are $7,939 which is identified on the
12 suurmary worksheet of Exhibit No. 2.
13 Evaluation Overview
14 a. Please discuss the Companyos objectives with program evaluations.
15 A. Evaluations are conducted using best-practice approaches and techniques
16 including those outlined in the National Action Plan for Energy Efficiency
t7 ("NAPEE") Program Impact Evaluation and the California Evaluation Framework
18 guides. The Company conducts process and/or impact evaluations on energy
19 efficiency and load management programs to ensure the ongoing cost
20 effectiveness of its programs through validation of energy savings and to provide
2L information to assist in management of its progrirms.
22 Process evaluations assess program delivery, from design to
23 implementation, in order to identiff bottlenecks, efficiencies, what worked, what
Hymas, Di - 17
Rocky Mountain Power
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did not work, constraints, and potential improvements. Identi$ring opportunities
for improvements is essential to making corrections along the way.
Impact evaluations determine the impacts (e.9. energy and demand
savings) that directly result from a program. Impact evaluations also support cost
effectiveness analyses aimed at identiffing relative program costs and benefits.
Evaluations are based on credible and transparent methods and efforts to
be successful in capturing the savings that programs offer. Evaluations develop
retrospective estimates of energy savings attributable to a program. While
evaluations will be retrospective in nature, the information obtained will be used
to inform future potential assessments, plans, forecasts and targets.
Which DSM programs have undergone a third party evaluation since the
previous prudency determination for the 2008 and 2009 program years?
The program evaluations and reports completed during 2010-2013 are listed in
Table 3. The evaluation reports are included in Exhibit No. 5.
i.,H::'
Other I - Idaho Post Peak Repon
Other 2 - Miscellaneous third party EM&V activit"v
a. Please provide an overview of the evaluations completed in 2010.
A. The Company completed five process and impact evaluations during 2010. Each
Hymas, Di - 18
Rocky Mountain Power
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Table 3 - Demand-side Management Program Evaluations Completed in 2010-2013
2010 2011 2012 20r3
[arldcntirl I
r' .,Ye.rt!, ,
Evirluite{
-fvaluetion
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Evaluated
Evdurtlon Yerrs
nwclrrqfed
Evaluatior
Tim
Ye ut.'
f'mhofsrf
Evrluation
Low Income Weatherization ,no?_rnno P&r
Refriserator Recvclinp 2006-2008 P&I 2009-201 0 P&t 2011-2012 P&I
Home Enersv Savinqs 20062008 P&I 2009-201 0 P&I
lommercial & Ildustrlal Prcgrams
Enerw FinAnswer 2008 P&I 2009-201 I P&I
FinAnswer ExDress 2004F2008 P&I 2009-201 I P&I
Aqricultural Enersv Services 200G2008 P&I 2(n9-20lL P&I
Load Maneee nrent Prognms
Inisation Load Control 2009-2010 Other 2 2012 Other I 2013 Other 1,2
1
2
of these evaluations were completed by third party consulting firms. Three of the
five programs evaluated during 2010 had a TRC and UCT benefit/cost ratio
greater than 1.0, except for Home Energy Savings and Agricultural Energy
Services programs. The Home Energy Savings program for the evaluation period
2006-2008 was cost effective from the UCT perspective with the TRC being 0.83.
The cost effectiveness results were impacted by start-up costs in the first year and
lower than expected CFL sales in 2008. Agriculture Energy Savers evaluated
TRC and UCT ratios were 0.39 and 0.57 respectively. Due to the high uncertainty
associated with the evaluation results, the cost effectiveness was also calculated
based on Regional Technical Forum's ("RTF") proposed deemed savings. Under
this savings scenario, the program was cost effective for the TRC and UCT tests.
Please provide an overview of the evaluations completed in 2011.
Two evaluations were completed by third parry consulting firms in 2011. A
process and impact evaluation was conducted on the Low Income Weatherization
program. The cost effectiveness results of the 2007-2009 program evaluation
found the program to not be cost effective without non-energy benefits. On April
29, 2011, the Company filed an application requesting to suspend future
obligations to perform program evaluations. The Irrigation toad Control program
was evaluated for 2009 and 2010 to determine demand impacts of the programs.
This analysis estimated the hourly load reductions achieved by the program
during the 2009 and 2010 control season.
Please provide an overview of the evaluations completed in 2012.
The Company completed two process and impact evaluations during 2012. These
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Rocky Mountain Power
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evaluations were completed by third party consulting firms. All programs
evaluated during 2012 had a TRC and UCT benefit/cost ratio greater than 1.0.
The Company also conducted an internal review of the post peak irrigation system
review to understand the impacts of the Irrigation Load Control program.
Please provide an overview of the evaluations completed in 2013.
The Company completed four process and impact evaluations during 2013. Each
of these evaluations were completed by third parfy consulting firms. All programs
evaluated during 2013 had a TRC and UCT benefiVcost ratio greater than 1.0
except for Agricultural Energy Services program. The Agricultural Energy
Services program for the evaluation period 2009-2011 was cost effective from the
UCT perspective with the TRC being 0.68. The evaluation also provided cost
effectiveness results at the measure category. The system redesign category was
cost effective for the evaluation period under the TRC and UCT benefit/cost ratio.
The equipment exchange and pivot/linear upgrade categories were not cost
effective based on the evaluated energy savings. During 2013, the Company
conducted an internal review of the post peak irrigation system review to
understand the impacts of the Idaho Irrigation Load Control Program. The
Irrigation Load Control program third party administrator also completed a report
providing an overview of the program. This report documents progftrm results,
accomplishments and challenges.
When will the remaining energy efficiency program years associated with
this prudency filing be evaluated?
The Low Income Weatherization program is being evaluated for program years
Hymas, Di - 20
Rocky Mountain Power
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2010-2012 with target completion by end of 2014. The commercial and industrial
programs of Agricultural Energy Savers, Energy FinAnswer and FinAnswer
Express programs are scheduled to be evaluated during 2015 for program years
2012-2013. The residential programs of Home Energy Savings and Refrigerator
Recycling are scheduled to be evaluated during 2015 for program year 20t3.
Did the evaluation for the Agricultural Energy Services program raise any
concerns?
Yes.
Please describe those concerns and how the Company has fixed the issues.
In an effort to address the high degree of uncertainty regarding the program
energy savings identified through third party evaluations, the Company filed an
application with the Commissions to revise Schedule 155 - Agricultural Energy
Services, to suspend: (l) the Nozzle Exchange Program; and (2) incentives for the
pivot and linear equipment measures. The Commission approved the request in
Order No. 32879, effective August 15, 2013.
Did the evaluation for the Low Income Weatherization program raise any
concerns?
Yes.
Please describe those concerns and how the Company has fixed the issues.
As discussed in the Cost Effectiveness Overview section, the Company
participated in workshops to address the cost effectiveness of the low income
weatheization programs. The Company has also requested that the results of the
2014 evahtation report for program years 2010-20t2 include an analysis to
8 Case No. PAC-E-I3-10.
Hymas, Di - 2l
Rocky Mountain Power
1 determine what changes could help the progr:rm achieve a PTRC benefit/cost ratio
2 of 1.0 or greater. Unless the Commission directs otherwise, the Company will
3 continue to offer the program while working to improve the program's cost
4 effectiveness.
5 Program Changes Overview
6 Q. Were there significant program changes during 2010-2013?
7 A. Yes. Irrigation Load Control, Agricultural Energy Services and FinAnswer
8 Express had significantprogram changes.
9 Q. Please describe the changes to the lrrigation Load Control program.
10 A. The Irrigation Load Control program was modified to address voltage excursion
11 issues experienced by Idaho customers as documented in Case No. PAC-E-I1-06,
12 Order No. 32235 which was approved on April27,20ll. The changes included:
13 an 18 percent reduction in participating load; no new participation accepted into
14 the program; changing the opt-out penalties to a percentage basis based upon
15 number of opt-out events; a decrease in incentive levels for 2011; and
16 miscellaneous administrative tariff changes.
17 ln 2013, the Company contracted with EnerNOC to administer the
18 Irrigation Load Control program. The contract with EnerNOC included: a Pay for
19 Performance agreement where EnerNOC assumes ful1 responsibility for the
20 installation, operation and maintenance of the irrigation load control devices,
2I dispatch of the devices as directed by the Company, customer recruitment,
22 customer service and issuance of irrigation credits to be paid to participating
23 irrigation customers; updated hardware including a near real-time two-way
Hymas, Di - 22
Rocky Mountain Power
1 communication system; and a shortened program season from June I - August 31
2 to the 10 full weeks that include June 15 and August 15. These program changes
3 were approvede by the Commission on March 18, 2013.
4 a. Please describe the changes with Agricultural Energy Services program.
5 A. The Agricultural Energy Services program was changed in August 2013 as a
6 result of Case No. PAC-E-13-10, Order No. 32879. The program suspended the
7 prescriptive measures and now offers only custom analysis of measures installed
8 to qualified customers. Custom analysis is based on pre-installation measurements
9 to develop savings estimates and post-installation verification of savings on a site-
10 by-site basis.
11 a. Please describe the changes with FinAnswer Express program.
12 A. In July 2012, the Company received approvallo to update the FinAnswer Express
13 program to align with new federal lighting standards and upcoming changes to
14 other codes, standards, third party specif,rcations and new market data.In addition,
15 the Company was authorized to offer the FinAnswer Express tariff utilizing a
16 "flexible tariff'approach to streamline program administration.
17 Conclusion
18 a. Does the Company believe that the information contained in this testimony
19 and attached exhibits supports a prudency determination for 2010-2013
20 DSM expenses?
2I A. Yes. Based on the cost effectiveness of the programs as supported by third-party
22 evaluations and the testimony set forth with the supporting exhibits, Rocky
e Case No. PAC-E-12-14, OrderNo. 32760.to Case No. PAC-E-12-10, OrderNo .32594.
Hymas, Di - 23
Rocky Mountain Power
a.
A.
Mountain Power respectively requests that the Commission determine
$25,765,486 of DSM expenses incurred during 2010-2013 were prudent.
Does this conclude your direct testimony?
Yes.
Hynas, Di-24
Rocky Mountain Power