20120625Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR A ) CASE NO. IPC-E-12-15
DETERMINATION OF 2011 DEMAND-SIDE )
MANAGEMENT EXPENDITURES AS ) COMMENTS OF THE
PRUDENTLY INCURRED ) COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's March 15, 2012 Application for an Order establishing that it prudently incurred
$42,641,706 in demand-side management ("DSM) expenses in 2011.
BACKGROUND
On March 15, 2012, Idaho Power Company (Idaho Power, or the Company) applied for
an Order establishing that it prudently incurred $42,641,706 in DSM expenses in 2011.
Application at 1. The Company asks the Commission to process the Application under Modified
Procedure. Id. at 7.
The Company says it has implemented or manages a wide range of opportunities for all
customer classes to participate in DSM activities, consistent with the Commission's direction
that the Company pursue all cost-effective DSM programs to promote energy efficiency. The
Company says it uses DSM programs to (1) provide customers with programs and information to
help them manage their energy usage, and (2) achieve prudent cost-effective energy efficiency
STAFF COMMENTS 1 JUNE 25. 2012
and demand response resources to meet the Company's electrical system's energy and demand
needs. Idaho Power consults with an Energy Efficiency Advisory Group (EEAG) that provides a
broad range of recommendations, including input on new program proposals, modifications to
existing programs, and overall expenditures of DSM funds. Id. at 2.
In this case, Idaho Power seeks a determination that it prudently incurred $35,623,321 in
Idaho Energy Efficiency Rider (Rider) expenses and $7,018,385 in custom efficiency incentive
expenses, for a total of $42,641,706 in DSM-related expenses. The Company notes that since
the Rider was implemented in 2002, Idaho Power has steadily increased the breadth and funding
level of its DSM activities. The Commission found the Company had prudently incurred cost-
effective DSM-related Rider expenses of $29 million from 2002 and 2007. Id., citing Order Nos.
30740 and 31039. Additionally, the Commission approved DSM-related Rider expenses of
$50.7 million from 2008 and 2009. Id., citing Order No. 32113. Further, the Commission found
the Company prudently incurred cost-effective DSM-related Rider expenses of $41.9 million in
2010. Id., citing Order No. 32331.
The Application says that in 2011, the Company continued its DSM programs to increase
participation and facilitate energy savings. The Company currently offers 17 energy efficiency
programs (16 of which are cost-effective; the Home Improvement Program was not for 2011),
three demand response programs (all of which are cost-effective from a long-term perspective;
the A/C Cool Credit program was not cost-effective for 2011), and several educational
initiatives. It also offers savings to customers through market transformation programs. Id. at
3-4. The Company notes that overall, energy savings from Idaho Power's efficiency activities in
2011 totaled 179,424 MWh. Id. at 3.
The Application attaches the Company's 2011 DSM Annual Report (the 2011 DSM
Report). The 2011 DSM Report provides detailed cost-effectiveness information by program
and energy savings measures as well as detailed financial information separated by expense
category and jurisdiction. Id. at 5. The Company uses four cost/benefit analyses to determine
cost-effectiveness of the programs: the total resource cost perspective (TRC), the utility cost
perspective (UCT), the participant cost perspective (PCT), and the ratepayer impact measure
(RIM). Id. The 2011 DSM Report also contains an evaluation section that includes the
Company's evaluation plans, copies of completed program evaluation reports, research reports,
and reports completed by the Company or third parties. Id. The 2011 DSM Report contains
STAFF COMMENTS 2 JUNE 25. 2012
specific information for each program, including its 2011 activities, a section on customer
satisfaction and evaluations providing an overview of process, impact, and market effect
evaluations. Id. at 6.
The Application says that independent, third-party consultants provide impact and
process evaluations to verify that program specifications are met, recommend improvements to
the programs, and validate program-related energy savings. Id. at 7. During 2011, impact
evaluations were completed on eight programs and process evaluations were completed on two
programs. Third-party consultants conducted eight of the evaluations. Id.
Based on the information provided with its Application, Idaho Power requests that the
Commission issue an Order designating the Company's expenditure of $42,641,706 in 2011 as
prudently incurred DSM expenses. Id. at 8.
STAFF ANALYSIS
The Rider funds about 83% of Idaho Power's DSM programs. The Company has
requested a prudency determination of $42.6 million, an amount that increased slightly from the
2010 prudency determination of $41.9 million. Staff notes that the Company continues to
generally meet the DSM reporting guidelines established in the 2009 DSM Memorandum of
Understanding (DSM MOU).'
Staff Attachment A compares Idaho Power's reported utility costs of $24.1 million for its
15 energy efficiency programs in 2011 to the estimated present value of utility benefits of $103
million over the projected lives of the installed measures. This analysis yields a 4.27 benefit/cost
ratio. Idaho Power's three demand response programs are projected to have average annual
utility cost of $15.3 million, which compares favorably with the reported average annual benefits
of $23.8 million for a benefit/cost ratio of 1.55. Net benefits to the utility indicate that future
rates paid by the utility's customers will be lower than they would be without the investment.
The Company claims a system-wide energy efficiency savings of 179,424 MWh,
including Northwest Energy Efficiency Alliance (NEEA) savings. The Company further claims
'The DSM MOU is a document signed by all Idaho three IOU's that outlines guidelines for a DSM prudency
determination. The document incorporates sections on management, planning, cost-effectiveness, evaluation and
reporting.
STAFF COMMENTS 3 JUNE 25. 2012
its demand response programs provide 403 MW of demand reduction capacity. Much of the
demand response capacity was not dispatched during 2011. The energy savings have dipped
slightly from 2010. However, the demand response capacity has continually increased over the
years since demand response was initiated.
Expenditures
Staff reviewed all expenditures charged to the Rider for 2011 and calculated the Rider
account balance as follows:
2010 Year End Balance
2011 Balance Transfer to PCA 2
2011 Funding plus Accrued Interest
2011 Expenses
Transfer to Oregon Rider
Adjustment to AC Cool Credit
2011 Year End Balance
$(1 7,595,938)
10,000,000
37,367,481
(35,096,540)
345
165,711
$( 5,155,941)
While preparing responses to Staff's production requests, Idaho Power discovered two customer
incentives for Oregon customers, paid through the Home Improvement Program, that were
inadvertently charged to the Idaho Rider. After filing this Application, Idaho Power removed
payments of $210 and $135 from the Idaho Rider and transferred these amounts to the Oregon
Rider as shown in the table above. Additionally, an adjustment to the A/C Cool Credit program
of $165,711 is discussed in further detail under the Demand Response section of this analysis.
2011 DSM Changes
Significant changes have been applied to the Company's 2011 DSM portfolio. Consistent
with the 2009 DSM MOU's reporting objectives, the Company has reported current and future
changes to DSM generally and to each program specifically. Pertinent changes include:
2 In Order No. 32217, dated April 1, 2011, the Commission authorized Idaho power to recover $10 million from the
Rider deferral balance through a Power Cost Adjustment (PCA) surcharge during the 2011 PCA year.
The Company's Application requests a prudency determination of $35,623,321, which is $526,781 more than the
net expenses included in this table. The $526,781 represents the incentive payments made to Oregon customers that
were inadvertently booked to the Idaho Rider in 2010, but corrected in 2011. The 2011 DSM net expenses are
$35,096,540.
STAFF COMMENTS 4 JUNE 25. 2012
1.Custom Efficiency incentive payments are now paid through a regulatory asset
account beginning January 1, 2011. Order No. 32245. The Commission authorized an
amortization period to be determined when the Company seeks recovery of the deferral balance.
Idaho Power reports a regulatory asset balance of $7,230,724 ($7,018,385 of incentive payments
and $212,339 in accrued interest). The Company is not asking to recover this amount now.
In the Stipulation filed in Case No. IPC-E-10-27, the signing parties agreed to a carrying
charge on the regulatory asset at a rate equal to the Company's approved overall rate of return.
However not all parties to that case signed the Stipulation and, in Order No. 32217, the
Commission ultimately rejected it. Discussion of the appropriate carrying charge was absent
from both orders in that case. Staff believes valid arguments exist for a carrying charge less than
that of the Company's rate of return. This issue can be more thoroughly vetted by all parties
when the Company seeks recovery and an amortization period is established in a general rate
case.
Idaho Power reports a Utility Benefit/Cost Ratio of 7.27 for this program, and a Total
Resource Benefit/Cost Ratio of 3.09. A 2011, independent impact evaluation confirms the
program's success and effectiveness. Staff recommends that the Commission approve the
incentives paid under the Custom Efficiency program as prudent expenditures, that the balance
of the Custom Efficiency regulatory asset account as of December 31, 2011 be set at $7,018,385,
and that the carrying charge and the amount of accrued interest be established when the
Company applies for recovery.
2.The avoided capacity cost for demand response increased from $63 to $94/kW as a
result of the Commission-accepted, 2011 Idaho Power Integrated Resource Plan (IRP). Order
No. 32425.
3.The Company applies an effective load carrying capacity (ELCC) of 93.4% to the
avoided capacity cost ($94) of its three demand response programs. The avoided capacity cost
for the Company's three demand response programs changed to $87.80 (93.4% of $94 yields
$87.80). Since demand response is viewed as a capacity resource, the ELCC is used to measure
the capacity of demand response against a thermal resource.
To obtain an ELCC of 93.4%, the Company analyzed the top 100 load hours in each of
the past 5 years. Of the top 500 hours, the number of hours that fell between the operating
parameters of demand response was used to calculate the ELCC. The Company maintains that,
STAFF COMMENTS 5 JUNE 25. 2012
because demand response programs cannot perfectly match the reliability of a generation
resource (due to the programs' limited availability), the Company should not claim the full
avoided capacity cost benefit of that supply-side resource. Staff finds this methodology
reasonable.
4.The Company altered the discount rate used to calculate the net present value (NPV)
of the benefits for the program participants. Formerly, the Company used a 6.98% weighted
average cost of capital (WACC) as the discount rate for participant costs and benefits. Now, a
3.88% discount rate is used. The Company says the new discount rate benefits participant bill-
savings and non-electric benefits. While Staff notes that multiple discount rates exist that can be
applied to the costs/benefits, Staff believes that the rate used is reasonable.
5.A one-time, $10 million deferral balance was transferred to the PCA mechanism
effective June 1, 2011 through May 21, 2012. Order No. 32217.
Several Commission decisions in 2011 will impact the DSM prudency determination for
the impending 2012 DSM review. First, the Commission adjusted the Rider from 4.75% to
4.0%, effective 2012. Order No. 32426. Second, a base level of$l 1.2 million in demand
response payments will be funded through base rates beginning January 1, 2012. Order No.
32426. Finally, the Company will recover all demand response incentive payments through base
rates and the PCA as power supply expenses.
While the Company will now recover demand response incentive payments through base
rates and the PCA, Staff recommends that the Company continue detailing its demand response
activities for prudency in the Company's DSM prudency determination. Staff believes it is more
appropriate for Staff to review and analyze demand response in the DSM prudency
determination than in a general rate case or PCA proceeding. The Rider will continue to fund a
substantial amount of expenditures for each demand response program, such as labor and
administrative expenses, materials and equipment, purchased services, and miscellaneous
expenses. For example, the 2011 A/C Cool Credit program spent about 73% of its total program
budget on expenditures that excluded customer incentive payments. Staff is opposed to
fragmenting demand response programs into multiple proceedings. Therefore, Staff considers
the DSM prudency determination to be the most appropriate venue for Staff analysis.
STAFF COMMENTS 6 JUNE 25. 2012
Cost-Effectiveness
The DSM MOU recognizes the cost-effective tests primarily from the perspective of the
UCT, TRC and PCT. Staff recognizes that the RIM perspective allows for a wider conceptual
context of the program. The Company's programs and measures were generally cost-effective
from a UCT and TRC one-year perspective. However, there were some exceptions.
1.The A/C Cool Credit program was not cost-effective for 2011 due to paging and
automated metering infrastructure (AMI) switches not functioning and a Company oversight on
software upgrades. The A/C Cool Credit program is discusses in greater detail later in Staff
comments.
2.The Home Improvement Program was not cost-effective for 2011 (TRC, RIM, PCT)
due to a change in the Regional Technical Forum's deemed savings for weatherization by
heating type and climate zone resulting in a large decrease in savings estimated with attic
insulation. Additionally, the 2011 third-party impact evaluation discovered the programs savings
estimates incorrectly included new windows in addition to insulation. Finally, of the 2,275
incentives offers, 40 incentives were paid to customers who submitted non-qualifying
applications. This was captured in the cost-effectiveness of the program, thus decreasing the
amount. The Company states that it has implemented a more rigorous participant review
process. Staff notes that 34 measures will be discontinued and three measures will be reviewed
for non-electric benefits. Staff has reviewed the Company's Home Improvement Program
analysis and finds the alterations to be reasonable and within the guidelines set forth in the DSM
MOU.
3.A total of 51 measures within various programs were not cost-effective from a UCT
or TRC perspective. Most of these measures will be discontinued and some will be reviewed for
non-electric benefits. The Holiday Lighting program was completely discontinued in 2011.
The Company continues to work within the cost-effectiveness guidelines 4 established in
the DSM MOU. Staff encourages the Company to continue updating the cost-effectiveness
assumptions with the most recent and correctly referenced sources. Staff expects the Company
"The DSM MOU calls for a cost-effectiveness section that lists programs and measures and includes the basis for
the cost-effective estimate, formulas, data inputs and assumptions, the source or rationale for each assumption, and
the corresponding date of the source referenced.
STAFF COMMENTS 7 JUNE 25. 2012
to include the correct status of the Regional Technical Forum measure (i.e. under review, active,
out of compliance).
Labor Expenses
Staff continues to have concerns with the escalating labor costs charged to the Rider
account. In 2011, Idaho Power charged approximately $2.64 million, or 7.5% of the total Rider
budget, in labor expenses to the Rider account. In 2010, labor expenses were approximately 6%
of the total DSM budget. Wage and Salary increases for Rider-funded employees continue to be
automatically passed on to customers without the level of scrutiny and evaluation that occurs
during a general rate case. The following table illustrates the increases in direct labor expenses
and labor loadings paid out of the Rider for 2005-2011:
Year Labor Total
FTE
Equivalents
Average Per
FTE
Equivalent
Average
Increase
2005 $ 434,301 5.6 $ 77,554 N/A
2006 $ 736,519 9 $ 81,835 5.52%
2007 $ 1,399,692 17.1 $ 81,853 0.02%
2008 $ 1,965,698 24.3 $ 80,893 -1.17%
2009 $ 2,293,136 25.7 $ 89,227 10.30%
2010 $ 2,577,080 26.7 $ 96,520 8.17%
2011 $ 2,637,729 26.4 $ 99,914 3.52%
Throughout several rate cases in 2011, Staff continually proposed adjustments for wage
increases during the tough economic times customers were facing. The table above illustrates
that the on average, Full Time Employee Equivalents (FTE) were seeing wage increases during
the recent recessionary period while many Idaho families were facing income reductions. Staff
continues to proposes that all wage increases for Rider-funded employees be excluded from the
Rider until the Commission has approved the wage increases in a general rate proceeding.
STAFF COMMENTS 8 JUNE 25. 2012
DEMAND RESPONSE PROGRAMS
A/C Cool Credit
Funding increased in 2011 by 44%, from $2 million to $2,781,553. Participation
increased 22%, from 30,391 participants to 37,728. The program was dispatched 14 times.
Comparatively, the program was dispatched three times in 2010. In 2011, an independent impact
evaluation was conducted on the A/C Cool Credit program, which indicated that the program
was not cost-effective in 2011 and will not be cost-effective until 2014. The program life cost-
effectiveness dropped from 1.11 to 1.10. The one-year TRC was not cost-effective at 0.74.
The cost-effectiveness decrease occurred because about 30% of A/C units or about
11,000 program participants were not cycled throughout the summer.5 The Company did not
discover the problem until well after the summer cycling season. To facilitate A/C unit cycling,
the Company may install four different types of switches that communicate with the A/C unit.
Two switches are AMI compatible and two are paging compatible. When an event is
dispatched, the Company will send a signal to communicate with AMI-compatible switches.
For A/C units with paging switches, a third-party paging provider is required.
A/C units were not cycled due to two problems. First, without Idaho Power noticing, a
paging company discontinued service to a large portion of the Company's service territory.
The second issue causing the decrease in the cost effectiveness of the program was with
the newest version of AMI-compatible switches. The Company used two different types of
AMI-compatible switches, and each switch required its own software and firmware. Rather
than running two separate operating systems for the switches, Aclara, the AMI switch
manufacturer, developed a code change that would allow both versions of the switch to be
dispatched through the same software.. The software change was tested successfully in a
controlled environment in fall 2010. However, following the successful testing of the new
software code, the Company failed to update its software throughout its system. This oversight
caused 7,891 A/C units in the Twin Falls, Idaho Falls and Boise area to not be cycled (February
22, 2012 EEAG).
Production Response V. The Company claims that some of the paging switches did receive the signal
intermittently throughout the summer, but the Company did not quantify that number.
STAFF COMMENTS 9 JUNE 25. 2012
This is the second consecutive year that participants in eastern Idaho were not cycled. In
2010, Twin Falls and Pocatello were not cycled because the two available paging companies
"discontinued their service" and no alternative paging providers "were available for that area"
(2010 DSM annual report, pg. 21). The Company brought this to the EEAG's attention and it
was determined that crediting the affected customers on their bills using non-Rider funds would
be appropriate. The paging equipment was subsequently changed out to new, AMI-compatible
switches in 2010/2011.
Remediation
The software affecting the AM! switches was upgraded in February 2012. The Company
says it will replace most paging switches with AM!-compatible switches in 2012 and 2013
(about 24,000 switches) at an approximate cost of $6 million. All financial inputs have been
updated to reflect the A/C Cool Credit issues in the 2011 DSM Report. The Company projects
that the A/C Cool Credit program will continue to be cost-effective from a program-life
perspective. However, the program will not be cost-effective from a one-year perspective until
2014. Mountain Home Air Force base (MHAFB)6 is unable to upgrade to the AMI switches and
may not be cycled during the 2012 season due to a lack of a paging service providers. Staff does
not believe that ratepayer money should be used to pay A/C Cool Credit incentive payments to
customers who are unable to provide any additional capacity to the system.
The Company says it will modify the program, conduct a process evaluation in 2012 and
an impact evaluation in 2013, and develop an enhanced measurement and verification plan for
2012. Staff expects the Company to adhere to its planned evaluation schedule for the A/C Cool
Credit program and implement modifications that enhance the program's cost-effectiveness. A
third independent analysis should provide the Commission and Staff the proper foundation and
information to determine how to modify or proceed with the program.
Staff finds the Company's impact analyses in the 2011 DSM Report to be excellent.
Staff also appreciates the Company's full disclosure about the A/C Cool Credit issue to Staff
MHAFB contributes 803 participants that ARE NOT individually metered. MHAFB can only be cycled by a pager
provider due to the technology of the MHAFB substation.
STAFF COMMENTS 10 JUNE 25. 2012
and the EEAG. However, Staff must ensure ratepayer funds are prudently spent. While the
program life cost-effectiveness yields a UCT and TRC greater than 1.0, at this point, Staff views
the Company's failure to properly manage the A/C Cool Credit program as an imprudent use of
ratepayer funds. The Company's failure to cycle 7,891 AMI compatible switches was an
avoidable error. Staff recommends the Commission deny the Company's request to fund from
the Rider $165,711 - the amount of incentives paid to the 7,891 participants affected by the
Company's failure to upgrade its software. Staff declines to recommend any adjustment for
failure to cycle due to pager problems.
Staff's recommendation to deny funding for only the amount of A/C units not cycled by
the AMI-compatible switches has been tempered by the Company's thorough evaluation and
clear disclosure. Denying the use of ratepayer funding for the 7,891 customer incentives is
consistent with prior Company actions. As stated earlier, the Company in 2010 did not fund
from the Rider the amount of incentives paid to eastern Idaho customers who were not cycled.
Further, a 2009 analysis performed by a third party evaluator, Paragon, found that the program's
cost-effectiveness was inconclusive and that some A/C units may not have received the paging
signal. If the Company has not resolved the paging issues for the 2012 cooling season, Staff
believes the Company should use non-ratepayer funds to pay any customers who are not cycled.
Staff will expect the Company's 2012 DSM Report to quantify how many switches the Company
could not cycle.
Irrigation Peak Rewards
Significant financial changes to the Irrigation Peak Rewards program occurred in 2011.
Formerly, the program paid participants a 100% fixed incentive structure with the ability to call
upon as many events as needed. As authorized in Order No. 32200, the program now offers a
75% fixed/25% variable structure. The Company now compares the cost of market energy
prices with the program's variable costs. The program was not dispatched in 2011.
The expenditures for the Irrigation Peak Rewards decreased by about 9% to $11.7
million, primarily due to the new fixed/variable incentive structure recently approved. Program
participation increased by about 15%, to 2,342 participants. Due to the increase in participants,
the available capacity increased from 250 MW in 2010 to 320 MW.
STAFF COMMENTS 11 JUNE 25. 2012
Irrigation Peak Rewards was cost-prohibitive to dispatch in 2011 due to the new
fixed/variable incentive structure and a combination of low system demand, low energy prices
and a lack of system emergencies. Furthermore, the Company says the program has an
approximate dispatch price of $200/MWh (totaling about $270,000 per event). To provide a
brief historical snapshot, the program in 2009 (100% fixed structure) was dispatched on seven
days and in 2010 the program was dispatched on three days. Regardless of the participation
increase and the funding decrease, the $11.7 million program was not dispatched in 2011,
providing limited system benefits. Staff is concerned that the new incentive structure will have
lasting implications for the program's viability. If the cost to dispatch the program continues to
outpace the cost of market-energy prices, the program will rarely be dispatched and may need to
be refined.
FlexPeak
The FlexPeak Management Program continues to increase its expenditures, participation,
cost effectiveness, and energy savings. The Company is requesting a prudency determination of
$2,057,730— a slight increase from 2010 ($1,902,680). The program life cost-effectiveness
increased from 1.14 to 1.19. Additionally, the Company claims 58.8 MW of demand reduction,
an increase from 4757 MW in 2010. The program participation has grown by 85% to 111 in
2011, primarily due to a change in the reporting structure between Idaho Power and EnerNOC.
(Customer sites were formerly reported by location. Now, customers are counted by the number
of meters.)
The FlexPeak contract with EnerNOC will expire in 2014. EnerNOC is responsible for
marketing, procuring participants, determining incentive levels, installing and maintaining
equipment, and running the program. The Company notifies EnerNOC of an impending event
and EnerNOC is responsible for meeting an agreed-upon weekly demand obligation. Over the
course of five years, EnerNOC's reduction capacity is required to incrementally increase.
For 2011, EnerNOC was contractually obligated to provide 35 MW of reduction each
week with an actual reduction ranging from 33 to 41.4 MW. The highest hourly reduction
EnerNOC achieved was 58.8 MW. EnerNOC met the agreed-upon demand reduction for most
This represents the highest hourly reduction.
STAFF COMMENTS 12 JUNE 25. 2012
of the events. EnerNOC did not meet its required demand reduction target for 5 of the 14 events
and thus received a financial penalty.
Fourteen events were called in 2011, with each event lasting about four hours. In 2010,
four events were called. EnerNOC committed to deliver 25 MW of reduction each week. The
highest hourly reduction EnerNOC achieved in 2010 was 34.2 MW.
The Company pays EnerNOC a monthly lump sum from June through August that
consists of unknown amounts of participant incentives, marketing costs, equipment costs,
EnerNOC administrative costs, capacity payments (amount of reduction EnerNOC can secure),
and energy payments (the measured reduction achieved during each event). Staff notes that the
Company categorizes all its EnerNOC payments as "incentive" payments in the 2011 DSM
report. Furthermore, the Company is unaware of the customer incentive structure and amount
negotiated with EnerNOC (Production Request 10). To be consistent with the Company's DSM
expenditure reporting, Staff believes it important for the Company and Staff to be aware of the
amount of incentives paid to FlexPeak participants. Staff recommends that the Company detail
the amount of incentives paid to its customers in future DSM annual reports.
Staff notes that the Company's demand response programs are not being used to their full
potential. There appears to be significant load-shaping potential that is not dispatched due to a
combination of low market prices, low demand, and cooler weather. For example, the Irrigation
Peak Rewards program (the powerhouse of Idaho Power's demand response portfolio) sat idle
due to a new incentive structure that made it cost-prohibitive to dispatch with such low energy
prices. With the addition of the Langley Gulch natural gas plant this year, Staff is concerned that
a combination of existing resources, and current market and load conditions make demand
response cost-prohibitive in the near term. Staff does not advocate that these programs be
discontinued now, but notes that further evaluation is necessary and future refinements may be
warranted.
ENERGY EFFICIENCY
Irrigation Efficiency
While reviewing the 2011 DSM Report, Staff noticed several omissions in the
Company's Irrigation Efficiency program discussion. First, the Company estimated 100% net-
to-gross (NTG) energy savings for both its Custom and Menu, or prescriptive, incentive options
STAFF COMMENTS 13 JUNE 25. 2012
in the program, even though the Regional Technical Forum estimates, which include NTG
assumptions, are only applied to the Menu option. In its discovery response, the Company
corrected this error and will apply a 75% NTG value to Custom energy savings in the future.
Applying a 75% NTG value reduced the UCT from 4.71 to 4.22 and provides an increase in the
TRC, from 1.55 to 1.90.
Second, Idaho Power wrote that the Regional Technical Forum savings cited for the
program's Menu option are "under review" by the Regional Technical Forum. Actually, the
Regional Technical Forum has deemed these savings to be "out of compliance" since February
2011. While it may be acceptable to cite savings estimates that are "out of compliance" if new
savings are being actively pursued, the 2011 DSM Report appears to mischaracterize the status
of the Company's savings estimates.
Third, Idaho Power reports that the non-electric benefits produced by this program
increased about 357% between 2010 and 2011, while electric savings increased by 35% and the
program budget increased by 7%. In response to discovery, Idaho Power wrote that it had
"improved its tracking of non-electric benefits with the implementation of a new more
comprehensive database," but did not provide sources, values, or any methodology for these
subjective, non-electric benefit estimates. Further, the Company's 2011 DSM Report fails to
mention this new database. Staff points out that even with the massive addition of non-electric
benefits, this program's TRC only increased from 1.52 in 2010 to 1.55 in 2011. After discovery,
the Company held a telephone conference with Staff and explained the methodologies used to
estimate non-electric benefits, which include yield benefits, labor savings, maintenance savings,
and water savings. None of these estimates come from verifiable sources - they are all
estimated by a project engineer on an individual project basis based on his or her judgment.
Fourth, the impact evaluation scheduled for Irrigation Efficiency in 2011-2012 was
removed from the evaluation schedule. In response to discovery, Idaho Power said that the
impact evaluation was modified to become a research project that would generate updated
energy savings estimates. While this may be a reasonable approach to the problem posed by
8 The DSM MOU recognizes the validity of incorporating non-energy benefits. However, the DSM MOU does not
discuss the appropriate amount of non-energy benefits.
STAFF COMMENTS 14 JUNE 25. 2012
"out of compliance" Regional Technical Forum savings, the Company's 2011 DSM Report
should have clearly explained the evaluation schedule change.
The sum of these missteps is a serious concern for a program that cost ratepayers $2.1
million in 2011. Even more concerning is the Company's decision not to disclose these issues in
the 2011 DSM Report. Lastly, Staff believes that a 357% increase in non-electric benefits,
which rests on the unevaluated estimations of program engineers, creates an artificially high
TRC. Staff believes that this program might not pass the TRC when energy savings are verified
by an impact evaluation and if non-electric benefits are removed.
Staff recommends that the Company include in its program cost-effectiveness the TRC
value with and without non-electric benefits.
Home Improvement Program
Idaho Power's 2011 Home Improvement program created an incentive for residential
customers with electric heat or central air conditioning to professionally install additional attic
insulation in their homes. During the 2011 impact evaluation of this program, Idaho Power
discovered that the energy savings estimates used for this program assumed that high-efficiency
windows had been installed along with additional attic insulation. This faulty assumption caused
the Company to overstate the program's energy savings. When the impact evaluation calculated
the accurate savings, only attic insulation incentives for customers with electric heat remained
cost-effective. In addition, the Company paid incentives to 40 non-qualifying program
applicants.
Staff appreciates that the Company is revising its program to only include cost-effective
measures and tightening its applicant review process. Staff is concerned, however, that the
Company has failed to detect its faulty inclusion of energy savings from high-efficiency
windows since 2008. Combined, these problems indicate inadequate oversight of the residential
programs.
Energy Efficient Lighting
The Company's residential Energy Efficient Lighting program experienced a slight
reduction in its cost-effectiveness, but it continues to pull in a strong program life UCT of 4.2
and a TRC of 3.07. The decrease in cost-effectiveness is due to the Regional Technical Forum's
STAFF COMMENTS 15 JUNE 25. 2012
updated savings assumptions. The recent change in baseline assumptions is due to compliance
with the federal Energy Independence and Security Act of 2007 (EISA).
Staff notes the variety of energy efficient lighting promotions detailed in the 2011 DSM
Report. Staff suggests the Company expand its marketing efforts to include mobile applications
like the Light Bulb Finder. Staff notes that federal policies will continue to change the lighting
industry and market, and will most likely impact the Company's Energy Efficient Lighting
program in the future.
Energy Efficiency Advisory Group
The EEAG met three times last year. Staff believes the dialogue between invited
stakeholders and the Company could be greatly improved by more frequent EEAG meetings and
more in-depth discussions. Discussion quality is currently hindered in two ways. First, Idaho
Power only lets EEAG members comment or ask questions at EEAG meetings. Since several
Staff members regularly attend EEAG meetings but only one Staff member is an EEAG member,
the Company's policy precludes most Staff members not from providing feedback or asking for
clarification on Company presentations.
Second, the EEAG has become a forum for Idaho Power's presentations on its DSM
activities rather than a discussion where the Company actively seeks input. Idaho Power's
ratepayers would be better served by an advisory group that contributes to the Company's
decisions rather than merely receives updates on the Company programs.
Staff notes that Avista and Rocky Mountain Power's DSM advisory committees met
either in person or by webinar approximately once a month in 2011 and that there committees
did not censor attendees. In fact, the other utilities encouraged everyone to participate. Since
this is the first year in which Idaho Power experienced declining energy savings and published
its first impact evaluations, Staff believes there is no shortage of topics that warrant EEAG
attention. Further, the publication of Idaho Power's next DSM potential study in 2013 will raise
questions about which DSM resources the Company should expand, initiate, or reduce. These
decisions would certainly benefit from the EEAG's frequent consideration.
STAFF COMMENTS 16 JUNE 25. 2012
STAFF RECOMMENDATIONS
With a few exceptions, Staff believes Idaho Power's DSM efforts were generally prudent
and cost-effective. The Company continues to make significant efforts to meet the objectives
and goals outlined in the DSM MOU. Staff recommends:
. That the Commission approve Rider-funded expenditures of $35,728,206 as prudently
incurred, and establish the ending balance of the Rider account as of December 31, 2011
at $(5,155,941);
. That the Commission deem the incentives paid under the Custom Efficiency program
($7,018,385) as prudently incurred;
. That the Commission deny Rider funding for $165,711 of A/C Cool Credit customer
incentives;
. That the Commission prohibit the Company from accruing a carrying charge on the
Custom Efficiency program's deferral balance until the Company seeks recovery of that
balance in a general rate proceeding. At that point, the Company should be able to apply
the Commission-approved carrying charge retroactively to the balance;
. That the Company continue to detail its demand response incentives, activities,
evaluations and cost-effective benefits/costs for prudency in the Company's DSM
prudency determination;
. That the Company detail the amount of incentives paid to its FlexPeak Management
participants in future DSM annual reports;
. That the Company increase the number and depth of the EEAG meetings and encourage
questions and feedback from all attending stakeholders;
. That the Company not fund any additional wage increases through the Rider until the
increases can be properly vetted through a general rate proceeding, and
. That the Company include in its program cost-effectiveness the TRC value with and
without non-electric benefits.
STAFF COMMENTS 17 JUNE 25. 2012
Respectfully submitted this Z 5 day of June 2012.
/
Karl T. Klein
Deputy Attorney General
Technical Staff: Nikki Karpavich
Donn English
Stacey Donohue
i:umisc/comments/ipce 12.1 5kkdesdnk comments
STAFF COMMENTS 18 JUNE 25. 2012
Attachment A
Idaho Power's 2011 Annual Demand-Side Management Utility Benefits and Costs
Utility
Benefit (net Net 2011
Energy Efficiency Programs Measure present Utility Benefit Utility
Life value of Cost (Benefit- B/C
avoided Cost) Ratio
costs)
Ductless Heat Pumps 20 591,603 191,183 400,420 3.09
Energy Efficient Lighting 5 6,850,821 1,719,133 5,131,688 3.99
Energy House Calls 20 1,178,997 483,375 695,622 2.44
Energy Star Homes Northwest 32 967,191 259,762 707,429 3.72
Heating & Cooling Efficiency 20 946,314 195,770 750,544 4.83
Home Improvement 45 1,772,738 666,041 1,106,697 2.66
Home Products 15 1,304,940 638,323 666,617 2.04
Rebate Advantage 25 183,939 63,469 120,470 2.90
See Ya Later, Refrigerator 8 994,718 654,393 340,325 1.52
Weatherization Assistance 25 3,531,604 1,324,415 2,207,189 2.67
Weatherization Solutions 25 1,447,829 788,148 659,681 1.84
Building Efficiency, Commerical 12 71627,364 1,291,425 6,335,939 5.91
Easy Upgrades, Commercial 12 25,650,385 4,719,466 20,930,919 5.44
Custom Efficiency, Comm/Indust. 12 38,838,187 8,783,811 30,054,376 4.42
Irrigation Efficiency, Irrigation 8 11,123,018 2,360,304 8,762,714 4.71
Total Energy Efficiency 103,009,648 24,139,018 78,870,630 4.27
Attachment A
Case No. IPC-E-12-15
Staff Comments
06/25/12 Page 1 of 2
Peak Demand Programs Utility
Benefit Utility Cost
I Net I Benefits I (Benefits -
I Cost)
I
2011 I
Utility I B/C Ratio I
AC Cool Credit
(20 year projected) 37,186,165 33,948,331 3,237,834 1.10
FlexPeak Management
(10 year projected) 36,551,819 30,629,291 5,922,528 1.19
Irrigation Peak Rewards
(20 year projected) 365,066,962 211,898,973 153,167,989 1.72
Average Annual Peak
Demand, Projected 23,767,838 15,355,294 8,412,544 1.55
Attachment A
Case No. IPC-E-12-15
Staff Comments
06/25/12 Page 2 of 2
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 25TH DAY OF JUNE 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-12-15, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
JULIA A HILTON
LISA D NORDSTROM
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
EMAIL: [e-mail]
[e-mail]
DARLENE NEMNICH
GREG SAID
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
EMAIL: [e-mail]
[e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
P0 BOX 7218
BOISE ID 83702
EMAIL: [e-mail]
greg(richardsonandoleary.com
BENJAMIN J OTTO
710 N 6TH STREET
BOISE ID 83702
EMAIL: botto(21idahoconservation.org
DR DON READING
6070 HILL ROAD
BOISE ID 83703
EMAIL: dreading(mindspring.com
KEN MILLER
SNAKE RIVER ALLIANCE
P0 BOX 1731
BOISE ID 83701
EMAIL: kmi11ersnakerivera11iance.org
CERTIFICATE OF SERVICE