20121022final_order_no_32667.pdf

Office of the Secretary
Service Date
October 22, 2012
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 ) ORDER NO. 32667
PRUDENTLY INCURRED )
On March 15, 2012, Idaho Power Company applied to the Commission for an order
finding that the Company prudently incurred $42,641,706 in demand-side management (DSM)
expenses in 2011. Application at 1. The Company later decreased its claimed DSM expense
amount to $42,641,361 in DSM expenses, which the Company said included $35,622,976 in
Idaho Energy Efficiency Rider (Rider) expenses and $7,018,385 in Custom Efficiency Program
incentive expenses. See Idaho Power Company's Reply Comments (Reply) at 2 and 13. We
have thoroughly reviewed the record in this case, including written comments and analysis from
the Company, Commission Staff, and the Company's customers. Based on that review, we find
that the Company prudently incurred $41,942,123.50 in DSM expenses in 2011, including
$34,923,738.50 in net Rider expenses and $7,018,385 in Custom Efficiency Program incentive
expenses. Our decision is more thoroughly described below.
PROCEDURAL BACKGROUND
On April 10, 2012, the Commission notified the public that the Company had filed
the Application and invited interested persons to file written comments. See Order No. 32512.
The Commission set a June 25, 2012, comment deadline and a July 23, 2012, Company reply
deadline. See Order No. 32569. The Industrial Customers of Idaho Power (ICIP), the Idaho
Conservation League (ICL), and the Snake River Alliance intervened as parties in the case. See
Order Nos. 32530, 32542, and 32551. Commission Staff, the ICIP, the ICL, and members of the
public filed written comments, and the Company filed a reply.
THE APPLICATION
In its Application, the Company noted that the Commission has ordered it to promote
energy efficiency by pursuing all cost-effective DSM programs. Consistent with this policy, the
Company said it allows its customers in each customer class to participate in DSM programs.
The Company said it consults with an Energy Efficiency Advisory Group that provides
recommendations on issues like new DSM program proposals, modifications to existing
ORDER NO. 32667 1
programs, and overall expenditures of DSM funds. See Application at 2. The Company noted
that it has steadily increased the breadth and funding level of its DSM activities since the Rider
was implemented in 2002. The Company also noted that the Commission found the Company
prudently incurred cost-effective, DSM-related Rider expenses of $29 million from 2002-2007,
$50.7 million from 2008 and 2009, and $41.9 million in 2010. Id., citing Order Nos. 30740,
31039, 32113, and 32331.
The Company said its 2011 DSM programs continued to increase customer
participation and facilitate energy savings. It currently offers 17 energy efficiency programs (16
of which are cost-effective; the Home Improvement Program was not cost-effective 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 says its 2011 efficiency activities saved 179,424 MWh of energy. Id. at 3.
The Company attached its 2011 DSM Annual Report (Report) to the Application.
The Report discusses the cost-effectiveness of the Company's DSM programs and energy-
savings measures, as well as financial information separated by expense category and
jurisdiction. Id. at 5. The Company examines a program's cost-effectiveness using the
following four tests: 1) the total resource cost test (TRC); 2) the utility cost test (UCT); 3) the
participant cost test (PCT); and 4) the ratepayer impact measure (RIM). Id.' The Report also
describes the Company's plans to evaluate its DSM programs, and contains copies of completed
evaluation reports and research reports. Id. The Report also describes each DSM program,
including 2011 activities, along with customer satisfaction and process, impact, and market-
effect evaluations. Id. at 6. The Company noted 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.
1 The four tests compare a program's cost-effectiveness from different perspectives. In sum, the TRC compares
program administrator and customer costs to utility resource savings, and assesses whether the total cost of energy in
a utility's service territory will decrease. The UCT compares program administrator costs to supply side resource
costs, and assesses whether utility bills will increase. The PCT compares the costs and benefits of the customer
installing the measure, and assesses whether program participants will benefit over the measure's life. The RIM
compares administrator costs and utility bill reductions to supply side resource costs, and assesses whether utility
rates will increase.
ORDER NO. 32667 2
COMMENTS AND DECISION
Members of the public, the ICL, the ICIP, and Commission Staff filed comments, and
the Company filed reply comments. The following sections summarize these comments and
provide our findings and decision on each issue.
I. PUBLIC COMMENTS
The Commission received a number of public comments in this case. The public
comments generally supported the Company's energy-efficiency efforts. The Commission
appreciates the public's input on this matter. One commenter, EnerNOC, Inc., addressed the
Staff's recommendation that Idaho Power's future DSM reports should detail EnerNOC's
incentive payments to participants in the Company's FlexPeak Management Program. We
address EnerNOC's comments in section IV.13.2 of this Order.
II. ICL COMMENTS
The ICL generally supported the Company's 2011 DSM investments and
recommended that the Commission approve them. ICL Comments at 2, 7. But while the ICL
applauded the Company's energy-savings efforts, it said the "Company's most recent DSM
Potential Study reveals a huge gap between economic potential and achievable economic
potential." Id. at 4. The ICL argued that it is imprudent for the Company "not to expand DSM
savings far beyond current levels" when the Company knows DSM programs are highly cost-
effective and could close the achievement gap. Id at 5. The ICL asked the Commission to
provide "guidance on expanding existing DSM programs" in 2012 and to order the Company to
"explain [its] strategy for closing the achievement gap." Id at 4-5, 7. Specifically, the ICL said
the Commission should order the Company to focus on increasing customer participation in
programs with RIM scores above 1.0. Id. at 4, 72 The ICL also said the Commission should
order the Company to: (1) describe its efforts to protect the lighting efficiency standards
embodied in the Energy Independence and Security Act of 2007; (2) allow customers to assign
incentives to contractors who install all DSM measures; (3) target high-energy users and increase
the cycling rate in the A/C Cool Credit Program; and (4) expand the Weatherization for Eligible
Customers Program to all customers with a cost-sharing provision based on household income.
Id. at 5-7.
2 See fn. 1, above, describing the RIM.
ORDER NO. 32667 3
In response to the ICL's comment that a "huge gap" exists between economic and
achievable potential, the Company said:
Economic potential calculates savings when cost-effective measures are
installed.... There is no expectation that the Company or any energy
efficiency organization could achieve the economic potential. On the other
hand, achievable potential is potential that the consultant deemed achievable
by the Company, and Idaho Power has consistently exceeded its achievable
potential.
Reply at 4. The Company also noted that it has retained "EnerNOC Utility Solutions to perform
a new potential study...." Reply at 13. With respect to the ICL's suggestion that the Company
focus on increasing participation in programs with RIM scores above 1.0, the Company pointed
out that the Commission has informed it that it need not use the RIM test. The Company said it
uses the TRC, UCT and PCT tests as directed by the Commission. Id. at 12, citing Order No.
28894 at 6.
Commission Decision: We appreciate the ICL's comments. But the issue here is
whether the Company's 2011 DSM expenditures in established programs were prudent. The
ICL's comments expand this issue, and we decline to address them here. That said, we
encourage the ICL to raise its concerns and suggestions in future Energy Efficiency Advisory
Group meetings. As noted below, we expect the Company to ensure that future Energy
Efficiency Advisory Group meetings are more inclusive and serve as a forum for the Company
to obtain input and address comments and questions from a broad range of stakeholders,
including the ICL, Staff, customers, and other interested persons.
III. ICIP COMMENTS
The ICIP stressed "the need to consistently evaluate cost effectiveness by applying
the same test to all resources for both the demand- and the supply-side of the equation." ICIP
Comments at 1. The ICIP said the Company's system-cost evaluation for DSM in this case is
inconsistent with the Company's evaluation for Qualifying Facility rates in case GNR-E-11-03.4
Id at 5. According to the ICIP, the "short-run avoided cost rates as advocated [by the Company]
in GNR-E-11-03 could in fact disallow those energy efficiency expenditures which fail to meet
3 See fn. 1, above, describing the TRC, UCT, PCT, and RIM.
' GNR-E-1 1-03 is a generic Commission investigation entitled "In the Matter of the Commission's Review of
PURPA QF Contract Provisions Including the Surrogate Avoided Resource (SAR) and Integrated Resource
Planning (IRP) Methodologies for Calculating Published Avoided Cost Rates."
ORDER NO. 32667 4
the Company's own test for cost effectiveness as applied to PURPA projects." Id. at 8. The
ICIP said that if the Commission adopts the Company's short-run approach in GNR-E-11-03,
then the Commission also should "find that Idaho Power's expenditures for all DSM programs in
the future be assessed in the same manner for determining prudence." Id. at 11-12. The ICIP
said that "[s]etting the benchmark for all avoided costs over the long term is the only way to
ensure ... that the utility values these ... resources equally [and] that some of the DSM programs
will still be economically viable." Id. at 12.
In reply, the Company said that the ICIP's arguments are only tangentially related to
whether the Company's 2011 DSM expenditures were prudent. Reply at 10-11. The Company
said it "applied the same methodology [here] as it has applied in every prudence determination
approved by the Commission since the inception of the Rider...." Id. at 11. The Company said
if the Commission finds merit to ICIP's recommendation, then the Commission should allow the
parties to evaluate it in a separate proceeding. Id. at 11.
Commission Decision: We appreciate the ICIP's comments. But the issue here is
whether the Company prudently incurred its 2011 DSM expenses. We find that the ICIP's
comments and recommendations are outside the scope of this proceeding, and we decline to
address them.
IV. STAFF COMMENTS
Staff generally supported Idaho Power's DSM efforts as prudent and cost-effective,
with a few exceptions. Id. at 17. Staff said the Company continues to make significant efforts to
meet the objectives and goals outlined in the 2009 DSM Memorandum of Understanding (DSM
MOU). d.5 Staff discussed the Company's DSM expenditures, demand response programs,
energy efficiency programs, and the Energy Efficiency Advisory Group. Each of these items is
discussed under a separate heading below.
A. Expenditures
In its Application, Idaho Power asked the Commission to review $42,641,706 in total
DSM expenditures, $35,623,321 in Rider fund expenditures, and $7,018,385 in Custom
Efficiency incentives. During the proceeding, however, the Company disclosed that it had
The DSM MOU is a document signed by Staff and Idaho's three investor-owned utilities (Idaho Power,
PacifiCorpfRocky Mountain Power, and Avista). It sets guidelines for a DSM prudency determination, and it
incorporates sections on management, planning, cost-effectiveness, evaluation and reporting. The Commission's
review of particular DSM programs is assisted, but is not replaced by, the Company's compliance with the DSM
MOU's terms. Order No. 31039,
ORDER NO. 32667 5
inadvertently inflated Idaho Rider fund expenditures by $345 in incentives that were actually
paid to Oregon customers. The Company corrected its error and said that the DSM expenditures
under review here are $42,641,361 in total DSM expenditures, $35,622,976 in Rider fund
expenditures, and $7,018,385 in Custom Efficiency incentives. Reply at 2 and 13. We
appreciate the Company's candor on this matter.
The Staffs comments on the Rider expenditures and the Custom Efficiency Program
expenditures, and the Company's replies to those comments, are discussed below.
1. Rider Expenditures.
Staff calculated the Rider account balance to be:
2010 Year End Balance $ (17,595,938)
2011 Balance Transfer to PCA 6 10,000,000
2011 Funding plus Accrued Interest 37,367,481
2011 Expenses (35,096,540)
Transfer to Oregon Rider 3458
Adjustment to A/C Cool Credit 165,711
2011 Year End Balance $ (5,158,941)
Id. at 4. Staff thus recommended that the Commission approve Rider-funded expenditures of
$35,096,540 and establish the ending balance of the Rider account as of December 31, 2011 at
($5,158,941).'o Staff criticized the prudency of the Company's Rider-funded expenditures
related to the A/C Cool Credit Program and labor expenses. Staff also discussed the one-time,
6The PCA, or Power Cost Adjustment, is a yearly adjustment to rates based on the always-changing costs of power
supply. It varies every year depending on water and market conditions. In Order No. 32217, dated April 1, 2011, the
Commission authorized Idaho power to recover $10 million from the Rider deferral balance through a PCA
surcharge during the 2011 PCA year.
The Company's Application asked the Commission to determine that Idaho Power prudently incurred $35,623,321
in expenses, 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. 8 The Company's prudency request changed during this proceeding after the Company discovered that it had
charged the Idaho Rider for $345 in incentives paid to Oregon customers. The Company removed these payments
from the Idaho Rider and transferred them to the Oregon Rider as shown above. Id.
Staffs table listed the 2011 year-end balance as $(5,155,941). The underlined part of Staffs number appears to be
an inadvertent error. Adding the other numbers in the table yields a corrected, 2011 year-end balance of
$(5,15 8194 1). We have inserted the corrected balance into the table.
10 Page 4 of Staffs Comments contains a table listing the Company's 2011 DSM net expenses at $35,096,540. But
page 17 of Staff's Comments inconsistently recommended that the Commission approve Rider-funded expenditures
of $35,728,206, which is more than the Company asked the Commission to approve. Reply at 7. It appears that the
amount listed on page 17 of Staffs Comments is an error. We appreciate the Company bringing this to our attention.
Based on our review of the record, we find that the correct amount is the $35,096,540 reflected in the table on page
4 of Staffs Comments.
ORDER NO. 32667 6
$10,000,000 balance transfer from the Rider account to the Power Cost Adjustment. These three
items are discussed below.
a. A/C Cool Credit Program.
Staff recommended that the Commission disallow $165,711 in A/C Cool Credit Program
expenditures. According to Staff, an independent impact evaluation established that the A/C Cool
Credit Program was not cost-effective in 2011 and that it will not be cost-effective until 2014. Staff
Comments at 9. Staff said the cost-effectiveness decrease occurred because the Company did not
notice—until well after summer—that it had failed to cycle A/C units for about 11,000 program
participants (about 30% of the A/C units in the program). Staff attributed the Company's failure to
cycle the A/C units to: (1) the Company did not notice that a third-party paging provider, which the
Company used to communicate with certain A/C unit cycling switches, stopped serving a large part
of the Company's territory; and (2) the Company failed to update software used to operate certain
A/C units with AMI-compatible switches after the switch manufacturer successfully tested a new
software code in fall 2010. Id. at 9. Staff said this latter oversight caused 7,891 A/C units to not be
cycled. Id. Staff noted that 2011 was the second consecutive year in which the Company failed to
cycle eastern Idaho participants. Id. at 10.
Staff said the Company has tried to remedy the cycling problems. The Company updated
its AMI-switch software in February 2012. It also will replace most of its paging switches with
AMI-compatible switches in 2012 and 2013. Id. Staff nevertheless opined that the Company's
failure to update its AMI switching software was an "avoidable error" and that the Company should
not have paid incentives to the non-cycled participants (just as the Company did in 2010 when
participants were not cycled). Staff said the Company's failure to properly manage the A/C Cool
Credit Program resulted in an imprudent use of ratepayer funds. Id. at 9-11. Staff recommended that
the Commission find as imprudent the $165,711 in A/C Cool Credit Program customer incentives
that the Company paid to the 7,891 Program participants whose A/C units were not cycled due to the
Company's failure to upgrade its AMI-switching software. Id at 11.
The Company disagreed with Staff on two points. First, the Company said its software
difficulties did not amount to an "imprudent use of ratepayer funds." Reply Comments at 3. The
Company argued that its "program is complex and, when the Company encountered issues, it
promptly approached Staff for recommendations and quickly took corrective actions." Id. The
Company said its actions fostered transparency and improvement in DSM operations. Id. at 34.
ORDER NO. 32667 7
Second, the Company said it should have paid Rider-funded customer incentives to the
non-cycled, A/C Cool Credit Program participants in 2011 even though the Company chose not to
fund such participants from the Rider in 2010. Id. at 4. The Company distinguished its 2010 actions
by noting that it knew that paging services had stopped and that A/C control devices would not work
before the cycling season started, but that it still paid participants to retain them in the Program. In
2011, the Company paid participants while believing that the equipment and software was properly
operating. The Company says the Commission should "not deny recovery of program expenses that
were incurred based upon the reasonable expectation that participants were receiving dispatch
signals." Id.
Lastly, the Company noted that it is remedying and continuing to evaluate the A/C Cool
Credit Program as noted by Staff. Id. at 4-5.
Commission Decision: Staff recommended that we deny Rider-funding for $165,711
in A/C Cool Credit Program incentives. While the full amount suggested by Staff might
arguably be disallowed for imprudence, based on our review of the record and in view of all the
circumstances, we find it reasonable and appropriate to deny Rider-funding for one-half that
amount, or $82,855.50 in A/C Cool Credit Program incentives. We appreciate the Company's
full-disclosure of the A/C Cool Credit Program cycling issues. And we understand that it has
taken steps to remedy the cycling problem and to modify the Program to enhance its cost-
effectiveness. Further, we understand that the Company paid participants while mistakenly
believing that its equipment and software were properly operating. But we disagree with the
Company that its mistaken belief was reasonable. We recognize that A/C Cool Credit Program
logistics can be complex. Nevertheless, in light of the A/C Cool Credit Program's past cycling
problems, we expect the Company would have more closely monitored the Program to ensure
that the software was working and that participants were actually receiving dispatch signals.
b. Labor Expenditures.
Staff again expressed concern with the escalating labor costs that the Company charges to
the Rider account. Id. at 8. Staff noted that in 2011, Idaho Power charged approximately $2.64
million in labor expenses (about 7.5% of the total Rider budget) to the Rider account. Id. In 2010,
labor expenses were approximately 6% of the total DSM budget. Id Staff was concerned that the
Company continues to pass Rider-funded employees' wage increases to customers without the
scrutiny that occurs during a general rate case. Id. Staff thus proposed (as it has proposed in past
ORDER NO. 32667 8
cases) that the Commission exclude wage increases for Rider-funded employees from the Rider until
the Commission has approved the wage increases in a general rate case. Id.
The Company disagreed with Staff and argued that labor expenses stayed at about 6% of
the total amount requested for prudency, and that they have not dramatically increased between 2010
and 2011 as implied by Staff. Id. at 7-8. The Company noted that its DSM programs (except the
Home Improvement Program) were cost-effective under the three tests required by the DSM MOU,"
and that each test included the Rider employee salaries including the wage increases at issue. Id. at
8. The Company said the Commission should not use a prudency proceeding to assess whether the
Company should fund wage increases through the Rider. The Company said that setting
"prospective rates in a general rate case based upon a determination of prudent levels for salaries in a
test year is very different than evaluating the prudence of costs already incurred." Id. Also, tying the
disposition of payroll to a finding in a future rate case would limit the Company to providing wage
increases to Rider-funded employees in years when the Company files a rate case. Id. at 9. The
Company said that if the Commission disallows Rider payroll-related expenditures, it will be
penalizing the Company even though the disallowed amount was cost-effective. Id.
Commission Decision: Staff recommended that the Company not fund any additional
wage increases through the Rider until the increases can be properly vetted through a general rate
proceeding. Staff's point is well-taken. The salaries and wages for the Company's Rider-funded
employees typically are not addressed in a general rate case, and they typically do not receive the
same level of scrutiny as do expenditures that are reviewed in a general rate case. We also note that
the Company has the burden of proving that the increase in labor-related expenses is reasonable.
Based on our review of the record, we find that the Company has not yet carried its burden. The
record presently lacks sufficient evidence from which we may determine whether the increase in the
Company's labor-related expenses is reasonable when compared to the benefits those expenses
achieve. Accordingly, we decline to decide the reasonableness of the Company's labor-related
expense increase until the Company provides evidence from which we may better assess the
reasonableness of those expenses. We direct the Company to work with Staff to determine what
types of information should be provided. The Company shall promptly advise us of how and when
the Company intends to provide us with the information. The Company may, but need not, wait until
a general rate case to provide such supporting information.
' See ffi. 5, above, describing the DSM MOU.
ORDER NO. 32667 9
c. One-Time, $10 Million Deferral Balance Transfer.
Staff observed that a one-time, $10 million deferral balance was transferred to the Power
Cost Adjustment mechanism effective June 1, 2011 through May 21, 2012. Id. citing Order No.
32217.12 Staff noted that the Commission has authorized the Company to recover demand response
incentive payments through base rates and the Power Cost Adjustment (see Order Nos. 32217 and
32426). But Staff said it is more appropriate for Staff to review and analyze demand response in the
DSM prudency determination than in a general rate case or Power Cost Adjustment proceeding. Id.
at 6 and 17. Staff thus recommended that it continue to detail its demand response activities and
cost-effective benefits/costs for prudency in the Company's DSM prudency determination
proceedings. Id.
Commission Decision: Based on our review of the record, it appears that the Company
did not disagree with Staff's recommendation that the Company continue to detail its demand
response incentives, activities, evaluations and cost-effective benefits/costs when it applies for a
DSM prudency determination. We find this recommendation to be reasonable, and we direct the
Company to continue detailing such information when it applies for a DSM prudency determination.
2. Custom Efficiency Program Expenditures.
Staff concurred with the Company that the Commission approve $7,018,385 in Custom
Efficiency Program incentive payments. Id. at 4. But Staff and the Company disagreed on whether
the Company should be allowed to accrue interest on the incentive payments at this time.
Staff said the Company began booking Custom Efficiency Program incentive payments
into a regulatory asset account on January 2, 2011, with the goal of recovering the deferral balance
on the account when it files a rate case. Staff Comments at 5; Order No. 32245. Staff said that in
this proceeding, the Company reported that the deferral balance in the account is $7,230,724, which
includes the $7,018,385 in incentive payments (which both Staff and the Company said should be
allowed in this proceeding) and $212,339 in carrying charges. Staff said the Commission should
prohibit the Company from accruing interest on the incentive payments in the account because the
Commission has not yet determined what the interest rate should be and the rate arguably should be
less than the rate proposed by the Company. Staff said the Commission should not decide the
interest rate now, and should prohibit the Company from accruing interest in the account, until
parties and the Commission have thoroughly examined the appropriate interest rate in a general rate
12 See th 6, above, discussing the Power Cost Adjustment.
ORDER NO. 32667 10
proceeding. Id. at 5 and 17. Staff advocated that of the Company's reported $7,230,724 Customer
Efficiency Program incentive payment deferral balance, the Commission should: (1) find that the
$7,018,385 in incentive payments were prudently incurred expenses; and (2) not decide the
appropriate interest rate and the accrued interest amount until the Company asks to recover the
deferral balance in a rate case. Id.
While the Company agreed with Staff on the amount of prudently incurred incentive
payments, the Company disagreed with Staff suggestion that the Commission defer deciding the
interest rate and amount until a general rate case occurs. The Company used its current rate of
return/cost of capital as the rate at which interest on Custom Efficiency Program payments should
accrue. The Company said that using the cost of capital as the interest rate treats the Company's
Customer Incentive Program expenditures in the regulatory asset account like the Company's other
capital investments. The Company noted that Staff and the Commission have previously supported
this concept. Id. at 9-10, citing the Stipulation in Case IPC-E-10-07 13 and Order Nos. 22299 and
22758 (We have "held in several previous orders that prudently-incurred costs associated with
conservation programs should be capitalized in a manner equivalent to the treatment of expenditures
on generating resources. We reaffirm our position that such equivalent accounting treatment is
appropriate").
Commission Decision: Based on our review of the record and the agreement of Staff
and the Company, we find that the Company prudently incurred $7,018,385 in Custom
Efficiency Program incentive expenses. But we believe the interest rate to be applied to the
balance—and ultimately included in rates—concerns all customers and should be thoroughly
reviewed and determined in a rate case. We thus find it reasonable to defer deciding the interest
rate to be applied to the Customer Efficiency Program regulatory asset account, and the resulting
interest amount, until the Company seeks to recover the deferral balance in a general rate
proceeding. We find it reasonable to require the Company to maintain records with sufficient
detail to replicate the Company's calculation of any deferral charges.
13 The Stipulation agreed to by Staff stated, in pertinent part: "The parties [to the Stipulation] agree that the direct
incentive payments of the Custom Efficiency program should be capitalized as a regulatory asset beginning January
1, 2011. A carrying charge equal to the current Commission authorized rate of return of 8.18 percent will be applied
to the balance until the Commission includes the regulatory asset in Company rates as part of its next general rate
case." Stipulation at 3, Case No. IPC-E- 10-27. Not all the parties to the case signed the Stipulation, and the
Commission ultimately rejected it. See Order No. 32217.
ORDER NO. 32667 11
B. Demand-Response Programs
The Company offers three demand-response programs: the A/C Cool Credit Program; the
Irrigation Peak Rewards Program; and the FlexPeak Management Program. We have discussed the
A/C Cool Credit Program above, and we will discuss the remaining two programs in the sections that
follow. Before that, we address Staff's general concern that the Company is not using its demand-
response programs to their full potential.
In sum, Staff generally observed that "the Company's demand-response programs are not
being used to their full potential" and that 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." Staff
Comments at 13. Staff said that the Company's addition of the Langley Gulch plant raises concerns
"that a combination of existing resources, and current market and load conditions make demand
response cost-prohibitive in the near-term." Id. Staff did not advocate discontinuing the programs,
but it noted that future refinements may be warranted. Id.
The Company disagreed with Staff and said Staff ignores that the demand-response
programs were not meant to be cost-effectively dispatched in times of "low market prices, low
demand, and cooler weather." The Company said the programs "are intended to meet system loads
in times of extremely high demands, high market prices, low water conditions, transmission
constraints, and in system emergencies." Reply at 2-3.
Commission Decision: Based on our review of the record, we find that the Company
continues to make strides in meeting the objectives and goals outlined in the DSM MOU.'4 We
expect the Company to refine individual programs as their effectiveness changes, consistent with our
direction that the Company pursue all cost-effective programs.
We now discuss Staff's concerns about the Company's Irrigation Peak Rewards Program
and the FlexPeak Management Program.
1. Irrigation Peak Rewards Program
Staff said the Company's Irrigation Peak Rewards Program experienced significant
financial changes in 2011. Id. at 11. While the Program initially paid participants a 100% fixed
incentive structure with the ability to call upon as many events as needed, Commission Order No.
32200 authorized the Program to offer a 75% fixed/25% variable incentive structure. Id. Staff said
that under the new structure, Program expenditures decreased by 9% to $11.7 million and Program
See fh. 5, above, describing the DSM MOU,
ORDER NO. 32667 12
participation increased by 15% to 2,342 participants. Still, Staff said the Program was cost-
prohibitive to dispatch in 2011 due to the new structure and a combination of low system demand,
low energy prices, and the absence of system emergencies. Id. at 12. Staff expressed concern that
the new incentive structure will adversely impact the Program's viability. Staff predicted that the
Program will rarely be dispatched and may need to be refined if the dispatch cost continues to
outpace the cost of market-energy prices. Id. at 12.
The Company did not specifically respond to the Staff's comments about the Irrigation
Peak Rewards Program. But the Company responded generally to Staffs comments that its demand
response programs may be cost-prohibitive to dispatch. As discussed above, the Company noted that
the demand response programs (including the Irrigation Peak Rewards Program) are not intended to
be cost-effectively dispatched in times of "low market prices, low demand, and cooler weather."
Rather, such programs "are intended to meet system loads in times of extremely high demands, high
market prices, low water conditions, transmission constraints, and in system emergencies." Reply at
2-3.
Commission Decision: Based on our review of the record, we are concerned that the new
incentive structure may be limiting the effectiveness of the Irrigation Peak Rewards Program. We
direct the Company to continue to monitor the Program and to take such steps as may be needed to
improve it, consistent with the Commission's directive to pursue all cost-effective DSM programs.
2. FlexPeak Management Program
Staff said the Company's FlexPeak Management Program continues to increase its
expenditures, participation, cost effectiveness, and energy savings. Staff Comments at 12. Despite
this, Staff expressed concern that the Company pays its Program's third-party administrator,
EnerNOC Inc., a monthly lump sum to cover unknown amounts of participant incentives and other
costs. Staff said that to be consistent with the Company's DSM expenditure reporting, the Company
and Staff must be allowed to know the incentive amounts that EnerNOC pays to Program
participants. Accordingly, Staff recommended that the Company's future DSM reports detail the
incentive amounts paid to customers. Id. at 13.
The Company and EnerNOC disagreed with Staff. Reply at 5; EnerNOC Comment.
They said the payment information is EnerNOC's confidential trade secret, that the Company has no
right to obtain it, and that the information does not reflect the value of EnerNOC '5 services or the
value to Program participants. EnerNOC also noted that disclosing the information could impair its
ability to negotiate with participants and damage the aggregator business model that supports the
ORDER NO. 32667 13
Program's effectiveness. The Company and EnerNOC said Staff does not need EnerNOC's
confidential, customer specific incentive payment information to determine that the FlexPeak
Management Program is efficient and cost-effective and that funds were prudently spent. Id.
Commission Decision: Based on our review of the record, we find no need for the
Company's future DSM reports to disclose EnerNOC's incentive payment information so long as the
Company pays a reasonable price and the FlexPeak Management Program is cost-effective. We will
continue to evaluate the FlexPeak Management Program based on its cost-effective performance.
C. Energy Efficiency Programs
The Company offers its Idaho customers seventeen energy efficiency programs.
Application at 3. Staff expressed concern about three of those programs: 1) the Irrigation Efficiency
Rewards Program; 2) the Home Improvement Program; and 3) the Energy Efficiency Lighting
Program. Staff's concerns about the three programs are discussed below.
1. Irrigation Efficiency Rewards Program
Staff had several criticisms about how the Company reported its Irrigation Efficiency
Rewards Program. Staff Comments at 13-15.
First, Staff said the Company reported a 100% net-to-gross energy savings for the
Irrigation Efficiency Rewards Program's Custom and Menu incentive options even though the
Regional Technical Forum estimates apply only to the Menu option. Staff noted, however, that the
Company has now corrected the error and will apply a 75% net-to-gross value to Custom energy
savings. This reduced the UCT from 4.71 to 4.22 and increased the TRC from 1.55 to 1.90. Id. at
13-14.'
Second, Staff said the Company's reported evaluation schedule omits the impact
evaluation scheduled for Irrigation Efficiency in 2011-2012. Id. According to Staff, the Company
later said the impact evaluation was modified to become a research project that would generate
updated energy savings estimates. Staff said the Report should have clearly explained the evaluation
schedule change. Id. at 14-15. The Company did not respond to Staff's observation.
Third, Staff said the Company reported its savings estimates to be "under review" by the
Regional Technical Forum when the Regional Technical Forum actually had deemed those savings
estimates to be "out of compliance." Id. at 14. The Company replied by clarifying that the phrase
"under review" merely refers to the Company's efforts to review Program measures through a
university study, and not to the Regional Technical Forum's measure status. Reply at 5-6.
15 See fn. 1, above, describing the TRC and UCT.
ORDER NO. 32667 14
Fourth, Staff said the Company reported that the Irrigation Efficiency Rewards Program's
non-electric benefits increased about 357% between 2010 and 2011, electric savings increased by
35%, and the budget increased by 7%. Staff said the Company attributes the increase in non-electric
benefits to "improved ... tracking of non-electric benefits [using] a new, more comprehensive
database." But Staff said the Report does not mention the new database. Staff Comments at 14.
Further, Staff said the Company's "massive addition" of non-electric benefits increased the
Program's TRC from 1.52 in 2010 to 1.55 in 2011. Id. 16 According to Staff, the Company later said
its estimated non-electric benefits—including yield benefits, labor savings, maintenance savings, and
water savings—are not verifiable but merely the product of a project engineer's judgment. Id. Staff
concluded that the "357% increase in non-electric benefits, which rests on the unevaluated
estimations of program engineers, creates an artificially high TRC." Staff speculated that the
Program might not pass the TRC when energy savings are verified by an impact evaluation and if
non-electric benefits are removed. Accordingly, Staff recommended that the Company include in its
program cost-effectiveness the TRC value with and without non-electric benefits. Id. at 15 and 17.
In reply, the Company said that Staff used inequivalent data points when comparing the
reported increase in the Irrigation Efficiency Rewards Program's costs and non-electric benefits
between 2010 and 2011. Reply at 5-7. The Company said the 2011 increase in non-electric benefits
largely is due to how the Program's Custom Incentive Option treats participant costs. Further, while
Staff said the Program's budget/utility cost increased by 7%, non-electric benefits are not used to
calculate the UCT; rather, they are used to calculate the TRC and so should be compared to the
TRC.'7 The Company said the TRC increased by 91%. Id. The Company disagreed with Staff's
recommendation that future DSM reports include the TRC ratio with and without non-electric
benefits. The Company said Staff's recommendation departs from national guidelines and the DSM
MOU, which recognizes that non-electric benefits are "important and prudent factors to assess in
analyzing cost-effectiveness."'8 Id. at 6-7 (quoting DSM MOU at 9-10). The Company said third
party evaluators have described the Irrigation Efficiency Rewards Program as a "leading edge
irrigation program" (Id. at 7), the DSM MOU guidelines accurately assess the Program's value, and
that Staff's proposed TRC variation is unnecessary. Id.
16 See fn. 1, above, describing the TRC.
17 See fn. 1, above, describing the TRC and UCT.
18 See fri. 5, above, describing the DSM MOU.
ORDER NO. 32667 15
Commission Decision: Based on our review of the record, we find that the Company's
DSM Report should have clearly explained the evaluation schedule change as discussed by Staff, and
we direct the Company to clearly disclose such changes in its future DSM reports. But we decline to
require that the Company's future DSM reports include the TRC ratio with and without non-electric
benefits. Staff should undertake to negotiate a new DSM MOU if Staff believes the current cost-
effectiveness tests are inadequate.
2.Home Improvement Program
Staff said the Company's 2011 Home Improvement Program was not cost-effective in
2011 for a couple of reasons. First, the Program created an incentive for residential customers with
electric heat or central air conditioning to add attic insulation to their homes. But during the 2011
impact evaluation the Company learned it had overestimated the Home Improvement Program's
energy savings by wrongly assuming that customers installed high-efficiency windows when they
added insulation. When the impact evaluation calculated accurate savings, only attic insulation
incentives for customers with electric heat remained cost-effective. Second, the Company paid
incentives to 40 non-qualifying applicants. These problems lead Staff to opine that the Company
does not adequately oversee its residential programs. Staff Comments at 13 and 15. That said, Staff
noted that the Company is revising its Program to include only cost-effective measures, and that it is
tightening its applicant-review process. Id. at 15.
The Company did not specifically respond to Staff's comments about the Home
Improvement Program. It acknowledged that the Home Improvement Program was not cost-
effective in 2011. Reply at 8.
Commission Decision: We are concerned about the Company's errors in managing
the Home Improvement Program. We expect it to correct those errors and to continue adjusting
this (and other individual programs) as their cost-effectiveness changes, consistent with our
direction that the Company pursue all cost-effective programs. Oversight by Staff and others
should continue, and the Company should seek their feedback.
3.Energy Efficient Lighting Program
Staff said the Company's residential Energy Efficient Lighting Program was slightly less
cost-effective in 2011 but nevertheless has "a strong program life UCT of 4.2 and a TRC of 3.07."
Staff Comments at 15.19 Staff said the decreased cost-effectiveness is due to the Regional Technical
Forum's updated savings assumptions related to the federal Energy Independence and Security Act
19 See fn. 1, above, describing the TRC and UCT.
ORDER NO. 32667 16
of 2007. Id. Staff suggested the Company augment its Program marketing with mobile applications.
Id. The Company did not respond to the Staff's comments, although it did note that the Program was
cost-effective.
Commission Decision: We will continue to evaluate the Energy Efficient Lighting
Program based on its cost-effective performance. We appreciate Staff suggesting that the Company
use mobile applications to help market the Program. We encourage the Company to use such
applications if doing so will cost-effectively enhance Program marketing.
D. Energy Efficiency Advisory Group
Staff said the Energy Efficiency Advisory Group (EEAG) met just three times last year,
and that more frequent and in-depth meetings would greatly improve the dialogue between invited
stakeholders and the Company. Id. at 16, 17. Staff said the Company hinders the quality of EEAG
meetings in two ways. First, the Company only lets EEAG members comment or ask questions.
Second, while the Company updates EEAG members about the Company's DSM activities, it does
not actively seek advice from the EEAG or other stakeholders on such matters. Id. at 16.
In Reply, the Company said most EEAG members support more frequent meetings. The
Company also said the EEAG meetings include workshops, and that the Company hosts webinars for
EEAG members. Reply at 10. The Company said that while EEAG meetings are public, they
primarily are held for the EEAG members. The Company noted that the EEAG members represent
stakeholder groups like the major customer groups, governmental and environmental entities, and the
Company. Reply at 10.
Commission Decision: DSM programs and measures are powerful tools that help
customers manage their energy consumption and mitigate the impact of potential rate increases. In
recognition of this, we direct Idaho Power to expand participation in the EEAG. The EEAG's
primary purpose is to "advise the Company on new measure recommendations, existing measure
revisions, measure prioritization, and evaluation." Order No. 28894 at 7 (emphasis added). Based
on our review of the record, we are concerned that the Company may not be using the EEAG as we
intended or to its fullest potential. While the Company certainly may use EEAG meetings to update
the EEAG on Company DSM activities, the Company must primarily use those meetings to obtain
advice about those activities from the EEAG. To the extent the Company is not obtaining advice
from the EEAG, we direct the Company to resume doing so.
In addition, we find it reasonable to require the Company to increase the number and
depth of the EEAG meetings and encourage questions and feedback from all attending stakeholders,
ORDER NO. 32667 17
(not just EEAG members). While the EEAG consists of stakeholder members, that does not mean
the Company should only take input from EEAG members. We direct the Company to use the
EEAG meetings to improve customer awareness of energy efficiency programs, and to allow
customers, Staff, and other interested persons to provide information and have an advisory role. We
also encourage the Company to take other opportunities to improve customers' energy I.Q. and to
educate them about the Company's energy efficiency programs. For example, the Company might
hold workshops or post videos on its website that explain the energy efficiency programs it offers,
why it selects certain programs and measures over others, and how it perceives cost-effectiveness and
values energy efficiency within its system.
ULTIMATE FINDINGS OF FACT AND CONCLUSIONS OF LAW
Idaho Power is an electrical corporation. The Commission has jurisdiction and authority
over Idaho Power and the issues in this case under Title 61 of the Idaho Code and the Commission's
Rules of Procedure, IDAPA 31.01.01.000, et. seq. Based on our review of the record and the
discussion above, we find that Company prudently incurred $41,942,123.50 in DSM expenses in
2011, including $34,923,738.50 in net Rider expenses and $7,018,385 in Custom Efficiency Program
incentive expenses.
ciis'n
IT IS HEREBY ORDERED that Idaho Power's 2011 DSM expenditures are approved as
prudently incurred in the amount of $41,942,123.50, as described above.
IT IS FURTHER ORDERED that the Company take such actions as are directed in the
body of this Order.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7) days
after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code § 61-626.
ORDER NO. 32667 18
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this a
day of October 2012.
PAUL KJELLANDE , RESIDENT
\\kA \J
MACK A. REDFORD, COMMISSIONER
IL
MARSHA H. SMITH, COMMISSIONER
ATTEST:
Jn D. Jewe1I7
6mmission Secretary
O:IPC-E- 12-1 5_kk3
ORDER NO. 32667 19