20101022Nemnich Di.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S REQUEST TO MODIFY
RECOVERY OF INCENTIVES PAID TO
SECURE DEMAND-SIDE RESOURCES.
CASE NO. IPC-E-IO-27
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
DARLENE NEMNICH
1 Q.Please state your name and business address.
2 A.My name is Darlene Nemnich. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what
5 capacity?
6 A.I am employed by Idaho Power Company ("Idaho
7 Power" or "Company") as a Senior Regulatory Affairs
8 Analyst.
9 Q .Please describe your educational background.
10 A.In May of 1979, I received a Bachelor of
11 Arts degree in Business Administration with emphases in
12 Finance and Economics from the College of Idaho in
13 Caldwell, Idaho. In addition, I have attended the electric
14 utility ratemaking course offered through New Mexico State
15 University's Center for Public Utili ties as well as various
16 other ratemaking courses sponsored by the Edison Electric
1 7 Institute.
18 Q.Please describe your business experience
19 wi th Idaho Power.
20 A.In 1982, I was hired as an analyst in the
21 Resource Planning Department. My primary duties were the
22 calculation of avoided costs for cogeneration and small
23 power production contracts and the calculation of costs of
24 future generation resource options. In 1989, I moved to
NEMNICH, DI 1
Idaho Power Company
1 the Energy Services Department where I performed economic,
2 financial, and statistical analyses to determine the cost-
3 effectiveness of demand-side management programs. I stayed
4 in that general area designing, implementing, and
5 evaluating programs until 2000, when I was promoted to
6 Energy Efficiency Coordinator. In that capacity, I
7 coordinated the Company's effort to expand customer
8 programs and education in energy efficiency. I was
9 responsible for complying with regulatory and financial
10 requirements in the area of energy efficiency. In 2003, I
11 was promoted to Energy Efficiency Leader where I managed
12 the Company's demand-side management efforts, including
13 strategic planning, design and development of programs,
14 regulatory compliance, and overall management of the
15 department.
16 In 2006, I left the Company to pursue personal
17 opportuni ties but returned to the Company as a Senior
18 Regulatory Affairs Analyst in the Regulatory Affairs
19 Department in April 2008. My duties as Senior Regulatory
20 Affairs Analyst include the development of alternative
21 pricing structures, analysis of the impact on customers of
22 rate design changes, providing regulatory assistance in the
23 area of demand-side management, and the administration of
24 the Company's tariffs.
NEMNICH, DI 2
Idaho Power Company
1 Q.What is the scope of your testimony in this
2 proceeding?
3 A.My testimony will address two areas:(1 )
4 the Company's proposal for changes in how demand response
5 incentive costs are recovered and (2) the Company's
6 proposal for changes in how some of the energy efficiency
7 incenti ve costs are recovered.
8 Q.How does your testimony tie to Mr. Gale's
9 testimony?
10 A.Mr. Gale's testimony provides a
11 comprehensi ve policy discussion on the subj ect of demand-
12 side resources ("DSR"). The two proposals contained in my
13 testimony are intended to support the implementation of two
14 parts of the Company's overall plan as described by Mr.
15 Gale.
16 Q.Are you sponsoring any exhibits?
17 A.Yes. I am sponsoring Exhibit No.1, Energy
18 Efficiency Rider Account Projections.
19 Q.Please describe the Company's proposal for
20 changes in how demand response incentive costs are
21 recovered.
22 A.Currently, all Idaho demand response program
23 costs are recovered through the Energy Efficiency Rider
24 ("Rider") balancing account, Idaho Rate Schedule 91. The
NEMNICH, DI 3
Idaho Power Company
1 Company is proposing to move the recovery of some of those
2 costs to the Power Cost Adjustment ("PCA") mechanism.
3 Q.What demand response programs have been
4 implemented by the Company as part of its overall DSR
5 portfolio?
6 A.Idaho Power currently manages three demand
7 response programs. The A/C Cool Credit program provides
8 summer peak reduction benefits by cycling participating
9 residential customers' air-conditioning units. This
10 program began in 2003. The Irrigation Peak Rewards program
11 began in 2004 and switches off participating customers'
12 irrigation pumps during times when additional system peak
13 resources are needed. The most recently implemented demand
14 response program, FlexPeak Management, began in 2009 and
15 reduces commercial and industrial load when called upon
16 during system peak times.
17 Q.How does the Company determine the amount of
18 demand response resources to acquire?
19 A.The overall amount and timing of demand
20 response resources the Company acquires is determined
21 through the development of the Integrated Resource Plan
22 ("IRP"). The IRP identifies when new peak resources are
23 needed due to increased load. Options to meet that peak
24 capacity requirement, whether from new peaking plants or
NEMNICH, DI 4
Idaho Power Company
1 new demand response programs, are evaluated and the least-
2 cost option that best fits the need is selected.
3 Q.How many megawatts ("MW") of peak demand did
4 these programs contribute to offset system peak needs in
5 recent history?
6 A.In 2009, the three programs provided 218 MW
7 of resources available to meet system peak needs. In 2010,
8 preliminary estimates indicate that these programs reduced
9 peak by approximately 290 MW.
10 Q.Have the demand response programs supplied
11 the Company a consistent and reliable resource similar to
12 other peaking resources?
13 A.Yes. System dispatchers use demand response
14 resources to meet system needs alongside traditional
15 supply-side means of meeting system peak requirements, like
16 a gas-fired simple cycle combustion turbine or wholesale
17 energy purchases. For the past several years at the
18 beginning of each summer peak season, Company system
19 dispatchers and demand resource program managers have
20 reviewed the total demand response resource available and
21 the general operating parameters of each program for the
22 year. Then, each week of the summer season, system
23 resource dispatchers are given the amount of demand
NEMNICH, DI 5
Idaho Power Company
1 response resource, in megawatts of peak reduction, which
2 will be available for dispatch that week.
3 Q.Gi ven the characteristics you have described
4 for the demand response resources, why is it appropriate to
5 include them in the PCA mechanism?
6 A.Demand response programs have become a
7 significant and mature resource for reducing the varying
8 summer peaking needs on the Idaho Power system. Demand
9 response resources are selected similar to other generating
10 resources in the IRP, and most importantly, this resource
11 is dispatched by system operators just like any other
12 peaking resource used by the Company. Starting with the
13 2009 IRP, demand response resources were included in the
14 Power Supply Planning model, AURORAxmp.
15 Q.Currently, how are demand response program
16 costs recovered?
17 A.All costs for the demand response programs
18 are recovered through the Rider. Currently, the Idaho Rider
19 charge is 4.75 percent of base rates applied to all
20 customer groups. Idaho Power tracks the costs of its
21 demand response programs by program and expense type.
22 These cost categories include incentives , administrative
23 costs, materials and equipment, marketing costs, labor, and
24 evaluation.
NEMNICH, DI 6
Idaho Power Company
1 Q.What categories of costs is the Company
2 proposing to be recovered through the PCA mechanism?
3 A.The Company proposes that the costs which
4 would most appropriately be recovered through the PCA are
5 the direct incentive costs paid either to customers for
6 demand reduction or to demand-aggregator contractors for
7 demand reduction. Incenti ve costs more closely represent
8 the variable cost used to acquire a peak resource during a
9 peak shortage.
10 Q.Why not move all demand response program
11 costs out of the Rider and into the PCA?
12 A.The PCA typically recovers variances in net
13 power supply expenses. These expenses, which include fuel,
14 purchased power, and surplus sales, vary over the course of
15 the year as the Company responds to meeting system load
16 requirements. Generally, demand response program costs,
17 other than those associated with direct incentive costs, do
18 not vary with the dispatching of this peak resource and
19 therefore could be categorized as fixed costs. That is why
20 the Company has chosen to propose to move only demand
21 response incentive costs to the PCA.
22 Q.Are you proposing to shift costs incurred in
23 2010?
NEMNICH, DI 7
Idaho Power Company
1 A.No. Idaho Power is proposing that all 2010
2 actual program costs, even the demand response incentive
3 costs for reduced load for the summer peak season, continue
4 to be recovered through the Rider. Idaho Power's proposal
5 is to begin shifting the recovery of the demand response
6 incenti ve costs to the PCA beginning with the Company's
7 forecast of April 2011 through March 2012 power supply
8 costs.
9 Q.What will be the amount of forecasted demand
10 response incentive costs included in the 2011 PCA?
11 A.It is premature to know the exact amount of
12 the demand response incentive costs to be included in the
13 2011 PCA. However, current estimates of the 2011 demand
14 response incentive costs based upon the current structure
15 of the three programs would be approximately $13. 7 million.
16 This estimate would be refined next spring as summer loads
17 and resource needs are reevaluated.
18 Q.How do you propose to include the forecasted
19 demand response incentive costs in the 2011 PCA?
20 A.Idaho Power proposes to include these costs
21 in the PCA in a manner that is consistent with the current
22 PCA methodology. The Company would forecast demand
23 response incentive payments just as it does for its
24 forecast of fuel, purchased power, and surplus sales. This
NEMNICH, DI 8
Idaho Power Company
1 forecasted amount of demand response incentive costs would
2 be included in PCA rates, effective June 1, 2011.
3 Q.Does the Company intend to establish a base
4 level of demand response incentive cost recovery in base
5 rates just like other power supply costs?
6 A.Yes, but not at this time. As part of a
7 future filing , it would make sense for the Company to
8 include a normal or base level of demand response incentive
9 expenses in base rates just like other supply-side peaking
10 resources. Then annually, as part of the PCA case, the
11 forecasted level of incentive payment expenses would be
12 compared to the normal level included in base rates to
13 determine the level of demand response cost recovery to be
14 included in the PCA forecast. Any deviations between
15 actual demand response incentive costs and forecasted costs
16 would be included in the following year's PCA true-up.
17 Q.How would demand response costs be
18 allocated?
19 A.Idaho Power proposes to allocate 100 percent
20 of the Idaho incentive payment costs to the Idaho
21 jurisdiction in the PCA. This is no different from the
22 current recovery of demand response incentive costs through
23 the Rider where Idaho customers are paying for 100 percent
NEMNICH, DI 9
Idaho Power Company
1 of the demand response incentives incurred by Idaho
2 customers. It is logical that if the recovery of those
3 costs is moved from the Rider to the PCA, that the
4 jurisdictional assignment of those costs remains
5 consistent.
6 Q.Do you propose that 100 percent of the
7 demand response incentive payments be recovered in the PCA?
8 A.Yes. Because 100 percent of these demand
9 response costs are currently being recovered in the Rider,
10 recovering 100 percent of these costs in the PCA would be
11 consistent. To do otherwise would force Idaho Power to
12 take a financial loss on its pursuit of demand response as
13 a resource.
14 Q.Do any other utili ties have their demand
15 response program incentive costs recovered outside of an
16 energy efficiency rider?
17 A.Yes. Rocky Mountain Power does not recover
18 their Idaho irrigation load control program incentive
19 amounts from their energy efficiency rider account. Those
20 amounts are currently recovered through Idaho base rates.
21 Also, costs from Portland General Electric's current demand
22 response pilot are tracked in a deferred account and PGE
23 requested these amounts be transferred to their PCA at the
24 end of the pilot.
NEMNICH, DI 10
Idaho Power Company
1 Q.Please describe the Company's second
2 proposal that would change the method of recovery for a
3 portion of energy efficiency program incentive payments.
4 A.In addition to moving demand response
5 incenti ve costs to the PCA, Idaho Power is proposing to
6 change the method of recovering a portion of the energy
7 efficiency program incentive costs. Currently, all energy
8 efficiency incentive costs are recovered through the Rider
9 balancing account. As explained in Mr. Gale's testimony,
10 the Company is proposing to capitalize the direct incentive
11 payments associated with the Custom Efficiency program to
12 enable the Company to earn a return on a portion of its
13 demand-side resource activities. The Company proposes to
14 start booking direct incentive payments for the Custom
15 Efficiency program to a regulatory asset account beginning
16 January 1, 2011. The balance in the account would be
17 included in the Company's revenue requirement at the time
18 of a future rate case and would be amortized over four
19 years. The then current Commission authorized rate of
20 return would be applied as a carrying charge during the
21 deferral period and the amortization period. This
22 treatment will keep the selected demand-side resource
23 assets on par with Company investments in supply-side
24 assets.
NEMNICH, DI 11
Idaho Power Company
1 Q.Please describe the Custom Efficiency
2 program and explain why it was selected for capitalization.
3 A.The Custom Efficiency program is a mature
4 program that started in 2003 and has grown into the
5 Company's largest program in terms of megawatt-hour ("MWh")
6 savings. Each customer proj ect wi thin the Custom
7 Efficiency program is thoroughly reviewed to ensure that
8 energy savings are achieved. The energy savings are
9 calculated by Idaho Power engineering staff or a third-
10 party consultant. The verification process requires that
11 end-use measure information is collected. On many
12 projects, and especially the larger and more complex
13 projects, Idaho Power or a third-party consultant conducts
14 on-si te power monitoring and data collection before and
15 after proj ect implementation. The measurement and
16 verification process ensures achievement of projected
17 energy savings. Additionally, this program historically is
18 one of the most cost-effective programs in the Idaho Power
19 portfolio. As shown on page 43 of Supplement 1 of the
20 Demand-Side Management 2009 Annual Report filed in Case No.
21 IPC-E-10-09, from a Total Resource Cost ("TRC")
22 perspective, the 2009 TRC benefit/cost ratio was 3.56. If
23 analyzed over the life of the program, the TRC benefits are
24 more than twice the costs. The program maturity, the high
NEMNICH, DI 12
Idaho Power Company
1 benefi t/ cost ratios, and the detailed verification process
2 were maj or factors in the selection of this program for
3 cost deferral and capitalization.
4 Q.How many megawatt-hours did this program
5 save in recent history?
6 A.In 2008 and 2009, the Custom Efficiency
7 program saved 41,059 and 51,836 MWhs, respectively. In
8 2009, this represented almost 40 percent of the total MWh
9 savings on a system-wide basis for energy efficiency
10 programs implemented by Idaho Power.
11 Q.Please explain the current method of
12 tracking energy efficiency incentive costs.
13 A.As mentioned earlier, costs for the energy
14 efficiency programs are recovered the same as the demand
15 response programs - through the Idaho Rider. Idaho Power
16 tracks the costs of its energy efficiency programs by
17 program and expense type. These cost categories include
18 incentives , administrative costs, materials and equipment,
19 marketing costs, labor, and evaluation.
20 Q.Which cost categories does the Company
21 propose be capitalized?
22 A.The costs which would most appropriately be
23 capi tali zed are the direct incentive costs paid to
24 customers for energy efficiency measures. The maj ori ty of
NEMNICH, DI 13
Idaho Power Company
1 payments made for direct incentives are for tangible
2 equipment in customer facilities. This equipment can be
3 viewed as similar to physical plant except it is not owned
4 by the Company; it is owned by the customer.
5 Q.When these costs are placed into rate base,
6 how would the Company allocate energy efficiency incentive
7 costs?
8 A.Idaho Power proposes to allocate 100 percent
9 of the Idaho incentive payment costs to the Idaho
10 jurisdiction. Currently, Idaho customers are paying for the
11 energy efficiency program incentives incurred by Idaho
12 customers. It is logical that if the recovery of those
13 costs is moved from the Rider into a regulatory asset
14 account that is capitalized, that the jurisdictional
15 assignment of those costs remains consistent.
16 Q.What is the current balance in the Energy
17 Efficiency Rider balancing account?
18 A.As of the end of September the Rider account
19 balance was $16,688,002.
20 Q.Have you estimated what the Rider balance
21 would be if neither of the Company's proposals are approved
22 by the Commission?
23 A.Yes. Exhibit No.1, Table 1, shows a three-
24 year forecast of the Rider balance with revenues at current
NEMNICH, DI 14
Idaho Power Company
1 rates and with the current forecast of demand-side resource
2 expenditures. The estimated 2010 year-end negative balance
3 of $17,009,140 increases to a negative $29,677,151 in 2012.
4 Q.How did you arrive at this estimate?
5 A.I used the same revenues that were used in
6 compliance filings made June 1, 2010 , with the Idaho Public
7 Utilities Commission pursuant to Order Nos. 31091, 31093,
8 and 31097. Then I applied the current Rider percent of
9 4. 75 to calculate Rider revenues. All DSR expenditures are
10 from current forecasted estimates. For 2010, I used
11 January-August actual values and forecasted values for
12 September-December.
13 Q.If approved by the Commission, how will
14 implementing the Company's two proposals affect the
15 forecasted balance of the Rider?
16 A.Table 2 of Exhibit No. 1 reflects the impact
17 of the two proposals and shows that the 2010 negative Rider
18 balance of $17,009,140 would be reduced to a negative
19 $3,356,306 in 2011. If the current forecasted revenues and
20 expenses hold true, it is expected that this account will
21 approach zero sometime in the middle of the year 2012.
22 Q.How did you arrive at these estimates?
23 A.To arrive at these numbers, I started with
24 Table 1, described above. For 2011 and 2012, I subtracted
NEMNICH, DI 15
Idaho Power Company
1 the forecasted incentive costs for demand response programs
2 of $13, 753,335 and $ 14,537,368 , respectively, in the row
3 labeled Less DR Incentives. These forecasted values are
4 the estimates of demand response incentives that would be
5 transferred to the PCA mechanism. I also subtracted out
6 the forecasted incentive costs for the Custom Efficiency
7 energy efficiency program of $5,193,650 in 2011 and
8 $5,565,480 in 2012 in the row labeled Less EE Incentives.
9 These forecasted values are the estimates of incentive
10 costs for the Custom Efficiency program that would be
11 transferred to a regulatory asset account for
12 capi talization. Only the actual incentive payments made to
13 customers would be included in the regulatory asset
14 account.
15 Q.Have you calculated the Rider percent
16 necessary to take the Rider account balance to zero absent
17 Commission approval of the two Company proposals?
18 A.Yes. The Rider percentage would have to
19 increase from the current 4. 75 percent to approximately 6.6
20 percent in January 2011 for the balance to be zero by the
21 end of 2012. To take the Rider balance to zero in one
22 year, by the end of 2011, the Rider percent would have to
23 increase from the current 4. 75 percent to approximately 7.5
24 percent.
NEMNICH, DI 16
Idaho Power Company
1 Q.If the Commission adopts these proposals,
2 would it change the ability of the Commission and its staff
3 to review incentive costs for prudency?
4 A.No. Demand response incentive costs would be
5 reviewed along with power supply expenses and market
6 transactions as part of the PCA review process between
7 April 15 and June 1 of each year. However, unlike other
8 PCA costs, the prior year's costs will be available for
9 review earlier because they will be included in the Demand-
10 Side Management Annual Report filed March 15.
11 Energy efficiency incentive costs can be reviewed
12 during the annual prudency review filed by the Company.
13 Q.Why are you proposing these changes at this
14 time?
15 A.With regard to the first proposal to move
16 demand response incentive costs to the PCA, Idaho Power is
17 filing for this change now in order to provide the
18 Commission ample time for deliberation and review prior to
19 the annual spring PCA filing. If the Commission agrees to
20 this proposal, Idaho Power will be able to include these
21 changes in the April 15, 2011 PCA filing. With regard to
22 the second proposal, with a Commission order allowing
23 creation of a deferral account, the Company will be able to
NEMNICH, DI 17
Idaho Power Company
1 begin deferring the appropriate energy efficiency
2 incentives as of January 1, 2011.
3 Q.Does this conclude your testimony?
4 A.Yes, it does.
NEMNICH, DI 18
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-10-27
IDAHO POWER COMPANY
NEMNICH, DI
TESTIMONY
EXHIBIT NO. 1
Idaho Power Company
Energy Effciency Rider Account Projections
Table 1
Projected Year-End Energy Efficiency Rider Account Balances
Expected Expenditures
2010-2012
Actuals (Jan-Aug)
Forecast (Sep-Dec)
2010
Calculation of Rider Revenues
Estimated Total Revenues
Idaho Rider Percent
Idaho Rider Revenue (1)$34,976,990
Calculation of Rider Balance
Beginning Balance
Revenue(l)
Total Expenses(2)
Ending Balance
($9,718,518)
$34,976,990
($42,267,612)
($17,009,140)
Forecast
2011
$801,868,308
4.75%
$38,088,745
($17,009,140)
$38,088,745
($43,382,895)
($22,303,290)
Forecast
2012
$801,868,308
4.75%
$38,088,745
($22,303,290)
$38,088,745
($45,462,605)
($29,677,151)
Table 2
Projected Year-End Energy Effciency Rider Account Balances
With DR incentives to PCA and EE Incentives to Deferred Account
2010-2012
Calculation of Rider Balance
Beginning Balance
Revenue(l)
Total Expenses(2)
Less DR Incentives
Less EE Incentives
Net Expenses
Ending Balance
($9,718,518)
$34,976,990
($42,267,612)
$0
$0
($42,267,612)
($17,009,140)
($17,009,140)
$38,088,745
($43,382,895)
$13,753,335
$5,193,650
($24,435,910)
($3,356,306)
($3,356,306)
$38,088,745
($45,462,605)
$14,537,368
$5,565,480
($25,359,757)
$9,372,682
(1) 2010 revenue; Jan-Aug actual $22,805,939, Sep-Dec forecast $12,171,051.
All forecast revenues based on June 1, 2010, Spring IPUC compliance filngs per Order Nos. 31091, 31093, and 31097.
Rider revenues are 4.75% of forecast revenues.
(2) Total expenses for 2010 include Jan-Aug actuals, Sep-Dec forecast.
All expenses and incentive values based on current forecast.
Exhibit No. 1
Case No. IPC-E-10-27
D. Nemnich, IPC
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