HomeMy WebLinkAbout20100225Application.pdf'''~ROCKY MOUNTAINPOERADIVSlONOFPACIFICRP ZOIO FEB 25 A~1 to: 26
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201 South Main, Suite 2300
Salt Lake City, Utah 84111
February 25,2010
VI OVERNIGHT DELIVERY
Idaho Public Utilities Commission
472 West Washington
Boise,ID 83702-5983
Attention:Jean D. Jewell
Commission Secretary
Re:Case No. PAC-E-IO-03
In the Matter of the Application of Rocky Mountain Power for an Increase to
the Customer Efficiency Services Rate.
Rocky Mountain Power, a division of PacifiCorp, hereby submits for fiing an original and seven
(7) copies of its Application in the above referenced matter.
Service of pleadings, exhibits, orders and other documents relating to this proceeding should be
served on the following:
Ted Weston
Idaho Regulatory Affairs Manager
201 South Main, Suite 2300
Salt Lake City, UT 84111
Telephone: (801) 220-2963
Facsimile: (801) 220-2798
E-mail: Brian.Dickman(iPacifiCorp.com
Danel Solander
Senior Counsel
201 South Main, Suite 2300
Salt Lake City, UT 84111
Telephone: (801) 220-4014
Facsimile: (801) 220-3299
E-mail: DaneL.Solander(iPacifiCorp.com
It is respectfully requested that all formal correspondence and Staff requests regarding this
material be addressed to:
Bye-mail (preferred):datarequest~pacificorp.com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, Oregon 97232
Any informal inquiries may also be directed to Ted Weston at 801-220-2963.
Idaho Public Utilities Commission
Februar 25,2010
Page 2
Enclosures
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IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR AN
INCREASE TO THE CUSTOMER
EFFICIENCY SERVICE RATE
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APPLICATION OF
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-IO-03
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-IO-03
Application and Attachments
February 25,2010
Mark C. Moench
Danel E. Solander
201 South Main, Suite 2300
Salt Lake City UT 84111
Telephone: (801) 220-4014
FAX: (801) 220-3299
Email: danieL.solander(ipacificorp.com
mark.moench~pacificorp.com
R
iola FEB 25 AM 10: 26
Attorneys for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR AN )CASE NO. PAC-E-IO-03
INCREACE TO THE CUSTOMER )
EFFICIENCY SERVICES RATE )APPLICATION
)
)
COMES NOW, Rocky Mountain Power, a division of PacifiCorp (the
"Company"), and in accordance with RP 052 and RP 201, et. seq., hereby applies to the
Idaho Public Utilities Commission (the "Commission") for approval to adjust the
Customer Efficiency Services Rate (Schedule No. 191). The adjustment is needed to
faciltate the fuding of ongoing demand-side management ("DSM") program
expenditues and reduce the back balance or yet to be recovered DSM expenses in the
DSM balancing account from $3.5 milion, the April 2010 forecasted balance to $2.25
milion by April 30, 2011, a reduction of approximately $1.25 milion. The Company
expects to review funding needs again in early 2011 to determine whether this proposed
adjustment is sufficient to fud ongoing program expenses beyond April 2011 and
recover the remaining balance owed the Company in the DSM balancing account at that
APPLICATION OF ROCKY MOUNTAIN POWER - 1
time. In this Application, the Company seeks to increase the Schedule No. 191 rate from
3.72 percent to 5.85 percent. The Company respectfully requests that this Schedule No.
191 adjustment become effective May 1,2010.
In support of its Application, Rocky Mountan Power states:
1. Rocky Mountain Power does business as a public utilty in the State of
Idaho and is subject to the jurisdiction of the Commission with regard to its public utility
operations.
2. This Application is filed pursuant to Idaho Code §§ 61-301, 61-307, 61-
622, and 61-623. In paricular, Idaho Code § 61-623 empowers the Commission to
determine the propriety of proposed rate schedules, §§ 61-307 and 61-622 require
Commission approval prior to any increase in rates, and § 61-301 requires Idaho retail
electric rates to be just and reasonable.
3. This Application is fied in compliance with Customer Information Rile
102 (IDAPA 31.21.02.102). Notices of the proposed rate change will be included as a
bil insert staring Februar 25, 2010 and wil continue until all Idaho customers have
received a bil with a notice. The Company estimates this will tae approximately 30
days from date of this fiing. See Attchment 1 for a copy of the customer notice and the
press release.
BACKGROUND
4. As far back as the 1970s the Company has offered a variety of DSM
programs to its customers. As with all the Company's DSM programs, those offered by
Rocky Mountain Power in Idaho have been designed to be cost-effective. On March 2,
APPLICATION OF ROCKY MOUNTAIN POWER - 2
2006, the Commission approved an enhanced set of DSM programs and cost recovery
through Schedule No. 191, Customer Efficiency Services Rate, which was applied to
customers' bils beginning on May 1, 2006. The collection rate was set at 1.5 percent,
which was below the rate needed by the Company to fully fud all reasonably available
cost-effective resources identified at that time. The enhanced set of programs was
designed to measure Idaho customers' wilingness to paricipate in programs and the
Company's ability to deliver them cost-effectively.
To manage collection and program expenses durng the initial period, the
Company did not introduce the Energy FinAswer program for business customers and
tied paricipation to funding availability for business energy effciency programs.
On Februar 14, 2008, the Company filed an application with the Idaho Public
Utilities Commission requesting authorization to increase the Customer Effciency
Services Rate, Schedule No. 191, from 1.5 percent to 3.72 percent. In Order No. 30543
the Idaho Public Service Commission approved this increase effective on May 1,2008.
The increase to the Customer Effciency Services Rate provided additional
fuding for operating programs, including:
Schedule No. 117 - Refrigerator Recycling;
Schedule No. 21 - Low Income Weatherization Services; and,
Schedule Nos. 72 and 72A - Irrigation Load Control Credit Rider.
Additionally it allowed the Company to enhance some of its other programs such
as:
Schedule No. 115 - FinAnswer Express;
APPLICATION OF ROCKY MOUNTAIN POWER - 3
Schedule No. 155 - Irrgation Energy Services; and,
Schedule No. 118 - Home Energy Savings.
The Company also offered one new program - Schedule No. 125 - Energy
FinAnswer.
5. Program performance, including expenditues, savings and assessments of
cost-effectiveness, as well as the balancing account activity associated with Schedule No.
191 for the period from Januar 1, 2006, through December 31, 2007, was provided in
the Annual Report of Idaho Demand Side Management Activities filed with the
Commission March 14, 2008, and prudency determination in Case No. PAC-E-08-07
Order No. 30783. Program performance, including expenditures, savings and assessment
of cost effectiveness for the period from January 1, 2008, through December 31, 2008,
was provided in the Anual Report of Idaho Demand Side Management Activities filed
with the Commission on March 18,2009.
The energy effciency programs in place in 2009 are cost-effective based on a
preliminar assessment using actual expenditures and achieved savings for 2009. The
results from this preliminary assessment are included in Attchment 2. The Annual
Report of Idaho Demand Side Management Activities for 2009 will be filed with the
Commission on or before March 15,2010, and wil contain complete information on the
2009 program performance.
6. The load control service credits available for Irrgation Load Control
Credit Rider participants (Schedules No. 72 and 72A) has not been included in or
collected through the Customer Efficiency Services rate. However, these credits are
APPLICATION OF ROCKY MOUNTAIN POWER - 4
included in the program's cost-effectiveness assessments, including the preliminar
assessment of the 2009 program results found in Attachment 2 of ths filing. The load
control service credit paid to customers for the 2009 program year was $7.3 milion.
DESCRIPTION OF CHANGES AND COST DRIVERS
7. Schedule No. 191- "Customer Effciency Services"
The Company proposes to adjust the collection rate for Schedule No. 191 from
3.72 percent to 5.85 percent of retail revenue, excluding the taiff contract customers,
which is a 2.13 percent net increase to customers subject to that schedule. Ths collection
rate is designed to fund ongoing demand-side management ("DSM") program
expenditues and reduce the back balance or yet to be recovered DSM expenses in the
DSM balancing account from $3.5 milion, the April 2010 forecasted balance, to $2.25
milion by April 30, 2011, a reduction of approximately $1.25 milion. The Company
will continue to review fuding needs on an annual basis to determine whether this
proposed adjustment is suffcient to fud ongoing program expenses and continue to
recover the remaining balance owed the Company in the DSM balancing account at that
time. At 5.85 percent of retail revenues, Schedule 191 wil provide approximately $8.325
milion per year, assuming 2008 energy usage levels. As noted, Schedule No. 191
collections does not fud an estimated $7.3 milion in Schedules No. 72 or 72A irrigation
load control service credits curently recovered in the Company's base rates.
Administration of the balancing account, including carying charges, prudence
review, and separating these costs from the revenue requirement in general rate cases
would continue as outlined in Order No. 29976.
APPLICATION OF ROCKY MOUNTAIN POWER - 5
8. Residential Programs
While the fuding by program vares, the projected residential program fuding of
$.980 milion (excluding fuding for the Northwest Energy Efficiency Alliance) for May
1,2010, though April 30, 2011, is consistent with the 2009 level forecasted in Case No.
PAC-E-08-01.
. Refrigerator Recycling Program
Paricipation and estimated savings associated with the refrigerator recycling
program in 2009 were consistent with 2008 levels. When compared to the estimates
provided in Case No. PAC-E-08-01, 2008 and 2009 energy savings are 45 percent of the
forecast and expenditues are 41 percent of forecast. The changes are attributed to
general economic conditions prevailing for mostf the period, which may have resulted
in a reluctance to recycle working appliances. In the last half of 2009, all markets for
Rocky Mountain Power were re-assessed. Curent forecasts show an increase in
refrgerator and freezer recycling in 2010 and 2011 demand in all markets including
Idaho. As a result, the projected 2010 anual expenses and energy savings for the
program are expected to increase by about 60 percent when compared to 2009.
. Home Energy Efficiency Incentive program
Energy savings associated with the Home Energy Efficiency Program more than
doubled when compared to 2008, while the expenditues increased by approximately 20
percent when compared to 2008. As noted in the 2008 anual report referenced above,
one of the major factors that impeded customer paricipation in the program in 2008 was
APPLICATION OF ROCKY MOUNTAIN POWER - 6
the lighting program alignment, which was overcome in 2009. This improved alignment
in 2009 resulted in a four-fold increase in lighting savings when compared with 2008.
The availability of federal tax credits and media coverage surounding federal
stimulus fuding began increasing the overall awareness and interest in providing energy
efficiency opportunities in homes. Contractors and retailers in tur have 'developed
marketing messages and sales materials that feature the availability of the federal tax
credit and increased customer contact. Use of the tax credit as a sales tool has been
especially prominent in the window replacement market. The addition of incentives for
heat pumps in 2008 increased overall activity in the HV AC market that has cared over
into 2009 program results.
Weatherization activity has increased as a result of the slow-down in the new
construction markets, increasing competition among contractors now focusing on the
retrofit market. The impact has been threefold: 1) reduction in installed costs of
weatherization services; 2) near "free" deals for customers; and 3) an increase of
insilation projects. This trend has been fuher accelerated as the result of the availabilty
of the federal tax credit. To better align program incentives with current market
conditions, the Company utilized the notice provisions of Schedule 118 on Februar 3,
2010, to inform customers who visit the Company's website and contractors who have
paricipated in the program that insulation incentives wil change effective March 20,
2010.
The program expenditue forecast for 2010 is based on a December 2009 forecast
and approximates 2009 expenditures. After factoring for increased activity in some areas
and the proposed changes to insulation incentives, 2010 expenditures are forecasted to be
APPLICATION OF ROCKY MOUNTAIN POWER - 7
about the same as 2009's actual expenditues. The program administrator has performed
additional market sensitivity analysis work which indicates additional opportunity and
potential program expenditures in 2010 beyond that included in the curent Application.
However, a relatively wide range of uncertainty associated with the overall impact of
adjusted weatherization incentive levels led the Company to not further increase program
funding requirements, taking a more reserved position in our forecast for the puroses of
this Application. Furhermore, it should also be noted that the program funding estimates
used in this Application do not include some of the key measures in the Northwest Power
and Conservation Council's DRAFT 6th Power Plan such as heat pump water heaters and
ductless heat pumps, measures that may be applicable to the Rocky Mountain Power's
Idaho customers and impact program expenditues in the near future.
9. Commercial and Industrial Programs
The projected fuding for Energy FinAswer Express and Energy FinAswer for
the period May 1,2010, through April 30, 2011, is $800,000. This is consistent with the
2009 level forecasted in Case No. PAC-E-08-01.
The FinAnswer Express program has been available in Idaho since early 2006 and
was the sole program for business customers (other than those served on Schedule 10)
until May 2008 when the Energy FinAswer program became available. Since then the
Energy FinAswer and FinAswer Express programs have operated as originally
intended, providing a full range of services and incentives for virtually all energy
effciency projects in business customer facilities. The performance of the combined
program for 2008 and 2009 when compared to the forecast in the prior application
indicates 83 percent of the savings were achieved for 67 percent of the forecasted
APPLICATION OF ROCKY MOUNTAIN POWER - 8
expenditues. The program's 2009 savings achievement is approximately 40 percent
higher than 2008 savings.
Several factors contribute to steadily increasing paricipation. Increased energy
efficiency messaging and awareness from the residential sector affects business
customers. Selected investments in energy efficiency can improve operating margins in
businesses and may present attractive investments when compared to increased
production capacity projects considered in the recent past.
Idaho schools have increased their focus on energy effciency, parially as the
result of the Idaho Offce of Energy's K -12 assessment program which started in 2009.
Whle the analysis work is being performed by Idaho Office of Energy fuded
contractors, school districts served by Rocky Mountain Power have asked the Company
for some additional analysis services as they prepare to prioritize their projects. The
school analysis phase wil likely be completed during 2010 and the Company expects
some customers wil utilize available utility incentives to assist with the fuding of their
most promising projects.
Completed Energy FinAswer projects increased from 2008 to 2009 and the
pipeline of forecasted projects has also increased. In two other markets, the Company
has increased the availability of prescriptive incentives and improved the Energy
FinAswer incentive offer to better address emerging technologies and align with code
changes, changing market conditions and other utility program offerings. The changes
are expected to improve program paricipation generating greater savings opportties
through the program. These changes, which would require taiff changes, would also be
applicable to the Idaho market but are not explicitly factored into these forecasted
APPLICATION OF ROCKY MOUNTAIN POWER - 9
program expenditures at this time. Taking into consideration this combination of factors,
2010 program expenditures for these programs are forecasted, for the purose of this
Application, to be approximately 30 percent higher than the programs 2009 actu
expenditues.
10. Agricultural Programs
The projected fuding for agricu1ture energy effciency and load control programs
for the period May 1, 2010, through April 30, 2011, is $4.9 milion, an increase of $2.6
milion when compared to the 2009 estimate in Case No. PAC-E-08-01.
The Irrigation Energy Services program has been available since early 2006. As
described in the 2008 anual report, the program administrator was changed in early 2009
through a competitive selection process. The 2009 savings and expenses were 215
percent and 300 percent respectively of the 2008 program savings and expenditues.
Energy savings for the 2008 through 2009 period were 111 percent of the 2008
application forecast and expenditures 85 percent of the 2008 and 2009 forecasts.
Irrgation Energy Services program expenditures were $807,000 in 2009, the 2010
forecast includes $600,000 of program expenses. The 2010 forecast reflects a steady
state operation with costs and savings below 2009 levels, but higher than the costs
incured in 2008.
The 2009 Irrgation Energy Services program is cost effective from a utility cost
stadpoint; however, it did not pass the tota resource cost tests. Two primar factors
contributed to this result: 1) the contribution of non-recuring transition costs associated
with changing program administrators; and 2) customer specific costs associated with
equipment investments that delivered operational efficiencies in addition to energy
APPLICATION OF ROCKY MOUNTAIN POWER - 10
effciency benefits. The simple pre-incentive pay-back for all 2009 projects completed
through the program was 5.7 years; however, seven of these projects had simple
paybacks of between 15 and 20 years. The additional customer costs from these seven
projects had a negative impact on the total resource costs test results from a strictly
electric energy savings perspective. The projects accounted for about 50 percent of the
total customer costs reported by the program and were offset by utility incentives equal to
about 12 percent heavily influencing overall program results. The Company
acknowledges that most customers don't make uneconomic investments; therefore, there
must be additional benefits beyond just electrical savings that compelled this set of
customers to proceed with these projects. For any long payback projects such as those
described above that are eligible for incentives, the curent program administrator wil
tae extra steps to align energy and non-energy benefits with project costs prior to project
close-out and reporting project costs. As a result, this impact on the total resource cost
test is not expected to recur and the program is forecasted to be cost effective under both
the total resource cost and utility cost p~rspectives in 2010.
Several factors contribute to higher overall forecasted program expenses when
compared with prior program delivery, not the least of which is moving beyond nozzle
exchanges to more complex project work. In addition, and in response to grower needs,
the program administrator is providing improved service to irrigation dealers and growers
including faster turaround and increased technical rigor for site work.
The program administrator has analyzed further changes to this program to
increase prescriptive incentives and better align with other programs, including those of
Idaho Power and the Bonnevile Power Administration. Initial estimates of savings and
APPLICATION OF ROCKY MOUNTAIN POWER - 11
costs for an improved program are generally comparable with the forecasted estimates
provided for 2010.
The Irrigation Load Control Credit Rider program has grown significantly since
its inception in 2003 with the greatest growth occurng between 2007 and 2008. The
growth has been fueled by the loss of the regional residential and farm exchange credits
and in addition, beginning in 2008, of the dispatchable control option. Actul
paricipation in 2008 of 211 megawatts and in 2009 of 258 megawatts outpaced the
Company's April 2008 forecast, provided in Case No. PAC-E-08-01, of 150 megawatts
and 200 megawatts respectively. The rapid growth has driven increased complexity in
delivery and costs, some of which were not envisioned and until now not fuly reflected
in prior company forecasts. With the increased complexity and costs additional resource
flexibilty has been gained, grower satisfaction improved, and the program remains one
of the most cost-effective programs in the Company's DSM program portfolio.
In 2008, the full transition from static timer control equipment to two-way
dispatchable technology provided for a more robust and responsive control platform.
While the transition has increased program costs, the resource costs have remained least
cost to alternative supply side capacity resource options. The two-way technology
provides the necessar platform to manage a program the size of the Idaho program,
enhances the network's operational integrity, and reduces grower crop risk. In addition,
it allows for a more coordinated and deliberate dispatch event, allowing the Company to
stagger off and on loads preceding and following the need for the resources, minimizing
distribution system disruptions, improving overall system operations, and reliability. As
previously noted, the initial expectations of the impact of the transition to the two-way
APPLICATION OF ROCKY MOUNTAIN POWER - 12
control technology on program size have been exceeded with 2009 paricipation reaching
258 megawatts, 29 percent more load under management than forecasted during the
Company's February 2008 tariff rider fiing that established the current collection rate of
3.72 percent. Despite the growt in network size and commensurate delivery expenses
the program remains very cost-effective with total cost and utility cost benefit ratios of
5.87 and 1.89 respectively. Ths fiing forecasts additional program growth in 2010 to be
a modest 2-5 megawatts, however, program costs are forecasted to increase from $3.8
milion in 2009 to $4.3 milion in 2010. The increasing costs are the result of several
factors with the most noteworthy being the program costs staing to catch up with the
resource requirements needed to deliver the program. The rapid growth has led to greater
reliance on internal Company resources each year, a situation that, due to staffng
considerations, is not sustainable longer term. Beginning in 2010, a greater reliance on
external resources for the delivery of the program is forecasted. This is necessary to
ensure sustainability in program delivery necessar to rely on the resource in our
integrated resource planing process. In addition to having to outsource more of the
program delivery, several other cost pressures are impacting the 2010 program costs: 1)
market transitions in the digital communcations industr have resulted in the lack of
market support for less expensive forms of data transfers employed in the delivery of the
program in 2008; 2) the recent acquisition of Alltel, the 2009 communications provider,
by Verizon and possibility of communcation conductivity issues resulting from the
change in providers; and 3) greater network operations software expenses associated with
the development of staggered dispatch routines and equipment. For puroses of this
filing, only the forecasted 2010 program costs were used in the adjustment analysis, for
APPLICATION OF ROCKY MOUNTAIN POWER - 13
both 2010 and 2011. Given the uncertinty around outsourcing more of the program in
2011 than that planed for 2010, the Company felt it prudent to wait on the results of a
competitive bid process scheduled in 2010 for program delivery beginning in 2011 before
attempting to assess the likely impact on future program costs and recovery requirements.
As curently forecasted, the 2010 Irrigation Load Control Credit Rider program is
expected to remain highy cost-effective with total cost and utilty cost benefit ratios of
4.67 and 1.65 respectively.
11. Northwest Energy Effciency Alliance (NEEA)
The NEEA program fuding included in this Application is approximately
$467,000 compared to $287,000 for 2009.
The forecasted fuding and estimated savings for Idaho's share of regional market
transformation efforts is based on the NEEA Strategic Plan and 2010-2014 Business
Plan. The plans were developed collaboratively with stakeholders in the region and were
heavily informed by early findings in the Northwest Power and Conservation Council's
work on the DRAT 6th Power Plan suggesting that significant opportity exists in the
region for greater contributions to market transformation efforts. The result is a near
doubling of anual fuding requested by NEEA for the 2010-2014 funding cycle,
compared to the prior two five-year fuding cycles. In addition to the region and NEEA
seeking to increase market transformation related work activity, cost per unt of savings
from NEEA's efforts have increased as the complexity of the work has increased and the
contribution from lighting savings have decreased. As a result, Rocky Mountain Power's
Idaho share of NEE A expenses for 2010 are forecasted at approximately $180,000 higher
APPLICATION OF ROCKY MOUNTAIN POWER - 14
than 2009 and over the entire 2010-2014 fuding cycle to increase from roughly
$1,584,000 (prior fuding cycle of 2005-2009) to $2,903,514, or approximately $264,000
anually. Rocky Mountain Power joined other NEEA staeholders in developing
NEEA's plans and supports this increased activity and fuding leveL.
PROPOSAL OF PROGRAM OPTIONS
12. Rocky Mountain Power is committed to continue to acquire cost-effective
DSM resources. As noted in this Application all of the DSM programs offered by the
Company are cost effective and benefit customers. However, the Company is also
sensitive to the magntude and impact of increasing the Customer Efficiency Service rate
from 3.72 percent to 5.85 percent has on customers. Therefore, if the Commission
determined that increasing Schedule No. 191 to 5.85 percent was not in the public interest
at this time the Company is proposing the potential elimination of one or both of the
following options for Commission consideration:
1) as highlighted in section 11 of this Application the curent five-year NEEA
contract expired at the end of 2009, the 2010-2014 fuding cycle proposes to
increase the average anual fuding from $317,000 to $581,000 a 83 percent
increase; and,
2) section 10 of the Application sumarizes the agricultural programs offered by
the Company representing over 68 percent of all DSM program expenditues
that are collected through Schedule No. 191. The Irrigation Energy Services
program has projected expenditue of $600,000 during 2010.
APPLICATION OF ROCKY MOUNTAIN POWER - 15
The fuding for each of these programs represents approximately 0.4 percent of
retail revenues subject to Schedule No. 191. If the Commission determined to
discontinue both of these programs it would reduce the requested increase from 5.85
percent to 5.02 percent, reducing the anual revenues collected from $8.325 milion to
$7.144 milion.
TARIFFS AND SUPPORTING DOCUMENTATION
13. Attachment 1 to this Application contains Customer Rule 102
implementation information, including the customer notice and the press release.
Attchment 2 contains a preliminary cost effectiveness assessment of 2009 program
performance, a final assessment will be provided to the Commission no later than March
15, 2010. Attchment 3 contains Rocky Mountain Power's 2010 projected program
expenditures and savings, and Attachment 4 contains a sumar of the cost-effective
forecasts for 2010, supporting the proposed Schedule No. 191 collections. Attchment 5
contains Rocky Mountain Power's Table A, which shows the effect across rate schedules
of the proposed Schedule No. 191 rate change and a clean and legislative copy of the
taiff.
MODIFIED PROCEDURE
14. Rocky Mountain Power believes that consideration of the proposals
contained in this Application does not require an evidentiar proceeding, and accordingly
the Company requests that this Application be processed under RP 201 allowing for
consideration of issues under modified procedure, i.e., by written submissions rather than
by an evidentiar hearing.
APPLICATION OF ROCKY MOUNTAIN POWER - 16
SERVICE OF PLEADINGS
15. Communications regarding this Application should be addressed to:
Ted Weston
Rocky Mountain Power
Manager, Idaho Regulatory Affairs
201 South Main Street, Suite 2300
Salt Lake City UT 84111
Telephone: (801) 220-2963
Facsimile: (801) 220-2798
E-mail: ted.weston(ipacificorp.com
Danel E. Solander
Rocky Mountain Power
Senior Counsel
201 South Main Street, Suite 2300
Salt Lake City UT 84111
Telephone: (801) 220-4014
Facsimile: (801) 220-3299
E-mail: danieL.solander(ipacificorp.com
In addition, Rocky Mountan Power respectfuly requests that all data requests
regarding this matter be addressed to:
Bye-mail (preferred):datarequest(ipacificorp.com
By regular mail:
PacifiCorp
Data Request Response Center
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquires also may be directed to Ted Weston at (801) 220-2963.
CONCLUSION
WHEREFORE, Rocky Mountain Power respectfully requests that the
Commission issue an Order under Modified Procedure authorizing the Company to
APPLICATION OF ROCKY MOUNTAIN POWER - 17
increase Tariff Schedule No. 191, Customer Efficiency Services Rate, to 5.85 percent as
described herein effective May 1,2010.
DATED this 25th day of Februar, 2010.
Respectfully submitted,
Mark C. Moench
Daniel E. Solander
Attorneys for PacifiCorp
APPLICATION OF ROCKY MOUNTAIN POWER - 18
zata FEB 25 MilO' Rocky Mountain Power
. . 2èase No. PAC-E-1O-03
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ATTACHMENT 2
Preliminar 2009 DSM Program Cost Effectiveness Assessment
Februar 25, 2010
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201a FEB 2S Af11O' Rocky Mountain Power
. 2àase No. PAC-E-10-03
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ATTACHMENT 3
2010 - DSM Program Budget and Savings Forecast
February 25,2010
Idaho 2010 Demand Side Management Program Budget and Savings Forecasts
Programs 2010-MWH 2010-MW 2010- $
Low Income Weatherization 249 $225,000
Refrigerator Recycling 1,279 $186,500
Home Energy Savings 2,235 $564,000
Alliance 3,146 $298,880
Annual totals - Residential 6,908 $1,274,380
Energy FinAnswer 1,600 $480,000
FinAnswer Express 1,150 $324,000
Irrigation Efficiency 2,369 $600,000
Irrigation Interruptible 261 $4,300,000
Allance 1,770 $168,120
Annual totals - business 6,889 261 $5,872,120
Annual totals - all 13,796 261 $7,146,500
all savings figures are gross and at site
Program Incentives Program delivery Estimated Utilty labor Total
Low Income Weatherization $33,750 $181,450 $9,800 $225,000
Refrigerator Recycling $29,250 $146,000 $11,250 $186,500
Home Energy Savings $395,198 $151,173 $17,750 $564,121
Energy FinAnswer $139,200 $321,600 $19,200 $480,000
FinAnswer Express $92,000 $212,250 $19,750 $324,000
Irrigation Efficiency $292,252 $291,748 $16,000 $600,000
Irrigation Interruptible (a)$-$4,233,200 $66,800 $4,300,000
Annual totals $981,650 $5,537,421 $160,550 $6,679,621
Rocky Mountain Power Program Budget by Major Cost Category
(a) estimated incentives of $7,380,000 are recovered through base rates for this program
lOfO FEB 25 Mf 10: 28 Rocky Mountain Power
Case No. PAC-E-10-03
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ATTACHMENT 4
2010 DSM Portfolio Cost Effectiveness Forecast
February 25,2010
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ZOlû FEB 25 Mi 10: 28 Rocky Mountain Power
Case No. PAC-E-1O-03
UTI
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ATTACHMENT 5
Table A - Rate Impact by Schedule and Revised Schedule No. 191
February 25,2010
TABLE A BY SCHEDULE
ROCKY MOUNTAI POWER
REVISION TO CUSTOMER EFFICIENCY SERVICES RATE ADJUSTMENT
FROM ELECTRIC SALES TO ULTIMTE CONSUMERS
DISTRIUTED BY RATE SCHEDULES IN IDAHO
12 MONTS ENDING DECEMBER 2008
Average Present Schedule 191
Line Present No. of Revenue Present Proposed Net Change
No.Description Sch.Customers MW ($000)($000)($00)%($000)%
(I)(2)(3)(4)(5)(6)(7)(8)(9)0õ
(7)/(5)(9)/(5)
Residential Sales
1 Residential Service 1 40,193 398,783 $36,406 $1,354 $2,130 5,85%$775 2.13%
2 Residential Optional TOD 36 16,601 310,340 $22,920 $853 $1,341 5.85%$488 2.13%
3 Net Metering 135 0 0 $0 $0 $0 0,00%$0 2,13%
4 Unbiled 0 $0
5 Total Residential 56,794 709,122 $59,325 $2,207 $3,471 5,85%$1,264 2,13%
6 Commercial & Industrial
7 General Service - Large Power 6 1,056 297,534 $18,957 $705 $1,109 5,85%$404 2,13%
8 General Svc, - Lg, Power (R&F)6A 250 35,158 $2,433 $91 $142 5,85%$52 2,13%
9 Subtota-Schedule 6 1,306 332,692 $21,390 $796 $1,251 5,85%$456 2.13%
10 General Servce - Med, Voltage 8 0 0 $0 $0 $0 0,00%$0 2.13%
11 General Servce - High Voltage 9 12 105,183 $5,331 $198 $312 5,85%$114 2,13%
12 Irrgation 10 5,294 618,674 $43,253 $1,609 $2,530 5.85%$921 2.13%
13 Comm, & lnd, Space Heating 19 186 7,610 $528 $20 $31 5,85%$11 2,13%
14 General Service 23 6,314 126,659 $10,190 $379 $596 5,85%$217 2,13%
15 General Service (R&F)23A 1,401 17,981 $1,517 $56 $89 5,85%$32 2.13%
16 Trafc Signals 23S 3 7 $1 $0 $0 5,85%$249 2.13%
17 Subtota-Schedule 23 7,717 144,648 11,707 $436 $685
18 General Servce Oponal TOD 35 3 2,115 $143 $5 $8 5,85%$3 2,13%
19 Special Contrct 2 1,384,364 $56,806 $0 $0 0,00%$0 0,00%
20 Special Contrct 1 105,214 $4,255 $0 $0 0,00%$0 0,00%
21 Unbiled 0 $0 $0 $0 0,00%$0
22 Total Commercial & Industrial 14,520 2,700,500 $143,414 $3,064 $4,818 336%$1,754 1.2%
23 Total Commercial & Industrial 14,518 1,210,922 $82,354 $3,064 $4,818 5,85%$1,754 2,13%
(Excluding Special Contracts)
24 Public Street Lighting
25 Securty Area Lighting 7 221 275 $101 $4 $6 5.85%$2 2,13%
26 Securty Area Lighting (R&F)7A 186 131 $52 $2 $3 5,85%$1 2,13%
27 Stret Lighting - Company 11 32 131 $56 $2 $3 5,85%$1 2,13%
28 Street Lighting - Customer 12 297 2,166 $401 $15 $23 5,85%$9 2,13%
29 Traffc Signl Systems 12 25 165 $16 $1 $1 5,85%$0 2,13%
30 Unbiled 0 $0
31 Total Public Street Lighting 761 2,867 $626 $23 $37 5,85%$13 2,08%
32 AGA (Revenue Credit)$540
33 Total Sales to Ultimate Customers 72,075 3,412,490 $203,906 $5,294 $8,325 4,08%$3,031 1.49%=
34 Total Sales to Ultimate Customers 72,073 1,922,912 $142,306 $5,294 $8,325 5,85%$3,031 2.13%=(Excluding Special Contracts & AGA)
~~~~OUNTAIN
I i.P.V.C. No.1
FiSecond Revision of Sheet No. 191
Canceling OrigiBal First Revision of Sheet No. 191
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 191
STATE OF IDAHO
Customer Effciency Services Rate Adjustment
PUROSE: The Customer Efficiency Services Rate Adjustment is designed to recover the costs
incurred by the Company associated with Commission-approved demand-side management expenditures.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bils shall have the following percentage increases applied prior to the application of
electric service Schedule 34.
Schedule 1
Schedule 6
Schedule 6A
Schedule 7
Schedule 7A
Schedule 8
Schedule 9
Schedule 10
Schedule 11
Schedule 12 - Street Lighting
Schedule 12 - Traffic Signal
Schedule 19
Schedule 23
Schedule 23A
Schedule 24
Schedule 35
Schedule 35A
Schedule 36
5.85~%
5.85~%
5.85~%5.85~%5.85~%
5.85~%
5.85~%
5.85~%
5.85~%
5.85~%
5.85~%
5.85~%5.85~%5.85~%
5.85~%
5.85~%
5.85~%5.85~%
Submitted Under Advice Case No. PAC-E-1O-03~
ISSUED: February +425, 201OG&EFFECTIV: May 1, 201OG&
~~~o~OUNTAIN
I.P.U.C. No.1
Second Revision of Sheet No. 191
Canceling First Revision of Sheet No. 191
ROCKY MOUNTAIN POWER
ELECTRC SERVICE SCHEDULE NO. 191
STATE OF IDAHO
Customer Effciency Services Rate Adjustment
PUROSE: The Customer Efficiency Services Rate Adjustment is designed to recover the costs
incurred by the Company associated with Commission-approved demand-side management expenditures.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bils shall have the following percentage increases applied prior to the application of
electric service Schedule 34.
Schedule 1
Schedule 6
Schedule 6A
Schedule 7
Schedule 7A
Schedule 8
Schedule 9
Schedule 10
Schedule 11
Schedule 12 - Street Lighting
Schedule 12 - Traffc Signal
Schedule 19
Schedule 23
Schedule 23A
Schedule 24
Schedule 35
Schedule 35A
Schedule 36
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
5.85%
5.85 %
5.85 %
5.85 %
5.85 %
5.85 %
Submitted Under Advice Case No. PAC-E-IO-03
ISSUED: Februar 25,2010 EFFECTIV: May 1,2010