20141023Sterling Direct.pdf

BEFORE THE :liici: i''r .' :i
?ilrr0il'f ?3 Pi't 2: 58
IDAHO PUBLIC UrlLlrlES coMMlSiiP,}, f,,.,0i,,';,',ir,,,,-
rN THE MATTER OF IDAHO POWER )
coMPANy',S AppLtCATtON TO ) CASE NO. IPC-E-14-18
IMPLEMENT SOLAR INTEGRATION )
RATES AND CHARGES. )
)
)
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DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIG UTILITIES COMMISSION
ocroBER 23, 2014
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O. Please state your name and business address for
the record.
A. My name is Rick Sterling. My busj-ness address
is 472 West Washington Street, Boise, Idaho.
O. By whom are you employed and j-n what capacity?
A. I am employed by the Idaho Public Utilities
Commission as the Engj-neering Supervisor.
a. What is your educational and professional
background?
A. I received a Bachelor of Science degree in Civil
Engineeri-ng from the Unj-versity of Idaho in 1-981 and a
Master of Science degree in Civil Engineering from the
University of Idaho in l-983. I worked for the Idaho
Department of Water Resources Energy Division from 1983 to
L994. rn 1988, I became licensed in Idaho as a registered
professional Civil Engineer. I began worklng at the Idaho
Public Utilities Commission in 1,994. My duties at the
Commission include analysis of a wide variety of electric
and large water utility applications. In addition, I lead
the Engineering Section and supervise a staff of engineers
and utility analysts.
O. What is the purpose of your testimony in this
proceeding?
A. The purpose of my testimony is to discuss Idaho
Power's request to implement solar integration rates and
CASE NO. IPC-E-].4-18
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charges. I discuss the Company's 20l-4 Solar Integration
Study upon which the request is based, ily participation in
and t,he role of the Study's Technical Review Commj_ttee,
and Idaho Power's proposal to apply solar integration
charges as a component of Schedule 87.
O. Do you believe t,here are costs associated with
integration of solar generation resources on Idaho Power, s
system?
A. Yes, I believe there are integration costs
associat,ed with all intermj-ttent resources, including
solar, because they requj-re Idaho Power to j-ncrease the
reserves that must be carried as well as modify how it
dispatches its other resources. The utility strives to
dispatch its resources in an optimum, least cost manner
while sti11 maintaining reliability, and any change in an
optimum dispatch imposes additional costs. In addition,
operating reserves must be provided from other resources
capable of increasing or decreasing dispatchable
generation to accommodate rapid changes in non-
dispatchable solar generatj-on.
a. Why does holding greater operating reserves
impose additional costs on the utility?
A. Any resource that must be held in reserve cannot
be economj-caIIy dispatched. That means that a higher cost
mix of resources must sometimes be util-ized, therefore
CASE NO. IPC-E-14-18
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increasing power supply costs.
A. Doesn't Idaho Power already have the capability
and existing resources to provide the balancing reserves
necessary to integrate intermittent resources such as
solar and wind?
A. Idaho Power certainly already has existing hydro
and thermal generation resources that can j-ntegrate a
substantial amount of intermittent generation. In fact,
there is already approximately 575 MW of Public Utility
Regulatory Policies Act (PURPA) wind generation being
integrated now, and according to Idaho Power, there is
already 50 MW of approved solar contracts in Oregon and
380 MW of new solar generatj-on seeking contracts ln Idaho.
However, ds more intermittent solar and wind
generation is added to the utility's system, increasing
amounts of dispatchable hydro and thermal generation must
be held in reserve, forcing Idaho Power to employ a more
expensive mix of resources to meet Ioad. At some point,
Idaho Power's capacity to integrate intermittent
generation will be exhausted and additional dispatchable
resources may need to be added. In the meantime, existing
resources must simply be held in reserve or dispatched in
a more costly, less than optimum manner.
O. Do you believe it is reasonable that integration
costs associat,ed with solar generation be paid by the
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owners of the solar generation facj-lities, rather than by
ratepayers?
A. Yes, I do. The solar integration charges
proposed to be implemented in this case would be applied
to PURPA Qualifying Facilities 19rs). As required by
PURPA, avoided cost rates are intended to be set in such a
way so that the utility is indifferent as to whether it
purchases power from Ehe QF or obtains the power from
another source, includj-ng its own generation. Regardless
of whether the util-ity obtained the power from another
source or generated the power itself, it would almost
certainly come from a fu11y dispatchable source for which
there would be no associated integration costs. In order
for the utility and its ratepayers to remain indifferent,
costs of integration should rightfully be borne by the
owners of the non-dispatchable resources.
a. Have integration charges been j-ncluded before in
any solar PURPA contracts in ldaho?
A. No, they have not. The Commission has
previously approved two sol-ar PURPA contracEs, buE both
contracts were subsequently terminated. Neither of the
two terminated contracts contained an integration clause.
In Grand View Solar I (Case No. IPC-E-LO-17), the
Commission noted that the contract executed in 201-0 did
not include a solar integration adjustment, but agreed
cAsE NO. rPC-E-14-l-8
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wit.h Staff's comments that insufficient data existed to
calculate an integration adjustment at that time. In a
subsequent 2oll fnterconnecE Solar case (Case Wo. fPC-E-
11-l-0), the Commission acknowledged that. t.here is likely
some 1eve1 of integration costs assocj-ated with all
intermittent resources such as wind and solar and that
such factors should be considered in future power purchase
agreements.
O. Has the Commission made other recent statements
regarding solar integration charges?
A. Yes. In Case No. fPC-E-14-09 Idaho Power f il-ed
a petition requesting that the Commlssion immediately
issue an order temporarily suspending the utility's
obligat,ion to purchase energy from solar-powered QFs
pending the Company's completion of its 2Ol4 Solar
Integration Study. Although the Commission declined to
suspend Idaho Power's obligation, it did "direct Ehe
utility and its counterparties that their negotiat,j-ons in
pursuit of solar contracts using the IRP methodology
should include consideration of a solar integration
chargre." (Order No. 33043 at, 7) . The Commission further
stated "Our guidance to the negotiating parti-es is based
in part on PURPA's requirements that avoided cost rates be
just and reasonable to the utility's ratepayers and in the
public interest. As in the case of wind QFs, utilities
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j-ncur costs when they must integrate intermittent QF
resources into thej-r generation resource stack.,, Id.
Fina11y, the Commission stated, rr...we believe that Idaho
Power's filing has reinforced our previous view that
integration charges should be a part of PPAs, and has
adequately demonstrated that there is a pressJ-ng need to
address the issue of solar integration charges in solar
PPAs under consideration by negotiating parties. " Id. at
8.
O. Do you believe that t,he Commission's statements
in Case No. IPC-E-14-09 which you just discussed are
relevant in this case?
A. Yes, I do. I think the Commission's prior
statements are an indication that it believes there are
j-ntegration costs associated with solar generation and
that they should be included in all new solar contracts.
Now that Idaho Power has completed its 201,4 Solar
Integration Study and quantified the costs, solar
integration charges can be included in contracts and not
be entirely subject to negotiation.
O. Have you reviewed the 2Ol4 So1ar Integrat.ion
Study and Report submitt.ed by Idaho Power on June 17, 20L4
in Case No. IPC*E-7-4-09, and presented as Exhibit No. l- to
the Dj-rect Testimony of Philip DeVol in support of the
Company's Application in this case?
CASE NO. IPC-E-14-18
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A. Yes, I have reviewed the report.
O. Do you believe methods and model used by Idaho
Power to estimate solar integration costs are reasonable?
A. Yes, I do. For its study, Idaho Power utilized
a production cost simulation model which it developed in-
house that dispatches the Company's own resources whil-e
also acceptj-ng intermittent solar and wind generati-on.
Except for the introduction of solar generation, it is my
understanding that the model has been adapted from the
same model used for the Company's wind integration
studies.
a. Do you believe that the scenarios considered in
the Solar Int,egration Study were reasonable?
A. Yes, I do. Four buiLd-out scenarios were
studied ranging from l-00 to 700 Mw, with development
dispersed amongst six sites throughout Idaho Power's
service territory. The scenarj-os were developed in
consultation with the Technical Review Committee, based
upon the committee members' and Idaho Power's experience
and expectations of future solar development. Because
several hundred megawatts of development have already been
proposed at varj-ous locations, speculation about 1ike1y
development scenarios was minimal.
O. Idaho Power's 2Ol4 Solar Integration Study
Report presents int.egration costs as both "average
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integration cost.s per MWh" and as .,incremental J-ntegration
costs per MWh." Can you explain the difference between
the two?
A. "Average integration costs per MWh" is intended
to reflect the costs that would be incurred if all costs
at each penetration leve1 were spread equally across all
MWhs of solar generation; in other words, the costs that
would be attributable to all MWHs if costs were assigned
equally to all MWhs. Incremental integration cost per MWh
is intended to reflect costs attributable to each
increment of solar generation. Incremental integratj-on
costs assume early projects are assessed lower integration
costs and later projects higher costs to reflect the
higher cost of integratj-on as larger amounts of solar are
added to the system.
a. Which set of costs, average or incremental, do
you believe should be applied if solar integration costs
are approved by the Commission?
A. Under an average approach, costs would be
j-mposed equally to all solar generation. Under an
incremental approach, increasingly higher integration
costs would be charged as solar generation increased.
Because each additional increment of generation caused
higher integration costs, new generation would pay higher
integration charges. I support the incremental approach
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proposed by Idaho Power for two primary reasons. First, I
believe it is fair for the earliest solar projects to be
the beneficiaries of lower integration costs and to not
have to share in covering higher costs caused by later
projects. Second, I think an average approach would be
very difficult to administer because it would Iikely
require charges for existing contracts to be periodically
increased so that all i-ntegration costs could be fu1Iy
recovered by the utility.
O. Did you participate in the Technical Review
Committee?
A. Yes, I did.
O. What role did you play on t,he Technical Review
Committee?
A. I was considered an "observer" rather than a
fuI1 member of the review committee. As an observer, I
was invited to attend all committee meetings, ask
questions, participate fuI1y in discussj-ons, and offer
suggestions. The only thing I did not do was comment on
the draft report. I believed that it would not be
necessary or appropriate to comment on the draft report
knowing that I would like1y be responsible for submitting
comments or testimony at a later date in a formal case.
Two staff members from the Oregon Public Utility
Commission also participated as observers, although they
CASE NO. IPC-E-14-18
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did not. attend any committee meetings in person or
acti-ve1y participate in discussions.
O. Do you believe the Technj-ca1 Review Committee
was useful?
A. Yes, I believe it was very useful. Each of the
Technical Revj-ew Committee members offered expertise and
different points of view that helped influence how Idaho
Power performed the study.
O. Do you believe Idaho Power seriously listened t.o
members of the Techni-ca1 Review Committee?
A. Yes, f do. I believe many decisions Idaho Power
made about assumptions and methods of analysis were based
in large part on input provided by the committee.
Committee members were also instrumental in advising the
Company on sources of data, ds well as in constructing
realistic scenarios for the size and locations of possible
future development.
O. Can you give an example?
A. Yes, I can. At one of the first committee
meetlngs, I raised questions about whether solar
irradiance data collected at a single point, would be
representative over a much broader area encompassed by a
typical large photovoltaic project, due to cloud cover
potentially affecting only porti-ons of the project but not
others. This prompted another committee member to suggest
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Idaho Power investigate "wavelet variability modellng',
that was being researched at other places in the country.
After investigating the research, Idaho Power adapted and
incorporated the modeling techniques for its own study.
By using wavelet variability modeling, the impacts of
partial cl-oud cover were moderated, indicating fewer
reserves were needed for integrating solar.
O. Do you believe members of the Technical Review
Commj-ttee had adequate opportunity to comment?
A. Yes, at least initially. In the early stages of
the process, the Technical Review Committee met three
times as the study progressed. One publj-c workshop was
also he1d. However, in the final production cost modeling
stage of the study, and once the draft report was
prepared, Idaho Power greatly expedited the process.
fdaho Power maintained that there was an urgency to
complete the study because the Company was being inundated
with requests for new solar projects and it wanted to be
able to address integration costs in any new contracts
that might emerge. The Technj-ca1 Review Committee met
twice over about a two week period, just prior to the
draft report being prepared. While Technical Review
Committee members could sti11 provide input and ask
questions, they sometj-mes had to do it using email or
phone caIls. fn addition, the two week time period
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allotted for review of the draft report prior to
submitting it to the Commission seemed quiEe short.
O. Do you believe there is a need for additional
study of solar integration by Idaho Power in the future?
A. Yes, f do. The Technical Review Committee
raised numerous issues that I believe would be worthwhile
to investigate further in subsequent integration studies.
Many of those issues have been identified in the Solar
Study. I see the 20L4 Solar Integration Study as a
reasonable first step, but believe further improvements to
future st.udies are possible. In the meantime, however, I
believe the 2Ol4 Solar Study is a reasonable basis for the
solar integration charges proposed in Schedule 87.
O. Idaho Power proposes to apply the results of its
solar integration study as tariff-based charges applied to
all energy generated by PURPA Qualifying Facilities, i.€.,
Schedule 87. Do you agree with the tariff approach
proposed by the Company?
A. Yes. Idaho Power's approach as proposed in
Schedule 87 j-s identical to the approach proposed for wind
integration charges. Schedule 87 for wind integration
charges was recently approved by the Commission in Order
No. 33150 issued on Oct.ober 10, 201-4.
O. Idaho Power's proposed solar integration tariff
includes options for the charges to be either levelized or
CASE NO. IPC-E-14-181o/23/t4 srERLrNG, R. (Di) 1-2
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non-Ieve1ized. Do you agree that both options should be
offered?
A. Yes, both levelized and non-level-ized avoided
cost rates are offered, and both are also provided for
wind i-ntegration charges. To be consj-stent, Ieve1lzed and
non-levelized options should also be offered for solar
integration charges.
O. Have the lntegration charges been properly
levelized in your opinion?
A. Although Idaho Power has correctly levelized the
charges mathematically, I prefer that the discount rate
used to perform the levelization be the same as the
discount rate use in the SAR modeI. In addition, in
recently approving wind integration charges for Idaho
Power (See Order No. 33150), the Commission accepted
Staff's recommendation to use the same discount rate for
levelizing wind integration charges as is used in the SAR
mode1. For consistency sake, I believe the same discount
rate should be used for levelization of solar integration
charges, wind i-ntegrati-on charges, and avoided cost rates
for PURPA projects. That discount rate is currently 8.1-8
percent.. It represents Idaho Power's weighted cost of
capital from its last litigated general rate case, IPC-E-
08-10, Order No. 30722.
O. Have you prepared an exhibit showing what the
CASE NO. IPC-E-14-18
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levelized solar integration charges would be if an 8.18
percent. discount rate were used?
A. Yes, those integration charges are attached as
Exhibit No. 101.
O. Does changing the discount rate have a big
impact on the levelized solar integration charges?
A. No, the difference is very smalI, in part,
because the proposed integration charges are relatj-veIy
Iow. For example, for a penetration l-evel of 501-500 MW
and a 20]-4 online date, the difference is a decrease of
$0.06 per MWh. Despite the small differences, however,
Staff believes consistency throughout the levellzatlon
process for both integration charges and avoj-ded cost
rates is J-mportant and helps minimize uncertainty.
O. Do you believe it is reasonable to impose solar
integration charges now on QFs, knowing it is likeIy that
J-ntegrati-on operational practices and technology will
i-mprove in the future?
A. Yes, I believe it, is reasonable. No one can
rea11y be certain how or when technology might change.
For example, energy st,orage technology will 1ikely improve
and costs are bound to come down, but it is not possible
to know if that w111 happen soon or many years in the
future. Similarly, operat,ional practices and market
changes may develop, making integration of intermittent
CASE NO. IPC-E-14-18
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generat,ion easier and cheaper. At t,he same time, however,
the penetration of intermittent generation, particularly
solar, is 1ike1y to increase rapidly, presenting even
great,er integration challenges. f believe that in the
same way we must make our best effort to estimate avoided
cost rates 20 or more years int,o the future, that we must
also do the same to estimate integration costs.
a. How do you suggest that Idaho Power accommodate
changes to solar integration charges going forward?
A. As solar integration costs change in the future
and based on updated integration studies, I recommend that
Idaho Power make application to the Commission for changes
to Schedule 87 , just as it does for its other tariffs.
Under Idaho Power's proposal, however, the integration
charges that are in effect at the time a contract is
signed will remain unchanged for the durat.ion of the
contract. The new, revj-sed integration charges will only
apply to new contracts.
O. Idaho Power recently received approval in Order
No. 33L50 for a wind integration tariff. Is the Company's
proposed solar i-ntegration tariff similar?
A. Yes, Idaho Power proposes to incorporate both
wind and solar integration charges in Schedule 87. The
format and application of the solar integration charges
would be identical to that of the approved wind
CASE NO. IPC-E- ]-4 - 18
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integration charges. The only difference would be in the
numbers t.hemselves.
O. Do you believe it is J-mport,ant to implement a
solar integration charge as soon as possible, or should
the Commission wait until there are actual solar
generat.ion facilities on Idaho Power's system?
A. I belj-eve solar integration charges should be
implemented as soon as possible, before there are many
solar facilities operating. Idaho Power has recently
signed six PURPA contracts for 60 MW in Oregon. There are
currenLly two proposed large solar PURPA contracts j-n
Idaho pendlng before the Commission that contain negotiated
provisions for integration charges. One contract is for
an 80 MW facility and the other j-s for a 40 MW facility.
In addition, Idaho Power is currently seeking approval of
11 PURPA solar contracts comprisj-ng 281 MW of capacity,
each of which contaj-n integrat.ion charges negotiated
pursuant to the Commission's directive in Order No. 33043.
The negotiated rates are similar to those in the proposed
Schedule 87. The longer we wait. before imposing
integration costs on intermittent generators, the more
integration cost will be borne by ratepayers.
a. What is your recommendation in this case?
A. I recommend that the Commission issue an order
adopting solar integratJ-on charges as proposed by Idaho
CASE NO. IPC-E-14-18
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Power, with the exception that the levelized solar
integration charges be computed using the same discount
rates used to levelize the utility's wind integration
charges and to levelize avoided cost rates in the SAR
methodology.
O. Does thls conclude your direct testimony in this
proceeding?
A. Yes, it does.
CASE NO. IPC-E-14-18to/23/L4
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0 - 100 MW Solar Capacity Penetration Level
LEVELIZED
ON-LINE YEAR
20 YEAR
CONTRACT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
0.54
0.56
0.58
0.59
0.61
0.63
NON.LEVELIZED
CONTRACT
YEAR
NON.
LEVELIZED
RATES
2014
2015
2016
2017
2018
2A19
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
0.43
0.44
0.46
0.47
0.48
0.50
0.51
0.53
0.54
0.56
0.58
0.60
0.61
0.63
0.65
0.67
0.69
0.71
0.73
0.75
0.78
0.80
0.82
0.85
0.87
0.90
Exhibit No. l0l
rPC-E-14-18
R. Sterling, Staff
l0l23ll4 Page I of 7
101 - 200 MW Solar Capacity Penetration Leve!
LEVELIZED
ON-LINE YEAR
20 YEAR
CONTMCT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
201 I
1.49
1.53
1.58
1.63
1.68
1.73
NON.LEVELIZED
CONTMCT
YEAR
NON-
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
1.18
1.22
1.25
1.29
1.33
1.37
1.41
1.45
1.50
1.54
1.59
1.63
1.68
1.73
1.79
1.84
1.89
1.95
2.01
2.07
2.',|3
2.20
2.26
2.33
2.40
2.47
ExhibitNo. 101
IPC-E-14-18
R. Sterling, Staff
l0l23ll4 Page 2 of 7
201 - 300 MW Solar Capacity Penetration Level
LEVELIZED
ON-LINE YEAR
20 YEAR
CONTRACT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
2.32
2.39
2.46
2.54
2.61
2.69
NON.LEVELIZED
CONTRACT
YEAR
NON-
LEVELIZED
RATES
2014
2015
2016
20't7
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
1.84
1.89
1.95
2.01
2.07
2.13
2.20
2.26
2.33
2.40
2.47
2.55
2.62
2.70
2.78
2.87
2.95
3.04
3.13
3.23
3.32
3.42
3.52
3.63
3.74
3.85
ExhibitNo. 101
IPC-E-14-18
R. Sterling, Staff
l0l23ll4 Page 3 of 7
301 - 400 MW Solar Capacity Penetration Level
LEVELIZED
ON.LINE YEAR
20 YEAR
CONTRACT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
3.12
3.22
3.32
3.41
3.52
3.62
NON.LEVELIZED
CONTMCT
YEAR
NON.
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2.48
2.55
2.63
2.71
2.79
2.87
2.96
3.05
3.14
3.23
3.33
3.43
3.53
3.64
3.75
3.86
3.97
4.09
4.22
4.34
4.47
4.61
4.75
4.89
5.03
5.19
Exhibit No. 101
[PC-E-14-18
R. Sterling, Staff
l0l23l14 Page 4 of 7
401 - 500 MW Solar Capacity Penetration Level
LEVELIZED
ON-LINE YEAR
20 YEAR
CONTMCT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
3.94
4.06
4.18
4.31
4.44
4.57
NON.LEVELIZED
CONTRACT
YEAR
NON-
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
3.12
3.22
3.31
3.41
3.52
3.62
3.73
3.84
3.96
4.08
4.20
4.32
4.45
4.59
4.72
4.87
5.0'1
5.16
5.32
5.48
5.64
5.81
5.98
6.16
6.35
6.54
Exhibit No. 101
IPC-E-14-18
R. Sterling, Staff
l0l23ll4 Page 5 of 7
50{ - 600 MW Solar Capacity Penetration Level
LEVELIZED
ON.LINE YEAR
20 YEAR
CONTRACT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
4.76
4.91
5.05
5.21
5.36
5.52
NON.LEVELIZED
CONTRACT
YEAR
NON-
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2425
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
3.78
3.89
4.01
4.13
4.25
4.38
4.51
4.64
4.78
4.93
5.07
5.23
5.38
5.55
5.71
5.88
6.06
6.24
6.43
6.62
6.82
7.02
7.24
7.45
7.68
7.91
Exhibit No. 101
IPC-E-14-18
R. Sterling, Staff
L0l23ll4 Page 6 of 7
601 - 700 MW Solar Capacity Penetration Level
LEVELIZED
ON-LINE YEAR
20 YEAR
CONTRACT
TERM
LEVELIZED
RATES
2014
2015
2016
2017
2018
2019
5.54
5.71
5.88
6.06
6.24
6.43
NON.LEVELIZED
CONTRACT
YEAR
NON.
LEVELIZED
RATES
2014
2015
2016
2017
2018
20't9
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
4.39
4.53
4.66
4.80
4.95
5.09
5.25
5.40
5.57
5.73
5.91
6.08
6.26
6.45
6.65
6.85
7.05
7.26
7.48
7.70
7.94
8.17
8.42
8.67
8.93
9.20
Exhibit No. l0l
IPC-E-14-18
R. Sterling, Staff
l0l23ll4 PageT of 7
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 23'd DAY OF OCTOBER 2014,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN
CASE NO. IPC-E.14.I8, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
DONOVAN E WALKER
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-mail : dwalker@ idahopower.com
[e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
7IO N 6TH STREET
BOISE ID 83702
E-mail: [e-mail]
DEAN J MILLER
McDEVITT & MILLER LLP
420 W BANNOCK ST
BOISE ID 83702
E-mail: [e-mail]
MICHAEL J YOUNGBLOOD
GREG SAID
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail: [e-mail]
[e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 8370I
E-mail: [e-mail]
MATT VESPA
SIERRA CLUB
85 SECOND STREET 2ND FL
SAN FRANCISCO CA 94105
E-mail : matt. vespa@ sierraclub.org
CERTIFICATE OF SERVICE