20140904Supplementary Comments.pdf

Teresa A. Hill
ISB No. 6175
K&L Gates LLP
One Columbia St. Suite 1900
Portland, OR 97258
Telephone: [phone]
Fa"r: [phone]
Attorneyfor Renewable Northwest and American Wind Energt Association
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
F.ECItVl:i
?fftt StP -\ PH h: 5tr
uTIJftiS oo*tiriSsioi;
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY TO UPDATE ITS WIND
INTEGRATION RATES AND
CHARGES.
) Case No. IPC-E-13-22
) SUPPLEMENTARY COMMENTS
) oFAWEAAND
) RENEWABLE NORTHWEST
)
I. INTRODUCTION
Purstrant to Idaho Public Utilities Commission ("IPUC" or "Commission") Rule of
Procedure 203 and the Notice of Amended Schedule issued on July 15,2)l4,the American
Wind Energy Association ("AWEA") and Renewable Northwestl hereby file these
Supplementary Comments on Idaho Power Company's ("Idaho Power" or the 'oCompany")
November 29,2013 Application to Update Wind Integration Rates and Charges (the
"Application"). Using the Company's 2013 Wind Integration Study (*2013 Study") as a basis
for the proposed rates, the Application seeks to increase the wind integration rates and charges
applicable to quali$ing facilities ("QFs") under the Public Utility Regulatory Policies Act of
1978 ("PURPA").2
I Following the commencement of this proceeding, in recognition of the organization's twentieth
anniversary, Renewable Northwest Project changed its name to "Renewable Northwest."
2 In the Matter of the Application of ldaln Power Company to Update its Wind Integration Rates and
Chorges, Case No. IPC-E-13-22, Application at Part IV (Nov. 29,2013).
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
As discussed in these Supplementary Comments, the majority of the costs identified in
the 2013 Study are not "wind integration costs," but rather are costs associated with remarketing
must-take PURPA energy when the utility is surplus on energy; these costs should be included in
the Company's avoided cost methodology. A true "wind integration study" would not use the
methodologies employed in the Company's 2013 Study and would instead focus on the within-
hour balancing needs of the net load and wind variability. Accordingly, the 2013 Study should
not be used as a basis for determining wind integration costs applicable to wind QFs, and the
Company should instead use the 2007 Wind Integration Study or a revised study for this purpose.
After conducting such a study, to the extent that Idaho Power finds that there are additional costs
associated with must-take PURPA wind that are incremental to the integration costs identified in
a proper study, those costs should be captured in the Company's avoided cost methodology.
If the Commission nonetheless accepts the 2013 Study as the basis for wind integration
charges applicable to wind QFs under PURPA, at a minimum, the Commission should clarifr
that (l) it is accepting the 2013 Study without accepting the underlying methodologies; (2)the
wind integration charges would not be applicable to a wind generator transmission customer
transferring its energy outside of the Idaho Power Balancing Authority Area ("BA.A"); and (3)
the wind integration charges would not be used as the basis for wind integration charges in a
subsequent Integrated Resource Plan ("IRP") for purposes of evaluating different energy
resources to serve an identified energy need on Idaho Power's system.
II. COMMENTS
1. The Majority of the Costs Identified by ldaho Power Are Not 6'Wind
Integration Costs."
The majority of the costs identified in the Company's 2013 Study and Application are not
properly characterized as "wind integration costs." Indeed, the 2013 Study-which forms the
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
basis for the costs proposed in the Application-uses a methodology that is wholly inconsistent
with best practices in wind integration analysis; these methodological flaws are discussed in
Section 3 below. In its Reply Comments, Idaho Power responds to criticisms of its study
methodology by arguing that standard industry approaches to wind integration studies "fail[] to
take into account Idaho Power's own specific and real-world operation of its system."3 lndeed,
all power systems are unique, and specific circumstances should be taken into account when
analyzingsystem costs. However, unique circumstances on a given system do not warrant
abandonment of standard statistical analysis and industry standards on wind integration analysis.
Moreover, we disagree that the system circumstances described by Idaho Power translate
to costs that are inherently affributable to the costs of integrating wind energy. As Idaho Power
explains, "the fact that all but 101 MW of the 678 MW of wind on Idaho Power's system is
PURPA generation makes a significant difference because the Company does not have the
operational flexibility with PURPA generation that it may have (or another utility may have) if
its wind generation is non-PURPA."4 This quote from Idaho Power's Reply Comments
underscores that the costs the Company identifies as o'wind integration costs" are the costs of
remarketing must-take PURPA energy when the utility is surplus on energy. Idaho Power's
acknowledgement that the situation is different for non-PURPA wind further evidences that the
majority of the costs at issue here are not o'wind integration costs." In order to untangle these
issues, Idaho Power should first conduct a proper wind integration study consistent with its 2007
Wind Integration Study methodology. After conducting such a study, to the extent that Idaho
Power believes there are additional costs associated with must-take PURPA wind that are
' Idaho Power Reply Comments at I l.4Id.
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
incremental to the integration costs identified in a proper study, those costs should be captured
through the Company's avoided cost methodology.
2. The Majority of the 6.Integration Costs" Identified by Idaho Power Belong in
its Avoided Cost Methodolory.
The majority of the costs identified by Idaho Power's 2013 Study should be included in
the Company's avoided cost methodology. In response to our data request to list the factors that
go into the Company's avoided cost calculation under the IRP methodology, Idaho Power
responded that the methodology "utilizes rhe hourly generation profile of the proposed qualifying
facility ('QF') project in conjunction with the AURORA model to perform a production cost
simulation for the purpose of determining the highest displaceable, or avoidable, incremental
cost incurred during each hour of a QF's proposed contract term."S In other words, the avoided
cost methodology already produces an hourly forecast, and an hourly avoided cost value, for
every MWh of energy integrated into Idaho Power's system for the life of the project. There is
no evidence to suggest-and the Company has not made the case-that the AURORA
production cost model's hour-by-hour avoided cost calculation does not already capture the costs
that Idaho Power characterizes as day-ahead forecasting error costs in the 2013 Study. Idaho
Power's treatment of these day-ahead costs in its 2013 Study methodology is incorrect from a
wind integration perspective (as discussed further in Section 3), but in the context of excess
must-take PURPA energy, we understand that Idaho Power may have difficulty remarketing
surplus PURPA energy on a day-ahead basis. If the Company believes the AURORA model
does not capture all the costs associated with excess must-take PURPA energy when the utility is
surplus, it should reexamine and adjust the avoided cost methodology.
5ldaho Power Response to Question 2 of Renewable Northwest and AWEA's Second Data Request
(emphasis added).
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
When asked how the avoided cost methodology accounts for instances where Idaho
Power is surplus on energy and must remarket the PURPA energy, the Company replied,
"[w]hen the system is surplus on energy in a given hour for the AURORA simulation, the
avoided cost is the cost of the highest cost displaceable resource that is serving load."6 However,
with a situation like the one Idaho Power faces, where it must take PURPA generation even
when it is surplus on energy, the Company is in fact remarketing that energy instead of backing
down the "highest cost displaceable resource that is serving load." Idaho Power's response
appears to identify an inconsistency with how the av<lided cost methodology treats must-take
resources during surplus conditions. Under these circumstances, it would appear that the value
of the PURPA energy is not the "avoided cost" of the "highest cost displaceable resource that is
serving load," but rather a value more closely tied to the surplus energy market at that moment.
It appears to us that there is a tension between the IRP avoided cost methodology and the
real-world circumstances Idaho Power faces with having must-take PURPA energy on its system
under surplus energy conditions. Idaho Power's comments and data responses illustrate this
tension. For example, in one data response, the Company recognizes that, "[a]ny transactional or
operational costs incurred when moving IPURPA] energy to the market reduces the economic
value of PURPA energy [and] [v]ariable energy resources further reduce the economic value of
the energy because of their inherit variability and the resultant operational costs to remove that
variability to market the product as a firm energy product."T Flowever, Idaho Power does not
explicitly identify the shortcomings of the IRP methodology in failing to capture some of these
costs. Instead, another Idaho Power data response cites to a Commission ruling stating that the
u Idaho Power Response to Question 3 of Renewable Northwest and AWEA's Second Data Request.
' Idaho Power Response to Question 4 of Renewable Northwest and AWEA's Second Data Request.
IPC-E-13-22 - September 4,2014 Supplementary Comrnents of AWEA and Renewable Northwest
Company's revised avoided cost methodology "properly focus[es] the determination of avoided
costs on incremental costs, not solely on the value of potential market sales."8
Taken together, Idaho Power's statements point to an unintended consequence of the
decision in Commission Order No. 32697 to move from an avoided cost methodology based on
making surplus sales at future market prices (i.e., a "two-run simulation") to one based on the
highest displaceable incremental cost (i.e., a "single-run simulation"). Rather than working
through those issues, the Company is attempting to move what are properly components of the
avoided cost calculation into a new "integtation charge." While we sympathize with the
Company's situation, we object to the characteization of its 2013 Study methodology and
associated costs as a "wind integration study" that isolates and identifies "wind integration
costs." Rather, as demonstrated by Idaho Power's own data responses, the costs identified in its
2013 Study are costs associated with must-take PURPA energy under surplus energy conditions,
not wind integration costs more broadly speaking.
In order to accurately assess the value and cost of PURPA wind on Idaho Power's
system, the avoided cost methodology and the integration cost methodology must be considered
in tandem, with an eye toward avoiding any overlap or inconsistencies between the two
methodologies. Until Idaho Power can conduct a more holistic analysis of the relationship
between its calculation of avoided costs and "integration costs," the Commission should direct
the Company to use its2007 Wind Integration Study (with updated numbers) as the basis for
determining wind integration costs.
I Id.
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
3. A True \ilind Integration Study Would Not Contain the Methodologies Used
in the Company's 2013 Study
As discussed here and in our July 2,2014 comments in this proceeding, the Company's
2013 Study contains significant methodological flaws. The primary shortcomings of the 2013
Study are that it (l) uses the day-ahead wind forecast error instead of the hour-ahead forecast
error in calculating the reserve requirement for wind; and (2) calculates reserve requirements
based on the outdated assumption that reserves balance wind variability on a stand-alone basis
instead of the standard operating practice of balancing the deviations of net load (load minus
wind and other generation).
In response to our opening comments identifying the methodological flaws in the 2013
Study, Idaho Power's Reply Comments claim that the universal statistical and economic
principles that underlie wind integration studies for other areas do not apply to Idaho Power.e
We disagree. While any utility's unique circumstances must be considered when designing a
wind integration study, those circumstances do not change the fundamental principles of
statistics and utility economics. As illustrated in the following chart, Idaho Power's proposed
reserye needs and wind integration costs are extreme outliers across all utilities, even among
other power systems in the unorganized, bilateral markets of the West:I0
'Idaho Power Reply Comments at I l.
'o Ryan Wiser and Mark Bolinger, 2013 Wind Technologies Market Report at 70 (USDOE Aug. 2Ol4),
ovailable ar http://emp.lbl.gov/sites/alllfiles/201 3_Wind-Technologies-Market Report_Final3 .pdf.
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
s20 ,
i
$18 ,
20% 30% 48i/o 50Vo 60%
Wnd Penetration (Capacfu Basis)
***APS t2007)
-+-Avista (2087)* BPA{2CIffi} [alr BPA{2011} [al
.) BPA {2013}* CARPSt2006)lbl
I ERCOT (2012)
.) EWTS (2010)
+ldaho Porer {2007)
"-**ldaho Potrcr{2012)
..Ir.MN-MISO {2006) [ctx Nebraska (2010)
r NorthWestem (2012)
x Pacificorp {2005)* Paclficorp (2007)
,.+X*PacifiCorp (2010)
r PacifCorp (2t)12)
I Por$and GE (2011)
* Porfiand GE (2013]
{,.Puget Sound Ermrgy l2W7)
.r SPP-SERG {2011}
-We
Energies (2003)
* Xcel-MNDOC (2004)
..pXcel-PgQo (2([6)--i + Xcel-PSCo(2008)
70% -.qp*lssl-PSCo (2011) IdI
o XceLUWIG t2003)
$16
$ cr+
=t?fi $12c,(J
E'* sro
Lg,(l)
E
$8
1ffy'o
il
ffi6
$4
$2
$0
Idaho Power's claim that it cannot use netting and more up-to-date forecasts is
unsubstantiated. Netting different sources of variability and using the most up-to-date forecasts
for those sources of variability have been the cornerstones of reliable and efficient operations for
all electric utilities for nearly a century. In fact, Idaho Power's Reply Comments acknowledge
that it updates day-ahead load forecast information as it moves closer to real-time, allowing day-
ahead load forecast error to be "addressed through the hour-by-hour management in real time
described by AWEA/RNW in their Comments."rr The same principle that makes it efficient for
" Idaho Power Reply Comments at 13. ("NREL also importantly notes that significant day-ahead load
forecast erors are often auto correlated, reflecting a tendency for day-ahead load forecast errors to persist
in magnitude and direction throughout the day. Because of this tendency, day-ahead load forecast errors
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
Idaho Power to address load forecast errors through hour-by-hour management-the fact that
forecast error is reduced as one moves closer to real-time-also applies to wind forecast elTor.
This fact is also acknowledged in Idaho Power's Reply Comments: "AWEA/RNW correctly
note in their Comments that wind energy forecast error is greatly reduced as forecast lead time is
reduced."l2 If Idaho Power is able to use "hour-by-hour management" to more efficiently
accommodate load forecast error, it can also use hour-by-hour management to more efficiently
accommodate wind forecast enor. Idaho Power has not provided any analysis to support its
assertion that market or other barriers make it impossible to use hour-by-hour management to
better accommodate wind uncertainty.
The universal consensus of the published technical literature is that day-ahead wind
forecast error has a small impact on power system costs, as updated forecasts are used for the
economic dispatch process. In fact, the NREL paper that Idaho Power cites in its Reply
Comments as an authority on how wind and load forecast errors are accommodated concisely
makes this exact point:
It is important to note that the [wind forecast] error shown is at the
day-ahead timescale, and so only impacts unit commitment
decisions. Updated forecasts may be incorporated into the
economic dispatch process and could eliminate or reduce the error
before the dispatch timeframe. The only possible cost then
associated with the error would be the difference between
supplying that energy with a mid-merit unit that may need to be
started and a baseload unit that might have otherwise supplied the
required energy.[13]
Notwithstanding Idaho Power's citing of this paper, the Company's 2013 Study uses a day-ahead
forecast error assumption in a manner that drives up the costs of integration considerably. The
are more readily addressed through the hour-by-hour management in real time described by AWEA/RNW
in their Comments.")t' Id. at lz.
13 Bri-Mathias Hodge, et al., AComparison of Wind Power and Load Forecasting Error Distributions at
5, (USDOE May 2012), wailable ar http://www.nrel.gov/docs/*l2ostii54384.pdf.
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
Company's methodology drives up the costs in two ways: (1) bV driving up the need for
reserves through the day-ahead forecast assumption (instead of using an hour-ahead assumption);
and (2) by driving up the cost of providing this inflated amount of reserves by requiring
expensive, fast-acting reserves instead of relying upon less-expensive unit-commitment decisions
and the hour-by-hour economic dispatch process.'4 Thus, by setting the reserve requirement
based on day-ahead forecast error but then requiring the use ofexpensive fast-acting reserves to
meet that reserye need, Idaho Power is having it both ways in driving up the calculated cost of
providing reserves. Idaho Power needs to either (1) allow lower cost options to be used to
address day-ahead forecast erors; or (2) acknowledge that the fast-acting reserves it is charging
for are only truly needed for deviations that occur closer to real-time, and that forecast error at a
time period closer to real-time, such as hour-ahead forecast error, is the appropriate metric for
setting the need for those reserves.
With respect to netting, Idaho Power's argument that it cannot net wind variability and
forecast error with other sources of variability and uncertainty is not compelling. In its Reply
Comments, Idaho Power asserts that "[t]he challenges in forecasting wind and load for day-
ahead unit commitment are considerably different, requiring the system to treat differently the
possibility of errors in forecasting these two elements of the load and resource balance.
Moreover, the different treatments necessary for load and wind make impractical the netting
advocated by AWEA/RNW in the analysis of errors for load and wind."'s Ho*erer, Idaho
Power does not provide any evidence to support this assertion.
'o See, e.g.,2013 Study at l6 ("As a consequence of the high operating costs, the simple-cycle turbines
have been historically operated primarily in response to peak demand events and have seldom been
dispatched to provide operating reserves."); Direct Testimony of Philip B. DeVol at 7 ('Natural gas units
can respond to changes in wind generation, but they have to be operating to do so.").
" Idaho Power Reply Comments at 13.
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
The netting of different sources of variabilif and uncertainty, including loads and
generators with very different types of variability and uncertainty, has been a cornerstone of
efficient utility operations for more than a century. In fact, the efficiencies realized through this
netting is one of the primary reasons why in the late 19ft Century, the power industry moved to
large integrated power systems instead of coupling individual generators with individual loads.
Idaho Power and other utilities already integrate hundreds of thousands of different loads on a
daily basis, each with unique properties for variability and uncertainty
Statistical techniques readily allow grid operators to determine the optimal reserve levels
needed to accommodate the combined variability and uncertainty of all loads and generation on
the power system; this same principle applies when wind generation is added to the power
system. For example, while conventional generator output deviations and large industrial loads
may exhibit a large amount of variability from second-to-second that are largely independent of
the weather, yet lighting and air conditioning and heating loads may experience more gradual
changes over time that are largely dependent on the weather, grid operators are able to
statistically combine those sotrces of variability and uncertainty to set an optimal level of
reserves that efficiently manages the total variability and uncertainty of all factors.
In referencing the NREL paper, Idaho Power has acknowledged that wind forecast error
has the same type of normal distribution pattern that characterizes load forecast error, albeit with
a slightly different normal distribution shape. As a result, Idaho Power could easily follow the
standard practice employed by every other utility and use basic statistical techniques to combine
sources of variability and uncertainty that have different normally distributed shapes to
determine the optimal reserve levels. In fact, that aggregation is already happening on Idaho
Power's system through the laws of physics, as different sources of generation and load
t1
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
electrically combine and net out their variabilities. However, in its 2013 Study, Idaho Power
ignores the statistical reality of how those sources of variability are aggregating, instead choosing
a methodology that exaggerates the reserve requirement for wind. This methodological error by
itself guarantees that the reserve requirements estimated in the 2013 Study are greatly inflated.
Isolating the effect of netting the variability of wind and load would enable the resulting reserve
reduction to be subtracted from Idaho Power's reserve needs.
In light of the deficiencies with the 2013 Study, the Commission should direct the
Company to use its2007 Wind Integration Study as the basis for determining wind integration
costs until such time as the Company can complete a new study that corrects the methodological
flaws used in the 2013 Study. If the Commission nonetheless accepts the2013 Study as the basis
for wind integration charges for wind QFs without requiring any changes to the study, the
Commission should clarifu that such acceptance of the 2013 Study is without acceptance of the
underlying methodologies. In addition, the Commission should require regular updates to the
Company's wind integration studies (at least with every IRP cycle) to ensure that the most
current data and methodologies are being incorporated into the studies.
4. Idaho Power's 2013 Study Methodology Should Not Be Applied to Non-
PURPA Circumstances.
In addition to our concerns about the 2013 Study itself and its blending of PURPA costs
with "wind integration" costs, we are concerned with how the costs and rates identified in the
2013 Study might be applied outside of the PURPA context. In particular, we are concerned
with how the 2013 Study is applied to (l) an IRP analysis evaluating the costs of different energy
resources to serve an identified energy deficit on Idaho Power's system; and (2) an open access
transmission tariff ("OATT") schedule (reviewed by the Federal Energy Regulatory
t2
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
Commission) for balancing the within-hour deviation of a transmission customer's wind energy
schedule exported out of Idaho Power's BAA.
When asked how the Company might apply its 2013 Study methodology and costs to an
IRP analysis evaluating different energy resources to serve an identified energy deficit on its
system, the Company responded that, "Idaho Power proposes to include integration costs for
wind as set forth in Schedule 87 [as proposed in this docket]."16 We disagree that the costs
identified in the 2013 Study are appropriate for analyzing the value of wind energy resources
serving an identified energy need on Idaho Power's system. Under these circumstances, Idaho
power would not be surplus on energy and would instead be backing down more expensive
generation when the wind was generating. In light of this, the Company should use its 2007
Wind Integration Study methodology (or an updated study) in order to identifr integration costs
for non-PURPA wind that would be used in an IRP for purposes of evaluating different energy
resources to serve an identified energy need on Idaho Power's system.
With respect to an OATT schedule for balancing the within-hour deviation of a third-
party's wind energy schedule exported out of Idaho Power's BAA, the Company acknowledged
that it "does see a difference between must-take PURPA wind energy and a generator that is a
transmission customer not sinking the generation into the Idaho Power BAA."I7 Thus, it appears
that the Company does not intend to apply the 2013 Study and integration costs to a wind
generator transmission customer exporting its generation outside of the Idaho Power BAA. We
agree with Idaho Power that there is a significant difference between the integration charges
applicable to a wind generator transmission customer sinking the generation outside of the Idaho
Power BAA and the costs associated with accommodating excess must-take PURPA generation.
16 Idaho Power Response to Question 6 of Renewable Northwest and AWEA's Second Data Request.t' Id.
IPC-E-13-22 - September 4, 2014 Supplementary Comments of AWEA and Renewable Northwest
l3
To the extent that the Commission accepts Idaho Power's 2013 Study as the basis for "wind
integration charges" applicable to wind QFs under PURPA, we request that at a minimum, the
Commission clariff that such charges (l) would not be applicable to a wind generator
transmission customer transferring its energy outside of the Idaho Power BAA; and (2) would
not be used as the basis for wind integration charges in a subsequent IRP for purposes of
evaluating different energy resources to serve an energy need on Idaho Power's system.
5. Summary of Recommendations.
As discussed in these Supplementary Comments, the majority of the costs that Idaho
Power charactenzes as "integration costs" are costs associated with the remarketing of excess,
must-take energy when the Company is surplus on energy. These costs should be included in the
avoided cost methodology in order to avoid any overlap or inconsistencies.
. Due to the deficiencies with the 2013 Study, the Commission should direct the Company
to use its2007 Wind Integration Study as the basis for determining wind integration costs until
such time as the Company can complete a new study that corrects the methodological flaws used
in the 2013 Study. Such new study should focus on the within-hour balancing needs of the net
load and wind variability. After conducting such a study, to the extent that Idaho Power finds
there are additional costs associated with must-take PURPA wind that are incremental to the
integration costs identified in a proper study, those costs should be captured through the
Company's avoided cost methodology.
If the Commission nonetheless accepts the 2013 Study as the basis for wind integration
charges for wind QFs without requiring any changes to the study, the Commission should clariff
that such acceptance of the 2013 Study is without acceptance of the underlying methodologies.
In addition, the Commission should clarifu that wind integration charges derived from the 2013
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
14
Study would not apply to a wind generator transmission customer transferring its energy outside
of the Idaho Power BAA, and would not be used as the basis for wind integration charges in a
subsequent IRP for purposes of evaluating different energy resources to serve an identified
energy need on Idaho Power's system.
Finally, the Commission should require regular updates to the Company's wind
integration studies (at least with every IRP cycle) to ensure that the most current data and
methodologies are being incorporated into the studies.
IV. CONCLUSION
WHEREFORE, Renewable Northwest and AWEA respectfully request that the
Commission adopt the recommendations set forth in these Supplementary Comments.
DATED this 4th day of September,2014
K&L Gates, LLP
Attorney for AWEA and Renewable
Northwest
By
l5
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
CERTIT'ICATE OF SERVICE
I hereby certify that on the 4th day of September, 2014, a true and correct copy of the
foregoing SUPPLEMENTARY COMMENTS OF RENEWABLE NORTHWEST AND
AMEzuCAN WIND ENERGY ASSOCIATION, Case No. IPC-E-13-22, was served by
electronic mail to:
IDAHO POWER COMPANY: Donovan E. Walker
Idaho Power Company
l22l W.Idaho St. (83702)
P.O. Box 70
Boise,ID 83707-0070Email: dwalker@,idahopower.com
dockets@idahopower. com
Michael J. Youngblood
Greg Said
Idaho Power Company
l22l W. Idaho St. (83702)
P.O. Box 70
Boise,ID 83707-0070
Email:
myoungblood@i dahopower. com
[e-mail]
COMMISSION STAFF: Kris Sasser
Deputy Attorney General
Idaho Public Utilities Commission
47 2 W . Washington (837 02)
P.O. Box 83720
Boise, lD 83720-0074Email: [e-mail]
IDAHO WINDS LLCz Dean J. Miller
McDevitt & Miller LLP
420W. Bannock Street
Boise, ID 83702Email: [e-mail]
Rick Koebbe, President
Idaho Winds, LLC
5420W. Wicher Road
Glenns Ferry, lD 83623Email: [e-mail]
IPC-E-13-22 - September 4,2014 Supplementary Comments of AWEA and Renewable Northwest
l6
COLD SPRINGS WINDFARM, LLC;
DESERT MEADOW WINDFARM, LLC;
HAMMETT HILL WINDFARM, LLC;
MAINLINE WINDFARM, LLC;
RYEGRASS WINDFARM, LLC; AND
TWO PONDS WINDFARM, LLC:
CASSIA WINDFARM LLC;
HOT SPRINGS WINDFARM LLC;
BENNETT CREEK WINDF'ARM LLC;
CASSIA GULCH WIND PARK, LLC;
TUANA SPRINGS ENERGY,LLC; AND
HIGH MESA ENERGY, LLC:
DATED this 4th day of September, 2014.
Bob Eggers, Legal Counsel
Idaho Winds, LLC
Email: [e-mail]
Peter J. Richardson
Richardson Adams, PLLC
515 N. 27th Street
Boise, lD 83702Email: [e-mail]
Benjamin G. Huang, Manager
c/o Mountain Air Projects
6000 N. Foxtail Way
Glenns Ferry, ID 83623
Gregory M. Adams
Richardson Adams, PLLC
515 N. 27th Street
Boise, ID 83702Email: [e-mail]
Paul Ackerman
Assistant General Counsel
Exelon Business Services Corporation
100 Constellation Way
Baltimore, MD 21202
N
TERESA A. HILL
K&L GATES LLP
IPC-E-13-22 - Septernber 4,2014 Supplementary Comments of AWEA and Renewable Northwest
l7