20150423Yankel Direct.pdf

il RACI N E
OLSON
NYE
BUDGE
BAILEY
2O1 E. Center St.
P.O. Box 1391
Pocatello, lD 83204
o 208.232.6101
F 208.232.6109
racinelaw.net
Eric L. Olsen, LL.M
[e-mail].'.11, '
tilli,il'l 23 fil.i $; 53
ii...r':lTlt-ril ii,
April 22,2015
Jean J. Jewell, Secretary
ldaho Public Utilities Commission
P.O. Box 83720
Boise, ldaho 83720-0084
Re; Case No. IPC-E-I5-01; AVU-E-I5-01 and PAC-E-I5-03
Dear Mrs. Jewell:
Enclosed for filing in the captioned case please find an original and nine copies of
IDAHO IRRIGATION PUMPERS ASSOC'ATION, INC. DIRECT TESTIMONY OF ANTHONY
J. YANKEL AIso attached is an origina! and 9 copies of the "Confidential" pages as well as a
thumb drive as required for this filing.
Thank you for your assistance.
ELO:tl
Enclosuresc: Service List
i-r:.' \ '- l
:t!; rF.r ri. ,-r!ir. 'r( l!t i C.U j.ri O'c.)-' ' *i.J
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC.E.I5.OI
CASE NO. AVU-E-Is-OI
CASE NO. PAC-E-I5-03
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
DIRECT TESTIMONY
OF
ANTHONY J. YANKEL
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENT
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENT
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENT
April23,2015
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a. Please state your nzlme, address, and employment.
A. I am Anthony J. Yankel. I am President of Yankel and Associates, Inc. My
address is 29814 Lake Road, Bay Village, Ohio, 44140.
a. Would you briefly describe your educational background and professional
experience?
A. I received a Bachelor of Science Degree in Electrical Engineering from Carnegie
Institute of Technology in 1969 and a Master of Science Degree in Chemical Engineering from the
University of Idaho in1972. From 1969 through1972,I was employed by the Air Correction
Division of Universal Oil Products as a product design engineer. My chief responsibilities were in
the areas of design, start-up, and repair of new and existing product lines for coal-fired power
plants. From 1973 through 1977,I was employed by the Bureau of Air Quality for the Idaho
Department of Health & Welfare, Division of Environment. As Chief Engineer of the Bureau, my
responsibilities covered a wide range of investigative functions. From 1978 through June 1979,I
was employed as the Director of the Idaho Electrical Consumers Office. In that capacity, I was
responsible for all organizational and technical aspects of advocating a variety of positions before
various governmental bodies that represented the interests of the consumers in the State of Idaho.
From July 1979 through October 1980, I was a partner in the firm of Yankel, Eddy, and
Associates. Since that time, I have been in business for myself. I have been a registered
Professional Engineer in the states of Ohio and Idaho. I have presented testimony before the
Federal Energy Regulatory Commission (FERC), as well as the State Public Utility Commissions
of Idaho, Montana, Ohio, Pennsylvania, LJtah, and West Virginia.
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On whose behalf are you testiffing?
I am testiffing on behalf of the Idaho Irrigation Pumpers Association, Inc.
What is the purpose of your testimony in this proceeding?
My testimony will address:
* Supporting Idaho Power's initial request for a limitation on new PURPA
contracts to a term of two years. I do not view this as a long-term solution to
the glut of PURPA contracts that plague Idaho Power, but it is a good stop-
gap measure to give the Company and the Commission an opportunity to
correct problems with the present avoided cost model assumptions.
* My critique of Idaho Power's Exhibit 6 that attempts to illustrate the
problems of must-run and must-take power on the Company's system. I
contrast what is shown on Exhibit 6 with the manner in which the system is
actually operated.
* I provide a review and contrast of how the Company's avoided cost model
assumptions dif[er from the manner in which costly resources are actually
utilized, while making sales-for-resale at substantially lower prices.
* My ultimate recommendation is that new PURPA contracts be limited to a
term of two years and during that two year timeframe, the Company and the
Commission develop a more accurate avoided cost methodology.
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1 Q. What is your overall understanding of the purpose of the Qualifying Facilities
2 ("QF") under the Public Utility Regulatory Policies Act of 1978 ("PURPA")?
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4 A. PURPA attempted to encourage the development of cogeneration and small power
5 production facilities which were known as QF's. The purpose of these PURPA projects was to
6 help the Country become energy independent by utilizing cogeneration and small power
7 production facilities as a means of capturing energy, but for PURPA, may have been wasted. For
8 more than 20 years Idaho Power and the Commission have been successful in developing these
9 cogeneration and small production facilities.
10
I I However, with the advent of new wind and solar technology, the general principles behind
12 the PURPA generation resources has become lost. We are no longer talking about cogeneration
13 and small power production facilities, but installations/facilities that rival any utility generation
14 project. Rates paid to PURPA facilities were meant to be just and reasonable to a utility's
15 customers. In this case, Idaho Power appropriately points out that the present situation with
16 PURPA facilities is inappropriately causing rates to the customers to go up and are thus, no longer
17 just and reasonable.
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19 a. What is the present situation with PURPA facilities and the Idaho Power system?
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2l A. The present situation is well described by Idaho Power in this case. The capacity
22 level of PURPA facilities that are presently on the system or that have signed contracts, far out-
23 weigh the Company's ability to economically integrate them into the system. There are two basic
24 problems-must-take contracts and price. Given the level of the present facilities and signed
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contracts on the system, the Company will run into many times when it will simply have too much
capacity and will need to choose between curtailing its own must-run facilities or the PURPA
must-take contracts. The situation is further compounded by the fact that the prices being paid to
these PURPA facilities is usually higher than the running cost of any of the Company's facilities.
Backing down Idaho Power's facilities (to the point of must-run levels), in order to allow more
generation from these PURPA facilities simply means that the customers will be paying more.
The most egregious problem is that there have been times in the past when Idaho Power has had to
pay other utilities to take its excess power.
a. Why are you supporting Idaho Power's request to limit the term of future contracts
to just two years, when you indicate that the fundamental problem is the must-take provision as
well as the price?
A. I support the reduction of new contract terms to two years as a stopgap measure. I
assume that it will take at least two years to work out the complexities of what has gone wrong
and how to correct it. If new PURPA contracts were priced appropriately, Idaho Power would
either not have a glut of such facilities on its system now (and proposed to get much worse), or it
would be able to sell and/or deliver this energy in a manner that would not adversely impact its
customers. It is going to take some time to determine how to best integrate new PURPA facilities
into the system without exacerbating an already bad situation. If solutions can be developed in
two years, then they can be incorporated into the nedrenewed contracts. If the new contract
terms coming out of this case were for five years and solutions were developed in two years,
Idaho Power (and its customers) would have to wait an additional three years before finding some
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relief from a bad situation that has the potential to make things worse with each new contract that
is signed.
a. Do you support limiting all new PURPA contracts to a two year term?
A. No. I support only limiting the new solar and wind contracts to the two year term.
These are the contracts for intermittent power that got us into trouble in the first place. The
original pulpose of the PURPA contracts was for oocogeneration and small power production".
These are the types of facilities that may require long-term contracts in order to get financing.
PURPA was designed to stimulate cogeneration and small power production and not utility size
projects. I support the continuation of long-term contracts for new cogeneration and small power
production facilities.
IPCo's Exhibit 6 Compared To Actual Operation
a. Idaho Power's Exhibit 6 portrays the first week of each of 24 months of estimated
system load on an hourly basis compared to the company's must-run resources, must-take PURPA
generation and must-take non-PURPA power purchase agreements. Does that exhibit demonstrate
the problems Idaho Power could incur with respect to too much must-take capacity on the system?
A. Yes. Idaho Power's Exhibit 6 depicts the problem of having more must-take
capacity on the system (in addition to its own resources) than system load. However this exhibit
should be considered for illustrative purposes only. The system is far more involved than simply
assuming forecasted load and minimum must-run and must-take capacity levels.
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a. Idaho Power's Exhibit 6 demonstrates that Idaho Power not only has excess must-
take capacity from PURPA generation, but there is often excess capacity from only its own must-
run generation as well. Is that a problem?
A. No. First, it must be remembered that this exhibit is for illustrative purposes only.
The excess must-run capacity shown in Idaho Power Exhibit 6 does not reflect any additional sales
or obligations of Idaho Power. Thus, most of the extra Company-owned capacity on the system
can be absorbed by other than system customers. Very simply, Idaho Power's Exhibit 6 is for
illustrative puq)oses, and does not necessarily reflect how the system is actually operated.
Second, based upon Exhibit 6, the Company statesr that I4%o of the time there would be
excess capacity on the system, if one only included IPCo's must-run generation and the generation
from its own PPA's. I have worked on Idaho Power cases for over 35 years and have never heard
of a time where the Company had too much operating capacity on an ongoing basis. Yes, there
are times when generation exceeds system load, but during these times energy is sold off-system
or generation is simply taken off-line.
a. With respect to excess must-run capacity, how does the actual system operation
differ from the illustration in Idaho Power Exhibit 6?
A. On page 5 of 25 of Idaho Power Exhibit 6, is portrayed the "Forecasted Must Run
or Take Generation" for the f,rrst week of April2016 compared to the "Idaho Power Forecasted
I See testimony of Company witness Allphin at page 10.
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Load" (system only). As would be expected, April is the month with the most must-run capacity
compared to system load. During most of the forecasted hours for April20l6 (primarily the last
two hours of each day), the Idaho Power must-run capacity (excluding IPCo's own must-take
PPA's, PURPA excluding wind and solar, PURPA wind, PURPA solar under contract, and the
885 MW of proposed PURPA solar) is well above the forecasted load. Based upon the
assumptions contained on page 5 of that Exhibit, one would expect that April would be the month
when most of the curtailments due to excess capacity on the system would occur.
Idaho Power indicated2 that over the timeframe May 201 1 through Decemb er 2014, there
were 21 reliability curtailments of PURPA generation because of an over-generation position on
the system. Of these 2l curtailm.rt.,I during the month of April. However, compared
to the magnitude of the potential resource load/capacity imbalance demonstrated on Exhibit 6 for
April 2016, these ! curtailments only represented I of the number of hours of curtailment that
occurred during these 21 events3.
a. With respect to excess must-run capacity during other months, how does the actual
system operation differ from the illustration in Idaho Power Exhibit 6?
A. Unlike April, the graphs for October and November of 2016 on Exhibit 6 pages 11
and 12 portray the forecasted system load well in excess of Idaho Power's own must-run
generation. In fact the graph for October portrays no hours where the minimum must-run levels of
the Company's resources (plus IPCo must-take PPA) even approaches the level of the forecasted
system load. Additionally, with all of the resources (Company and none Company) listed on
2 See testimonv of
3
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witness Grow at paee 2l and
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Exhibit 6 there was only approximately 15 hours out of the 168 total hours in that week where the
system load is less than the summation of all must-take capacity including:
* IPCo's must-run hydro and coal generation,
* IPCo's own must-take PPA's,
* PURPA excluding wind and solar,
* PURPA wind. PURPA solar under contract, and
* 885 MW of proposed PURPA solar.
The graph for November portrays essentially the same thing. There are no hours in which
the must-run IPCo facilities plus IPCo's must-take PPA's exceeds the forecasted system load.
Even including the PURPA resources, (including solar under contract and the 885 MW of
proposed solar) there are only approximately 25 hours when the system load is less than the
summation of all must-run and must-take capacity. In other words, under today's conditions,
where the solar under contract and the proposed solar does not yet exist, October and November
are two months where Idaho Power should have minimal problems with excess capacity on the
system.
In contrast to the forecasted data in Exhibit 6, of the actual2l curtailments that occurred
between May 20ll and December 2014, I occurred during the months of October and
Novembera. However, compared to the minimal potential resource load/capacity imbalance (in
the future with added wind and solar) demonstrated on Exhibit 6 for October and November,
20l6,these ! historic curtailments represent"d It of the number of hours of curtailment that
occurred during these 21 events-under conditions of less PURPA wind and solar capacity than
a See confidential Response to Simplot Request 6d.
5 Confidential response to Simplot Request oaI
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whatislistedinExhibit6.Ecurtailmentslastedlongerthana1lIactual
events combined that occurred during the months of April6.
a. What does this comparison of Exhibit 6 and Idaho Power's actual curtailments
indicate about the need for reliability curtailments of PURPA generation on the IPCo system?
A. It means that Exhibit 6 does not give any quantifiable insight into the need of the
Company to call for reliability curtailments of PURPA generation because of excess must-take
capacity on the system. Exhibit 6 is a good illustration, but it is only an illustration and tells
nothing about the operation of the system. Looking only at Idaho Power's own must-run hydro
and coal, plus Non-PURPA must-take power purchases (without the addition of PURPA
generation-purchases), the Company statesT that Exhibit 6 demonstrates that over the2016---2017
period, system load will be exceeded 14% of the time. By comparison, the actual 21 curtailments
that occurred during the May 201 1 through Decemb er 2014 (44 months), amounted to only I
of that timeframe.
a. What should be concluded from a comparison of Idaho Power's Exhibit 6 and the
actual level of curtailments that have had to be taken on the system over the 44 month period
under review?
A. It should be recognized that Idaho Power's Exhibit 6 is a good illustration of the
problems the Company is facing, but it is not an accurate reflection of how the Company operates
6 Confidential
See Company witness Allphin's testimony pag3, l0 linel9l5.
8 Confidential response to Simplot Request 6d-
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in the real world. If the Company's modeling assumption do not reflect actual operation, then
inappropriate conclusion may be drawn from the models----of most concern in this case is the
avoided cost price that comes out of the Company's IRP model. If the IRP model assumption do
not recognizethe way that IPCo uses Term purchases and Sales, Beginning of Month ("BOM")
purchases and sales; and Day-Ahead purchases and sales, to balance its load, its avoided cost
pricing will be too high. The Company uses Term, BOM, and Day-Ahead activity to hedge its
supply in order to keep costs down. If the Company's IRP model assumptions do not reflect this
same logic, the resulting avoided costs will be too high.
a. As opposed to the general comparison that you just made between Idaho Power's
illustrative operation data and its actual level of curtailments over the recent 44 month period, can
you demonstrate more specifically how the assumptions of must-run capacity in Idaho Power's
Exhibit 6 compare to actual operations when a curtailment was called?
A. Yes. One of the 21 curtailments called by Idaho Power during this 44 recent month
periodoccurredduringEItlastedIandspannedtwodays.The
curtailment lasted over all of the light load hours between these two days as well as ! additional
hours.
Table 1 below lists the capacity figures from the last 12 hours of the first day when this
particular curtailment took place.l0 The "gray areas" reflects the first of the light-load hours (for
the last two hours of the day) when the curtailment was taking place. The capacity figures listed
are significantly higher than those that are represented as must-run and must-take capacity levels
e Confidential response to Simplot Request 6d-the curtailment occurred on
Data from the date and times listed from the confidential response to Irrigation Request 10.
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Hour
coal
hydro
gas
PURPA/other
found in [daho Power's Exhibit 6. A reliability curtailment was taking place during these two
light-load hours when generation was significantly above the minimum levels listed on IPCo's
Exhibit 6.
Table I
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For example, the capacity coming out of the coal facilities is significantly
higher than the "must-run" level of 266 MW listed on the graphs of Idaho Power's Exhibit 6.
Although there is a definite drop in coal generation from what occurred during the midaftemoon
hours, the drop is nowhere near the "must-run" level of 266 MW.
The capacity coming out of the hydro facilities is similarly higher than that used to
establish Idaho Power's Exhibit 6 page 9 for the last two hours of the first day. Measuring the
height of the "must-run" level depicted for "hydro plus coal" in Exhibit 6, it can be estimated that
the "must-run" capacity for these two sources is 700 MW. With coal generation taking up 266
MW of this total, this leaves 434 MW as the "must-run" minimum level for hydro generation. The
actual hydro generation was more than ! greater than this minimum during these last two hours
of the day when the curtailment was called.
Of even more significance, the gas plants, because of their nature, are not forecasted to run
during any of the minimum generation levels found on ldaho Power Exhibit 6. However, as seen
on Table 1 above, the gas plants were operating in th" I range during the last two hours of
the day when the curtailment was called.
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For completeness, Table 1 includes the amount of PURPA and other generation on the
Idaho Power system during these same hours.
a. How does purchase power and sales for resale fit into the mix of resources and
requirements on the I day that you are addressing?
A. Purchase Power and Sales for Resale are listed for each of the same last 12 hours of
that day on Table 2.rr
Table2
Hour
Term purchase
BOM purchase
Day Ahead purchase
Day Ahead sales
Real Time sales
Real Time purchases
The Term purchases and Beginning of Month (BOM) purchases are all apart of the system
balance, but they are set well ahead of the time when critical decisions need to be made regarding
the need for curtailment because of excess capacity. Day-Ahead sales and purchases reflect some
knowledge of what will occur during the following day.
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Real Time sales and purchases can definitely impact the excess capacity situation.
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a Please continue to demonstrate how the assumptions of must-run capacity in Idaho
Power's Exhibit 6 compare to actual operations during the second day when the curtailment in
question was called?
A.As pointed out above, the curtailment in question lasted I and spanned
two days. The curtailment lasted over all of the light-load hours between these two days as well as
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hours. Like the first day addressed above, for the second day of the curtailment, I
will primarily focus on what took place during light-load hours and contrast them with the rest of
the hours in the first half of the second day.
Table 3 below lists the capacity figures from the first l2 hours of the second day when this
particular curtailment took placel2. The "gray areas" for the first six hours of the day reflect the
remainder of the light-load hours when the curtailment was taking place. The significance of these
first six hours of the day is that the capacity figures listed are very different than those that are
represented as must-run capacity levels found in Idaho Power's Exhibit 6.
Table 3
Hour
coal
hydro
gas
PURPA,/other
12 Id.
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For example, the capacity coming out of the coal facilities is significantly
higher than the "must-run" level of 266 MW listed on the graphs of Idaho Power's Exhibit 6.
Although the coal generation that occurred during the first six hours (light-load hours) is lower
than the coal generation during the later morning hours, the drop is nowhere near the "must-run"
level of 266 MW-in spite of the fact that a reliability curtailment was taking place.
The capacity coming out of the hydro facilities is similarly higher than that used to
establish Idaho Power's Exhibit 6 page 9 for the first four hours of the second day. It can be seen
that on the graph on Exhibit 6 page 9 that the height of the "must-run" level depicted for "hydro
plus coal" is at the same height as the last two hours of the previous day, i.e., 700 MW. With coal
generation taking up266 MW of this total, this leaves 434 MW as the "must-run" minimum level
for hydro generation. The hydro generation was about lYo greater than this minimum during
these first four hours of the second day when the reliability curtailment was called.
Of even more signifrcance, the gas plants, because of their nature, are not forecasted to run
during any of the minimum generation levels found on Idaho Power Exhibit 6. However, as seen
on Table 3 above, the gas plants were operating in the ! MW range during the first six hours of
the second day when the reliability curtailment was called.
For completeness, Table 3 includes the amount of PURPA and other generation on the
Idaho Power system during these same hours.
a. How does purchase power and sales for resale fit into the mix of resources and
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requirements on the second day in I that you are addressing?
Hour
Term purchase
BOM purchase
Day Ahead purchase
Day Ahead sales
Real Time sales
Real Time purchases
A. Purchase Power and Sales for Resale are listed for each of the first 12 hours of that
day on Table 4.
Table 4
2345IITIIITIIIIIrIITIlllllll
Once again, the Term purchases and Beginning of Month (BOM) purchases are all apart of the
system balance, but they are set well ahead of the time when critical decisions need to be made
regarding the need for reliability curtailments because of excess capacity. Day-Ahead sales and
purchases reflect some knowledge of what will occur during the following day. The combined
Day-AheadtransactionsduringthesehoursresultedinEthefollowingdayof
excess capacity. For the particular hours in question, all of these non-Real Time transactions
result in
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Real Time sales and purchases can definitely impact the excess capacity situation.
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a. Does this comparison of Idaho Power's Exhibit 6,page 9 with an actual curtailment
that occurred during August 2012 indicate that Idaho Power was operating its system
inappropriately and/or it should not have curtailed PURPA load?
5 A. Absolutely not. At this time, I am assuming that Idaho Power operated its system
6 during the time of this reliability curtailment to the best of its abilities-including the curtailment.
7 Once again, this comparison shows is that there is a great deal of difference between many of the
8 Company's modeling assumptions and the way the system works on an hour-to-hour basis.
9
l0 a. What is the significance to this case of the difference between modeling
I I assumptions and hour-to-hour operations?
t2
13 A. The modeling indicates that there are potential problems regarding excess capacity
14 that cannot be addressed by backing down units below a must-run level. However, the large
15 differences between the model results and actual operation demonstrates the limited ability of the
16 model assumptions to reflect actual system operation, and more importantly, actual system costs.
17 This inability of the Company's model assumptions to reflect actual system operation and actual
l8 system cost is particularly important to this case, because if the avoided costs that are developed to
19 be paid to PURPA generators are inaccurate, so will the inducement to build these projects. If the
20 IRP model assumptions do not recognize the way that IPCo uses Term purchases and Sales,
21 Beginning of Month ("BOM") purchases and sales; and Day-Ahead purchases and sales, to
22 balance its load, its avoided cost pricing will be too high. The Company uses Term, BOM, and
Case No. IPC-E-I5-1
April23,2015
Yankel, Di -16
Inigation Pumpers
I Day-Ahead activity to hedge its supply in order to keep costs down. If the Company's IRP model
2 assumptions do not reflect this same logic, the resulting avoided costs will be too high.
J
4 A far better way to control the growth of PURPA generation on the Idaho Power system is
5 not to reduce the terms of the contracts, but to develop avoided cost model assumptions that more
6 accurately reflect the operation of the system. These avoided cost model assumptions must not
7 only recognizethe glut of PURPA generation that is presently on the system, but how the system
8 actually operates today. Having a model assumption that assumes that nedadditional PURPA
9 generation will replace the Company's owned resources is simply invalid. This may have been an
10 acceptable assumption when the amount of PURPA generation on the system was small, but today
l1 this assumption is not only causing operation problems, but is resulting in significantly higher
12 prices for ratepayers.
13
14 PURPA Generation Replacing The Hishest Cost Resource
15
16 a. Can you give any other examples of how the actual operation of the system may
17 differ from the assumptions used in the IRP model to develop avoided costs?
l8
19 A. Yes. It is my understanding that a prime assumption used in the IRP model is that,
20 except for system operating limitations, the least expensive options in the resource stack will be
2l used to supply load. Very simply, this means that a more expensive resource will be backed-offl if
22 a cheaper resource is available. However, there are times when the actual operation does not
23 strictly follow this rule. I assume that the Company is operating its system at the lowest cost it
24 can, given the minute-to-minute and hour-to-hour balancing of loads and resources that are
Case No. IPC-E-15-l
April23,2015
Yankel, Di -17
lrrigation Pumpers
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required. However, if the Company's IRP model assumptions, as a whole, do not accurately
reflect the minute-to-minute and hour-to-hour operation of the Company, one cannot expect the
resulting avoided cost that comes out of the model to be accurate.
a. Can you demonstrate how Idaho Power's actual operations differ from the general
principle that only the lowest cost resources should be utilized?
A. Yes. As a component of the concept of using the lowest cost resources first, it is
generally agreed that when a sales-for-resale is made, the price received for the energy should be
equal to or above the highest cost uniVresource operating. In other words, it is assumed that if the
sale were not made, then the highest priced resource could be backed-off by the quantity of the
energy sold. Of course, this does not apply to energy coming from PURPA projects or if there is
some operational limitation in effect at the time.
By way of example, during actual operations Idaho Power does in fact sell energy off-
system at prices lower than the cost of its most expensive operating resource (and often below the
cost of more than just its highest cost operating resource). In order to demonstrate this, I have
constructed Table s. In I Idaho Power started Langley Gulch on I and ran it
constantly (24x7)Generally speaking, Langley Gulch ran
generally at a
stable level during each period. Table 5 lists the hours I when the weighted-average
pricel3 received for day-ahead sales-for-resale fell well below the cost of running Langley Gulch
'3 Data from the date and times listed from the confidential response to Irrigation Request 10,
Case No. IPC-E-15-1
Apil23,2015
Yankel, Di -18
Inigation Pumpers
H14 H15 H16 H'.t7 Hi8 H19 H20 H21 H22 H23 H24
IIIIII
IIIIttttTIIIIIIIIITITIIIIIIITTITTIITIIIIIIIIIIITIIIIIIIIIIrrrtIIIIII
IIIIIIT
TIIITIIITIIIII
IIIITIT
HI H2 H3 H4 H5 H6
IIITITITIIITIIIITI III
IIIIITIIIIITllrtl!!TIITTIITTTIlrtlllIIIIIIIIITII
IIITIIIIIIIIIIIIITIIIIIIIIIIIIIITIIITITIIIIIIITI
Pric6
IIIIIIIIIIIIIIIIrIIIIII
($35.0 per MWH)14, and in many cases below the cost of operating some of the Company's coal
plant: Valmy at$4g.6per MWHrs; Boardman at $32.1 per MWHrU; *d Jim Bridger at $28.6 per
MWHr7.
Table 5H7 H8 H9 H10 Htl Ht2 H13
a. Please further describe what is contained on Table 5.
A. Table 5 indicates for the hours between whether or not
the price received for day-ahead sales-for-resale was less than the cost of operating Langley
Gulch. The first column lists the date and the first row lists the hours in each day. The second
column lists the average-weighted price received for the "low priced" sales-for-resale for a given
day and hour being addressed here. An "X" marks the hour during a given day when Langley
Gulch was operating and when sales-for-resale have occurred at the weighted-average price listed
in Column 2. When there is an ")C(", Langley Gulch is operating as well as one other gas
generator. When there is an "X)O(", all three of the Idaho Power's gas units are operating (note
to ldaho Power's 2013 FERC Form I page 402.1for Langley Gulch.t'Idaho Power's 2013 FERC Form I page 403 for Valmy.
16 ldaho Power's 2013 FERC Form I page 402 for Boardman.
17 Idaho Power's 2013 FERC Form I page 402 for Jim Bridger.
Case No. IPC-E-15-1
April23,2015
Yankel, Di -19
Irrigation Pumpers
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that Danskin operates at $54.3 per MWH and Bennett Mountain at $59.0 per MWHr). a" 66XV"
indicates that Langley Gulch is operating and that Valmy is operating above minimum must-run
level. No marking indicates that there were no sale-for-resale during that particular day and hour
at the "low prices" listed in Column 2.
By way of example,
energy sold at this time was
The average-weighted price of the
This price is well below the operating cost of
Langley Gulch and Valmy (as well as Bridger and Boardman), which were both operating at the
time. Sales-for-resale were sold at this weighted-average price of
These hours are marked with a "XV".
By way of further example, the weighted-average price of the energy sold onI
On this day Valmy was operating at minimum levels during the first six
hours so the table only displays an"X" for this time period. On this day, the sales-for-resale at the
weighted-average price of Valmy was operating
above minimum levels after the 6:00 a.m. hour. Because both Langley Gulch was operating and
Valmy was operating above minimum levels after the 6 a.m. hour, these hours are marked with a
ooxvrr.
a. What can be concluded from Table 5 with respect to the differences between the
assumptions in the Company models for avoided costs and the way the Company actually operates
its system?
" Idaho Power's 2013 FERC Form I page 403 for Danskin and Benneft Mountain.
Case No. IPC-E-15-l
April23,2015
Yankel, Di -20
Irrigation Pumpers
I A. As I pointed out above, I assume that the Company operates its system in order to
2 minimize costs. Table 5 demonstrates that Idaho Power does not operate its system based upon
3 the simplifring assumption that (absent certain operational constraints) the lowest cost resources
4 will be used to supply load. Under this assumption in the model, the Company would not be
5 selling power at prices significantly lower than the marginal cost to produce the energy. The
6 model assumptions used to establish avoided costs must reflect how the Company actually
7 operates and not rely upon general assumptions that ignore many of the realities of the system.
8
9 Conclusion and Recommendations
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a. What are your conclusions and recommendations?
A. From the above differences that I have pointed out, it is obvious that Idaho Power's
models and modeling assumptions do not sufficiently reflect actual Company operations. Without
the Company's model assumptions accurately reflecting actual system operation, it must be
assumed that the models do not adequately predict avoided costs.
I recommend that the Commission limit the term of all future PURPA contracts to 2-years
for all three of the major electric utilities operating in the Idaho. Hopefully, this will be suffrcient
time to review the modeling assumptions and the avoided costs of all three utilities. Assuming
that adequate modeling assumptions can be put in place within two years, then it may be desirable
to change the length of the term at that time. If adequate modeling cannot be put in place within
two years, then the 2-year term should stay in place.
Case No. IPC-E-15-1
April23,2015
Yankel, Di -21
Irrigation Pumpers
CERTIFICATP OT SERVICE
l
I HEREBY CERTIFY that on thisfrd\ay of April,20l5I served a true, correct and
complete copy of the Idaho Irrigation Pumpers Association,Inc. Direct Testimony of Anthony J.
Yankel to each of the following, via U.S. Mail or private courier, e-mail or hand delivery, as
indicated below:
IDAHO POWER COMPANY:
Donovan E. Walker
Regulatory Dockets
l22l W. Idaho St. (83702)
P.O. Box 70
Boise,ID 83707-0070
E-mail: [e-mail]
[e-mail]
COMMISSION STAFF:
Donald L. Howell, II
Daphne Huang
Deputy Attorneys General
Idaho Public Utilities Commission
472 W . Washington (837 02)
P.O. Box 83720
Boise,lD 83720-0074
E-mail: [e-mail]
daphne.huan [e-mail]. gov
J.R. SIMPLOT COMPANY:
Peter J. Richardson
Gregory M. Adams
Richardson Adams, PLLC
515 North 276 Street
P.O. Box 7218
Boise, D 83707
peter@ri chardsonadams. com
ere [e-mail]
Don Reading
6070 Hill Road
Boise, D 83702
E-mail: [e-mail]
IDAHO CONSERVATION LEAGUE, SIERRA
CLUB
Benjamin J. Otto
Idaho Conservation League
710 N. Sixth Street (83702)
P.O. Box 844
Boise, D 83702
E-mail: [e-mail]
X U.S. Mail/Postage Prepaid
E-mail
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Hand Delivered
X U.S. Mail/Postage Prepaid
E-mail
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X U.S. Mail/Postage Prepaid
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Matt Vespa
Sierra Club
85 Second St 2od Floor
SanFrancisco, CA 94105
E-mail: matt. [e-mail]
INTERMOUNTAIN ENERGY PARTNERS, LLC
Leif Elgethun, PE, LEED AP
Intermountain Energy Parhners, LLC
P.O. Box 7354
Boise, D 83707
leif@ s itebasedenerry.corn
Dean J. Miller
McDevitt & Miller LLP
420W. Bannock Street
P.O. Box 2564-83701
Boise, D 83702
j [e-mail]
SNAKE RTVER ALLIANCE:
Kelsey Jae Nunez
Snake River Alliance
223 N. 6ft Street, Suite 317
P.O. Box 1731
Boise,ID 83701
knunez@snakeriveralliance. org
Ken Miller
Snake River Alliance
km il I er@snakeriveral liance. org
PACIFICORP, DBA ROCKY MOUNTAIN POWER:
Ted Weston
ID Reg Affairs Manager
Rocky Mountain Power
201 S. Main St., Ste 2300
Salt Lake city, uT 84111
ted. weston(Epaci fi corp.com
Daniel S. Solander
Yvonne R. Hogle
Rocky Mountain Power
201 S. Main Street Ste 2400
salt Lake city, uT 84111
daniel.solander@pacifi corp.corn
yvonne.ho [e-mail]
Data Request Response Center-PacifiCorp
E-mail [e-mail]
U.S. Mail/?ostage Prepaid
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x
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x
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TWIN FALLS CANAL COMPA].[Y, NORTHSIDE
CANAL COMPANY AND AMERICAN FALLS
RESERVOIR DISTRICT NO. 2:
C. Tom Arkoosh
Arkoosh Law Offices
802 W. Bannock St., Ste 900 (83702)
P.O. Box 2900
Boise,ID 83701
E-mail: [e-mail]
Lynn Harmon
AMERICAN FALLS RESERVOIR DIST #2
409 N. Apple Street
Shoshone, ID 83352
Erin Cecil
Arkoosh Law Offices
E-mail : [e-mail]
IDAHO IRRIGATION PUMPERS ASSOCIATION,
INC.:
Anthony Yankel
29804 Lake Road
Bay Village, OH 44140
E-mail: [e-mail]
CLEARWATER PAPER CORPORATION :
Peter J. Richardson
GregoryM. Adams
Richardson Adams, PLLC
515 N.276 Street
Boise, D 83702
E-mail: [e-mail]
[e-mail]
RENEWABLE ENERGY COALITION:
Ronald Williams
Williams Bradbury PC
1015 W. Hays Street
Boise, D 83702
ron@william sbradbury. com
Irion Sanger
Sanger Law, PC
I117 SW 53'd Avenue
Portland, OR 97215
E-mail: [e-mail]
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AVISTA CORPORATION
Michael G. Andrea
Avista Corporation
1411 E. Mission Ave.
MSC-23
Spokane, WA 99202
m ichae l.andrea@avi stacorp. corn
Clint Kalich, Manager
Resource Planning & Analysis
Avista Corporation
141I E. Mission Ave., MSC-7
Spokane, WA 99202
E-mail: [e-mail]
MICRON TECHNOLOGY, INC.:
Frederick J. Schmidt
Pamela S. Howland
Holland & Hart LLP
377 S Nevada St.
Carson City, NV 89703
I B-mail: [e-mail]
Richard E. Malmgren
Micron Technology, Inc.
800 South Federal Way
Boise,ID 83716
E-mail: remalm [e-mail]
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TI{EAMALGAMATED SUGARCOMPA}.IY,LLC: X U.S. Mail/PostagePrepaid
Scott Dale Blickenstaff
Amalgamated Sugar Co.
1951 S. Saturn Way, Ste 100
Boise, D 83702
E-mail: [e-mail]
AGPOWER DCD, LLC & AGPOWER JEROME,
LLC
Andrew Jackura
Sr. VP North America Devl
Camco Clean Energy
9360 Station St., Ste 375
Loan Tree, CO 80124
E-mail: [e-mail]
DeanJ. Miller
McDewitt & Miller LLP
420 W. Bannock Street
Boise, D 83702
E-mail: [e-mail]
Jean D. Jewell, Secretary
Idaho Fublic Utilities Commissions
P.O. Box 83720
Boise, D 83720-0074
E-mail: i [e-mail]
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ERIC L. OLSEN