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BEFORE THE
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IDAHO PUBLIC UTiliTIES COMMISSJ~~ liES' CU
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S. GEOTHERMAL, INC., AN IDAHO
CORPORATION ) CASE NO. IPC-O4-
IDAHO POWER COMPANY, AN IDAHO
CORPORATION
) CASE NO. IPC-O4-
Complainant,
vs.
Respondent.
BOB LEWANDOWSKI AND BOB
SCHROEDER
Complainants
vs.
IDAHO POWER COMPANY, AN IDAHO
CORPORATION
Respondent.
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTiliTIES COMMISSION
AUGUST 5, 2004
Please state your name and business address
f or the record.
My name is Rick Sterling.My business address
472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What is your educational and professional
background?
I received a Bachelor of Science degree in Civil
Engineering from the University of Idaho in 1981 and a
Master of Science degree in Civil Engineering from the
University of Idaho in 1983.I worked for the Idaho
Department of Water Resources from 1983 to 1994.In 1988,
I became licensed in Idaho as a registered professional
Civil Engineer.I began working at the Idaho Public
Utilities Commission in 1994.My duties at the Commission
include analysis of utility applications and customer
petitions.
What is your background and experience as
relates to avoided costs and QF contracts?
I have worked for the Idaho Public Utilities
Commission for over 10 years.Throughout that time, I have
been the primary Staff person assigned to all matters
related to avoided costs and Qualifying Facility (QF)
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STAFF
contracts.I have been instrumental in developing and
employing methods to determine avoided cost rates.I have
reviewed and commented on every QF contract that has been
submitted to the Commission for approval during the past
ten years, and I have been ei ther the wi tness or sponsor of
comments on every PURPA-related proceeding to come before
the Commission in that time period.
What is the purpose of your testimony in this
proceeding?
The purpose of my testimony is to present Staff'
position on the following:
1) Definition of the 10 MW threshold for eligibility
for posted avoided cost rates; and
2) Whether the contract provisions offered by Idaho
Power to U. S Geothermal, Bob Lewandowski and Mark
Schroeder are reasonable, and if not reasonable,
to offer recommendations for revised provisions
which Staff believes are reasonable; and
3) Whether the ~regulatory-out" contract provision
sought by Idaho Power is necessary and
enforceable.
Please summarize your testimony.
I believe that Idaho Power s proposal to define
the 10 MW threshold for determining eligibili ty for posted
avoided cost rates is reasonable.Staff has always
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STAFF
interpreted the threshold as a capaci ty I imi t, not an
average energy I imi t I believe that a 10,000 kWh per hour
interpretation is easy to administer.I do not support
using nameplate capacity to judge eligibility for posted
rates.
I support Idaho Power s proposed concept of
establishing a performance band as the criteria for
distinguishing between firm and non-firm energy.Howeve r ,
I believe that the Company s proposed band is too narrow.
I recommend that the band be set between 80 and 120 percent
rather than the 90-110 percent band proposed by Idaho
Power.In addition, I support Idaho Power s inclusion of a
contract provision to excuse performance in the event of
forced QF outages, but I recommend that the grace period be
extended from 72 hours to 30 days.
I do not support Idaho Power s insistence on
inclusion of a ~regulatory-out" clause in QF contracts.
Please briefly summarize the varlOUS types of
avoided cost rates available to QFs in Idaho.
Idaho has a 25-year history of QF development in
the state.In that 25-year period, an extensive array of
power sales and pricing options has evolved to accommodate
a very wide variety of proj ect types, financing options,
generation characteristics and developer preferences.
more easily illustrate the variety of options, I have
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prepared Exhibi t No.1 0 1 .Al though thi s exhibi t
specific to Idaho Power, both Avista and PacifiCorp have
similar options.
Beginning at the top of the flowchart, proj ects
either sell to the utility under a contract or under a
tariff. Under a tariff , proj ects have no obligation to
deliver power In any specified amount or for any specified
length of time.The project is entitled to the rates
specified under the tariff as long as the tariff remains in
place.On the far right is Idaho Power s Schedule
tariff for net metering customers.This tariff is designed
for small projects that basically wish to ~spin the meter
backwards. "
The center section of the flowchart shows the
options available for ~non- firm" energy sales.proj ects
too large to qualify for the net metering tariff could
qualify for the Schedule 86 non- firm tariff.Non- firm
energy is that which is delivered on an ~if and as-
available basis.Non-firm energy projects less than 10 MW
in size are paid 85% of Mid-C market prices.proj ects
MW and larger would be subj ect to negotiated rates
beginning at a price equal to 85% of Mid-To date, there
have been no non-firm energy projects 10 MW or larger , and
there have only been a few non- firm proj ects smaller than
10 MW.
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By far , most proj ects developed to date have
chosen to sign long-term contracts with the utilities.
Long-term contracts are depicted on the left hand side
Exhibit No. 101.For proj ects smaller than 10 MW , the
Commission has developed avoided cost rates for fossil-
fueled and non- fossil- fueled proj ects, and rates that are
either levelized or non-Ievelized.Rates for these
contracts have been referred to in the past as ~published
rates " or ~posted rates.For proj ects 10 MW and larger
contractual rates are determined using a methodology that
relies on utilities ' Integrated Resource Plans (IRPs) and
their power supply models.The resul t of applying the
prescribed methodology is a project-specific rate that
recognizes the characteristics of individual proj ects.
Since this methodology has been in place, it has been
employed only once for a contract between Avista and
Potlatch.
Are there any other mechanisms for selling power
to utilities?
Yes, proj ects could also become certified as
Exempt Wholesale Generators (EWGs) under PURPA , or
merchant plants." In that case, they could sell power to
whoever they wanted under whatever terms they are able to
negotiate, as long as the sales are not retail.
Finally, proj ects could choose to respond to
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utilities ' Request for Proposals (RFPs)Solicitations to
acquire power are made from time to time, usually for some
specific type of product.For example, PacifiCorp recently
issued an RFP for renewables, but has yet to announce
which , if any, bids will be accepted.The utility intends
to issue more RFPs in the future, as does Idaho Power.
Idaho Power s draft 2004 Integrated Resource Plan states
that the Company intends to try to acquire 100 MW of
geothermal resources and 350 MW of wind resources in the
next six years through an RFP process.The Company intends
to issue an RFP for 200 MW of wind before the end of this
year , and another RFP for 100 MW of geothermal resources
next year.
Do you have any concerns about the RFP process
being used by utilities to acquire renewables?
I do not have concerns about using the RFP
process to acquire renewables, but I do have concerns about
inconsistencies between rates that might be paid for
renewables acquired under the RFP process and those
acquired as QFs under PURPA.
Do you believe that the tariffs and mechanisms in
place for enabling non-utilities to sell power to the
utilities are adequate?
Yes, I believe that this Commission s tariffs and
mechanisms are very extensive and can accommodate proj ects
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STAFF
of nearly any type and slze.In fact, my experience has
been that few people are aware and even fewer understand
just how many options there are for selling power to
utilities in Idaho.Many people have had the mistaken
impression for many years that proj ects 10 MW and larger
could not even be developed in Idaho.
What is the advantage, if any, for a proj ect
be smaller than 10 MW in size?
The advantage is that there is a pre-determined
schedule of rates developed that utilities must pay under
contract.With a pre-determined schedule of rates,
developers are relieved of being required to negotiate a
rate.Another possible advantage is that the ~posted
rates " may exceed the rates determined using the proj ect-
specific IRP-based methodology.
Why do you say possible advantage?
I say there may be a possible advantage because
it is not possible to know which rates will be higher
unless the IRP-based methodology is actually applied and a
rate computed. The assumption most people seem to make
that the ~posted rates " will always be higher, but I
contend this assumption is almost always made without any
information comparing the two rates.
Without actually making a comparison of the
under- and over-l0 MW rates, which do you think are more
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STAFF
likely to be higher?
I believe it depends on the generation
characteristics of the proj ect.For a proj ect that
generates as a mostly base-load type of proj ect, the under-
10 MW rates will probably be higher.However, for a
proj ect that is able to generate more during on-peak hours
and during peak seasons, the over-l0 MW rates are likely to
be higher because the project-specific modeling is able to
recognlze the added value of peak generation.
Has a project-specific rate been determined for
any of the parties in this case for proj ect sizes larger
than 10 MW?
No, not that I am aware.Quite frankly, I am
amazed that neither Idaho Power nor the complainants have
made any effort to determine what the rate would be if the
proj ect were larger than 10 MW.
Would it be difficult for Idaho Power to compute
a rate for U. s. Geothermal for a proj ect size of say, 20
MW?
I wouldn t say it is a trivial exerClse, but I
would say that Idaho Power should be qui te capable of doing
it in a relatively short period of time.According to the
methodology description adopted in the settlement
stipulation in Case No. IPC-95-9, Order No. 26576,
utilities are required to make such a computation within
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STAFF
days of the request.
If U.S. Geothermal simply cannot size its Raft
River proj ect to produce no more than 10, 000 kWh per hour
and remain cost-effective, does that mean that the project
mus t be abandoned?
No, clearly not.If the proj ect must be sized
larger than 10 MW , it just means that the IRP-based
methodology would be used to establish its rate as a QF
proj ect, or that it must become a merchant generator or
participate in an RFP process.
Idaho Power seeks to define the 10 MW threshold
for eligibility for posted avoided cost rates as being ~not
to exceed 10,000 kWh per hour " while U. s. Geothermal seeks
to define the threshold as 10 average megawatts (aMW)
measured on an annual bas is.How do you believe the
threshold should be def ined?
I believe that Idaho Power s proposal to define
the threshold as ~not to exceed 10,000 kWh per hour " is
reasonable.Idaho Power has used this definition in the
past when 10 MW was formerly the threshold.Whi I e not
stated in any prlor Commission Order or formally endorsed
by either the Commission or its Staff, Staff has
historically viewed this definition as reasonable and has
interpreted the threshold as an actual capacity generation
limit.Although capacity, by definition, is normally not
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STAFF
associated with generation over any specified time period,
defining capacity by measuring generation over a one-hour
period has proven to be a relatively easy method for Idaho
Power to use.In many respects, it is analogous to how
demand is measured for purposes of billing commercial,
industrial and irrigation customers, except that a one-hour
period is used instead of a 15-minute period that is used
for demand billing purposes.In the past, several QF
contracts have included this defini tion.
There has been a 10 MW threshold for posted rates
for most of the years PURPA has been implemented in Idaho.
Why has this issue not come up sooner?
I believe it has never been an lssue before
because there have only been few proj ects close
In Slze.these,all have been either hydropower
proj ects or wood waste fired proj ects wi generally higher
capaci ty factors.Existing projects close to 10 MW in size
can and do generate at their rated capacity a large share
of the time.The vast maj ori ty of existing QFs are much
smaller than 10 MW.Now, however, wi th the recent
introduction of lower capaci ty factor proj ects,
particularly wind, it is likely that some will rarely
generate at their rated capacity.For example, a wind
proj ect might be sized to be capable of generating 10 MWs
of capacity, but it will likely do so only for a very small
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port ion of the year.Thus, for some generation
technologies, how the 10 MW threshold is defined is
crucial.
In the past, has Staff viewed the 10 MW threshold
as a capacity limit or an energy limit?
Staff has always viewed it as a capacity limit.
Furthermore, I believe the utilities and developers have
also viewed capaci ty limit.Al though there has
been some question in recent years about how the I i mi
shoul d be measured,am not aware anyone,un t i I now
who has ever suggested that it be viewed as an energy
limit.If 10 MW had been viewed as an energy limit, Staff
would have been careful to always specify it as ~10 average
megawatts " or 10 aMW.Contrary to Mr. Ki t z ' s testimony, in
the regulatory arena, plants are always generally described
by their rated capaci ties , not by their average annual
capaci ties.For example, Idaho Power s Danskin project
normally referred to as a 90 MW plant because it has the
capability to generate 90 MW under normal conditions.
it were to be described instead based on its average annual
generation, it would be described as a 5 or 10 MW plant due
to its limited hours of operation.Moreover, its capacity
based on average annual generation would vary considerably
from one year to the next because it would never
consistently operate the same amount of time from year to
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year.Qui te frankly, I have never heard of a plant
generally described by its average annual energy unless
is specifically stated as average megawatts.If the
Commission had intended for the threshold to be 10 aMW , I
believe it would have stated it that way in its prior
Orders.
Could the Commission choose to define the
threshold as 10 aMW?
Certainly; however , I think it could become even
more problematic to administer if it were to do so.First,
if a threshold of 10 average megawatts measured over the
course of a year were used, it could not be verified except
on an annual basis.A test based on hourly metering would
instead be able to provide almost immediate- verification.
Second , if 10 aMW were used as the criterion , it would take
a complete year before it could be verified that a proj ect
was or was not less than 10 aMW.Moreover , that same
difficul ty would persist every year thereafter.If the QF
were found to have exceeded a 10 aMW threshold at the end
of a year , I think it would present administrative and
accounting difficulties to adjust for payments already made
to the QF in prior months based on an assumption that the
proj ect was less than 10 aMW.
Do you believe it would be unfair to certain
technologies to def ine the 10 MW threshold as being 10, 000
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kWh pe r hour?
No, I do not.One of the key reasons for having
any threshold at all is because there are better , more
accurate ways to establish a value for proj ects whose
generation characteristics and timing differ markedly from
the SAR plant used as the basis for computing posted rates.
A case could be made that the more sophisticated IRP-based
methodology should be used for all proj ects,especially
those that are radically different than a gas-fired CCCT.
I believe it is very reasonable to use the IRP-based
methodology for wind or geothermal proj ects wi th a capaci
of 10 MW or more because their generation is so different
from the SAR' s.If a different capaci ty threshold were
chosen for each generation technology, or if a 10 aMW
energy threshold were adopted, then I do bel ieve certain
technologies would be given a preference over others.
Do you believe ~nameplate capacity " lS a
reasonable way to define the 10 MW threshold?
, I do not.Other parties in this case have
pointed out the problems associated wi th this sort of a
defini tion so I will not rei terate them here.I don
believe anyone in this case is advocating such a
definition.
Idaho Power has proposed that a ~90/110 percent
band" as described in Mr. Gale s testimony be used to
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determine eligibility for posted rates.Us ing some
examples, can you illustrate how such a concept would work?
To illustrate the concept, I have prepared
Exhibit Nos. 102 and 103.Exhibit No. 102 illustrates
three scenarios in which base energy prices (or the posted
energy rates) are less than the market energy cost (or 85%
of Mid-C prices) Scenario 1 shows the payment if the
proj ect produces exactly as expected.Scenario 2 shows the
net payment in the event the proj ect fails to produce
least 90 percent of its estimated monthly generation.Note
that it is possible in this instance, if generation falls
short enough, for the project to owe money to the utility
if it fails to produce.Scenario 3 shows the net payment
ln the event generation exceeds 100 percent of the
estimate.Exhibit No. 103 illustrates comparable
scenarlos, except in the instance where base energy prlces
(posted rates) exceed market energy costs (85% of Mid-C) .
Do you agree conceptually with the ~90/110
percent band" concept as proposed by Idaho Power?
Yes, I do for the most part; however, I will
propose modifications to the proposed contract terms that
believe are fairer to both parties.Wind generation
generally considered non-firm in the traditional sense
because it is not possible to know in advance how much,
any, generation will be available.However , wind proj ect s
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are not all al ike Some larger , more sophisticated
projects may have some ability to predict generation with
varying degrees of accuracy.For example, a multi-turbine
wind farm in a location with steady winds and good
historical data may be capable of forecasting its
generation to some extent, while a single, small ~mom and
pop " turbine is unlikely to have any ability to forecast
generation.Idaho Power s proposal gives the opportuni
to receive posted rates to those who can predict their
generation with some certainty.Those who cannot would be
relegated to selling power under Idaho Power s Schedule
for non-firm energy sales.
Are there other ways besides establishing a
band" that could be used to properly discount the value of
non-firm energy?
Yes, I bel ieve there are.Many studies have been
done in the past few years to attempt to determine the cost
of firming non-firm wind energy.Exh i bit No.1 0 4 1 i s t s
several recent studies.One of the purposes of these
studies is to quantify the capacity value of wind
generation and to evaluate the costs of integrating wind
into utility systems.The studies usually assume that a
gas-fired simple cycle plant must be built to provide
backup capacity for those times when the wind plant cannot
produce its rated capacity.The results of these studies
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vary, but all conclude that there is some cost associated
with integrating wind.The resul ts often depend on
assumptions about how much wind generation would be added
in relation to the size of the utility s existing
generation fleet, along with how much peaking capability
the utility already has.The range of wind integration
costs from various studies is from approximately $1.50 to
$5.50 per MWh. Hirst's April 2004 study showed a very broad
range of integration costs, from almost none for very small
amounts of wind to as much as $14 per MWh for large amounts
of wind.PacifiCorp s studies have estimated integration
costs at $5.50 per MWh.Another way of looking at these
integration costs is that they represent the decreased
value of wind energy as compared to some other type of
generation that does provide capacity whenever needed.
I will discuss later in my testimony, BPA began offering a
wind shaping and storage service in which the costs of the
servlce are based on BPA studies of wind integration costs.
BPA charges $6.00 per MWH for its storage and shaping
servlce for wind energy.
Idaho Power proposes that proj ects be required to
produce at least 90 percent of their estimated monthly
generation in order to receive posted avoided cost rates.
Do you believe this percentage is appropriate as a lower
limit?
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In the calculation of rates using the SAR, we
assume a capacity factor of 92 percent.In other words, we
assume that the gas-fired CCCT would operate 92 percent of
the time.The remaining eight percent of the time, the
plant would not be operational due to forced or unforced
outages (e. g., scheduled maintenance is an example of an
unforced outage; equipment breakdown is an example of a
forced outage) Thus, there is a greater than 92 percent
likelihood that the SAR would be able to generate at any
specific time since unforced outages would reasonably be
scheduled during times when the plant would not be expected
to be needed.Requiring non-utility generators to meet the
same standard in order to receive firm energy rates makes
some theoretical sense, however, I do not believe that many
potential proj ects could forecast their generation wi
such high accuracy.
If you do not believe 90 percent would be
attainable by most QFs, what do you suggest as an
al ternati ve?
First, I would recommend that a lower percentage
be set.Idaho Powe I believe 80 percent is reasonable.
has been providing reports to the Commission since December
2002 showing statistics concerning its PURPA contracts.
One statistic provided in the reports is a monthly
comparison of contracted generation to actual generation.
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In the past 19 months, Idaho Power s PURPA QFs have
delivered an average of 71 percent of their contracted
ene rgy .None of the projects included in the summary have
ever been held to their contract amounts, nor have any ever
revised their original contract amounts based on amounts
the proj ect has proven able to del i ver With incentives to
deliver at least 80 percent of their monthly generation
estimates and periodic opportunities to revise the
estimates, I believe that 80 percent is achievable by most
proj ect s
Second, I would recommend that proj ect owners be
given more frequent opportunities to revise their monthly
generation estimates than has been proposed by Idaho Power.
Rather than an initial six-month revision opportunity
followed by two-year intervals thereafter, I would
recommend six-month intervals for the duration of the
contract.That way, Idaho Power will at least have some
certainty, but project owners will be able to adjust for
the effects of expected water conditions.
s. Geothermal witness Kitz states in his direct
testimony that Idaho Power s draft contract makes no
allowance for forced QF plant outages, yet he points out
that in the event of a forced outage at one of Idaho
Power s own plants, it could recover 90 percent of any
resul ting higher power supply costs through its PCA.What
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is you opinion on this issue?
First, as stated by Idaho Power witness Gale and
as included in section 14.1 of the draft contract, Idaho
Power does , in fact, make an allowance for forced outages
by allowing a 72 -hour grace period during which the QF'
inability to perform is excused.I believe it
completely reasonable to include provisions in the contract
that excuse the QF during forced outages such as equipment
breakdowns because this is consistent wi th the treatment
Idaho Power s own plants receive through the PCA.However
a critical difference is that QF's are only allowed a 72-
hour grace period, while the utili ty' s is unlimited except
to the extent it would be subj ect to Commission scrutiny in
the PCA proceedings.To resolve this dispari ty in
treatment, I recommend that the grace period for QF
contracts be extended to 30 days.This would enable QF
proj ect owners time to diagnose problems, order replacement
equipment and make repalrs.
I do not believe that QFs should be held to
strict of delivery requirements as short-term firm energy
purchases utilities routinely make with each other.
However, I do believe it is reasonable to compare the
firmness requirements of QFs to those of the utility s own
generating resources.
Complainants in this case have obj ected to Idaho
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Power s proposed contract provisions that requlre
developers to pay Idaho Power liquidated damages based on
the additional market purchase expenses Idaho Power may
incur if developers do not deliver 90 percent of the energy
they have agreed to provide in any month.In response to
the complainants ' concerns about unlimi ted exposure to
market prices, Idaho Power has offered to limit developers
exposure to a dollar per MWh amount equal to 150 percent of
the net energy price for the month in which the shortfall
occurs mul tiplied by the shortfall amount.Do you be 1 i eve
this is necessary, and if so, do you believe it is
reasonable?
Yes, I do believe it is necessary to place a cap
on the potential exposure developers would face in the
event their proj ect is unable to meet the lower band,
whether the band is set at 90 percent or 80 percent.
Furthermore, I believe that the 150 percent cap proposed by
Idaho Power as described in Idaho Power wi tness Gale
Exhibi t No.2 02 is reasonable.
What about the 110 percent upper bound?Do you
think this is appropriate?
Again, I believe there is good rationale for
imposing an upper bound, but I think it creates an
unrealistically tight band.I would recommend that the
band be symmetric with the lower bound; thus, I recommend
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an upper bound of 120 percent.
Are there ways for the non-firm output from a
proj ect to be firmed?
Yes, there are.One way is to purchase firming
servlce.BPA has developed a service for regional public
utilities that buy fixed amounts of power from BPA as well
as for investor-owned utilities.The service integrates
the wind energy and stores it in the hydropower system,
delivering the power to the utility a week later in a
steady, predictable supply.For this service, for
utilities and other entities outside of the BPA control
area, BPA charges $ 6 per MWh.BPA provides a similar
service for publicly owned utilities within its control
area at a cost of $4.50 per MWh.I have attached a brief
description of BPA's wind integration service as Exhibi t
No. 105.Under BPA's program, participants are required to
pay any wheeling charges to deliver power to and to receive
power back from BPA's system.In addition, participants
are responsible for the cost of any losses along the way.
These charges would be in addition to the $6.00 per MWh
storage and shaping charge, so the total charge to
participate in this program could be much higher than $6.
per MWh.For large wind proj ects or those easily able to
deliver to and receive from BPA's control area, BPA's wind
integration service may be a viable option , but
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acknowledge that this service is not realistic for small
wind proj ects.
Another possibility is to use a battery storage
system to store energy for short periods of time and
deliver it later at a specific time and amount.I am not
very familiar with this technology for large scale
applications, but I have been told by Idaho Power personnel
that a wind developer in Montana (the same developer who
responsible for the recently signed United Materials
contract, IPC-04-01) has proposed to use such a system
and sell the output to Idaho Power if a prlclng mechanism
can be devised to accommodate on-peak and off -peak pricing.
A proj ect unable to perform wi thin the band such
as Idaho Power has proposed in this case might be able to
use either of these two methods to firm its output in order
to qualify for the posted avoided cost rates.The proj ect
owner would have to weigh whether it would be better to pay
for a firming service or install batteries and receive
posted energy rates, or whether the non-firm market-based
rate (Schedule 86) would provide a higher rate.
U. S. Geothermal witness Runyan discusses his
client's negotiations with Idaho Power in which he alleges
that Idaho Power had initially offered to purchase the
first 10 MW of U. s. Geothermal's output at the posted
avoided cost rate and any additional amounts at a
CASE NO. IPC-E- 04 - 8/IPC-E- 04 -
8/05/04
STERLING, R (Di) 22
STAFF
negotiated rate.He then goes on to explain that Idaho
Power has since withdrawn its earlier offer and he suggests
that u. S. Geothermal be ~grandfathered" to allow it such a
contractual arrangement if the Commission rules that the
proj ect is in fact larger than 10 MW.Wha t is your
response to his suggestion?
My posi tion is that u. S. Geothermal should not be
grandfathered.It is true that the Commission recently
approved a contract for Renewable Energy of Idaho wi th a
pricing scheme like the one described by Mr. Runyan.(See
Case No. IPC-04-05, Order No. 29487)The Commission
very reluctantly approved that contract, in part because of
Idaho Power s stated inability to compute a rate using the
prescribed methodology, in part because it did not wish to
delay Renewable Energy s progress on completing the proj ect
and in part because it did not wish to penalize Renewable
Energy for mistakes not of its creation.This case differs
in that u. S. Geothermal has not presented a signed contract
for Commission approval.In addition, I specifically
remember telling u. S. Geothermal on one or more occasions
that if it wanted to pursue a project 10 MW or larger , it
must request that Idaho Power compute a rate using the IRP-
based methodology.Finally, just because the Commission
approved one contract with posted rates for the first
, I do not bel ieve it should approve another.If it did,
CASE NO. IPC-04-8/IPC-04-8/05/04 STERLING, R (Di) 23
STAFF
all proj ects regardless of Slze could get posted rates for
the first 10 MW and Schedule 86 rates for all excess
genera t ion.The size threshold would not matter except for
determination of how much generation would be paid
posted rates.This approach would undermine the primary
rationale for the IRP-based methodology for over 10 MW
proj ects - that the IRP-based methodology produces more
accurate resul ts for large proj ects by being able to
account for proj ect specific generation characteristics.
Idaho Power has included a ~regulatory-out"
clause (Section 23.2) in its draft contracts to u.
Geothermal, Lewandowski and Schroeder that in effect
permits Idaho Power to terminate its contractual
responsibilities in the event deregulation is implemented
in Idaho in the future and Idaho Power is denied full
recovery of its QF contract costs.Do you bel ieve such a
clause is reasonable?
I do not support Idaho Power s insistence on
inclusion of a ~regulatory-out" clause in QF contracts.
While I would not characterize the utili ty ' s attempt to
include same as obstructionist or as anything other than
good faith , I believe such a clause is unnecessary to
protect the Company s economic interest and is further
prohibited by PURPA and FERC regulations.
A utility has no discretion under PURPA as to
CASE NO. IPC-04-8/IPC-04-
8/05/04
STERLING, R (Di) 24
STAFF
whether or not to purchase QF power.It federal
obligation to purchase.Similarly,entitled to
fixed rate contract for sale of power over fixed period
time.Once a QF contract and price are approved by the
Commission , QF costs pursuant to that price are no longer
at issue as to prudency.
The Company-proposed regulatory-out provlslon
conditions termination on a change in state law resulting
in Idaho Power being unable to fully recover in its retail
revenue requirement all costs attributed to the QF
purchase.The very next section of the Company-proposed
firm energy sales agreement is a provision that conditions
contract approval on a Commission declaration that all
payments made to Idaho Power be allowed as prudently
incurred expenses for ratemaking purposes.This provision
alone gives the utility all the assurance it should require
regarding the recovery of costs.The QF is also entitled
to certainty, a certainty that it will receive a fixed
price and stream of revenue through the life of the
contract, without a re-opener clause, without rate
revlslon, and assuming compliance with contract terms and
condi t ions, wi thout termination.The QF should not be
denied the certainty of an arrangement and the benefits of
its commitment as a result of changed circumstances.
Staff attorney informs me that the proposed
CASE NO. IPC-04-8/IPC-04-
8/05/04
STERLING, R (Di) 25
STAFF
regulatory-out clause gives the Commission continuing
jurisdiction over the avoided cost rate and subj ects the QF
to the same ~utility type regulations " precluded by PURPA
Section 210(e); implementing FERC regulations, 18 C.R. ~
292 .602 (c) (1); by federal Courts; by State Supreme Courts
and by the I daho Supreme Court.
Does this conclude your direct testimony in this
proceeding?
Yes, it does.
CASE NO. IPC-E- 04 - 8/IPC-E- 04 -8/05/04 STERLING, R (Di) 26
STAFF
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6
BIBLIOGRAPHY
Articles
Dragoon, K., Milligan, M.
, "
Assessing Wind Integration Costs with
Dispatch Models: A Case Study ofPacifiCorp.
WINDPOWER 2003 , May 18-2003.
Parsons, B., Milligan, M., Parsons, B., Zavadil, B., Brooks, D., Kirby, B., Dragoon, K.
Caldwell, J.
, "
Grid Impacts of Wind Power: A Summary of
Recent Studies in the United States.
European Wind Energy Conference, June 2003.
Hirst, E., Hild, J.
, "
Integrating Large Amounts of Wind Energy
with a Small Electric-Power System.
Brooks, D., Lo, E., Zavadil, B., Santoso, S., Dragoon, K., Milligan, M., Hirst, E.
Parsons, B., Kirby, B., Caldwell, J.
, "
Wind Power Impacts on Electric-Power Operating Costs
Summary and Perspective on Work Done to Date November 2003.
Exhibit No. 104
Case Nos. IPC-04-
IPC- E-04-1 0
R. Sterling, Staff
8/05/04
BP A Wind Integration Services
Over the past two years, BP A has
undertaken an extensive research and
development effort to evaluate the costs and
opportunities associated with integrating
wind energy into the Federal Columbia
River Hydroelectric System (FCRPS). This
evaluation phase is now complete and we
are pleased to announce two new services
that will utilize the flexibility of the hydro
system to integrate wind energy into our
control area on behalf of electrical utilities
in the Pacific Northwest. BP A has
established a goal of providing up to
450 MW (nameplate) of wind integration
services over the 2004-2011 time period. At
least 200 MW of these services will be
earmarked for public power customers.
Network Wind Integration Service
Network Wind Integration Service has
been designed to serve the needs of public
power customers with loads embedded in
the BP A control area who elect to purchase
all or a portion of their power from a new
wind resource. Once the customer has (a)
signed a bilateral power purchase agreement
with a new wind resource, (b) procured firm
transmission and (c) determined a
scheduling agent for the power, the BPA
Power Business Line will use its hydro
system to integrate the scheduled output of
the resource with the customer s load. The
scheduled energy from the wind resource
will offset an equal amount ofHLH and
LLH PF energy that BP A otherwise would
have provided. BP A will continue to meet
and follow the customer s load at all times
including during those periods when there is
no output from the wind resource. The
customer s PF demand billing determinant
will not be reduced for the amount of wind
generation scheduled to its load on the hour
of the generation system peak. BP A PBL
March 2004
cannot count on the generation being there
and thus must hold sufficient generating
capacity available to fully back up the
resource. The PF Load Variance charge will
continue to be based on the customer s Total
Retail Load, so will not be reduced by the
amount of wind generation.
The customer will be charged a fee of
$4.50/MWh for all scheduled energy that
BP A integrates into its system. This fee may
be subject to annual escalation depending on
the length of the requested contract. For
contracts that extend beyond the current rate
period, the fee will be escalated at the rate
associated with the Gross Domestic Product
Implicit Price Deflator, which is the same
index used to escalate the Federal
Production Tax Credit for wind,
NetworkWind Integration$ervice
MWh
IMIJ 'kdIM~~1Pdj\'i1'r4u,(o~J:,,"'\i;"t;,..1;\!ln"~IIi1#1
+----+'- er.erg1Di;i~w$dl~
ti~b:;fi~I' b)l1;i'A('\I~t~(LQ~41Wt Of
Wi,id !'rtej~t Outpm:!
Transmission
With respect to transmission, customers
will be able to import power from new
resources using their NT transmission rights.
BP A will work with public power customers
and wind proj ect developers to identify
regions of the BP A grid best suited for wind
development with respect to the availability
IONHtVlltE
",-... '.-~'-"""~"~'
~:~;b
~ O iP~~ E-O4-8/
IPC-04-
R, Sterling, Staff
8/05/04 Page 1 of 3
of firm transmission, BP A plans to take an
active role in developing a diversified
portfolio of regional wind resources, This
diversification will be a key factor in
increasing the amount of wind energy
selling into the BP A grid.
Network Wind Integration Service
TransmIssion
On,e l'r/iflsmbsionWheel Using (ustomet's
Netwdrk'fnmimisilon Rlglm
Scheduling and Generation Imbalance
The customer (or its scheduling agent)
will be responsible for transmission
arrangements and for scheduling the wind
output from the point where the generation
is integrated into the BP A transmission
system to a point of delivery where the
customer s system interconnects with the
BPA transmission system. Generally, the
customer will need to request a new Point of
Receipt under its NT transmission contract
and there is no guarantee that firm
transmission capacity will be available.
The wind project operator or its
scheduling agent will provide the
Transmission Business Line with a Day-
Ahead Generation Estimate followed by
revisions up to 30 minutes before the start of
the hour if changes are required. The proj ect
operator will be responsible for paying the
BP A TBL Generation Imbalance charges for
deviations between wind project actual
generation and the Generation Estimate,
March 2004
Whether the project operator directly assigns
these generation imbalance costs to proj ect
participants or not will depend on the
specific contractual agreements between
those entities. Accurate wind forecasting
will minimize these charges, If changes are
made to the Generation Imbalance tariff in
the future, these changes will be amended to
the Network Wind Integration Service
Contract.
Storage and Shaping Service
Storage and Shaping Service has been
designed to serve the needs of utilities and
other entities outside of the BP A Control
Area who have chosen to purchase the
output of a new wind resource but do not
want to manage the hour-to-hour variability
associated with the wind output. To
facilitate such an arrangement, BP A's Power
Business Line will take the hourly output of
new wind projects physically located and/or
scheduling directly into the BP A Control
Area, integrate and store the energy in the
Federal hydro system, and redeliver it a
week later in flat peak and off-peak blocks
to the power purchasing customer. In order
to help reduce transmission costs, returns
will be capped at 50 percent of the
participant's share of project capacity. The
base charge for storage and shaping service
is $6.00/MWh, escalated annually at the
GDP Implicit Price Deflator.
Transmission
Storage and Shaping Service is for
energy delivered to and from the BP A
system. Thus, two transmission wheels are
required to receive the service. Generators
will be responsible for Generation
Imbalance charges for generation scheduled
into the BP A system. BP A expects that the
transmission arrangements will vary from
project to project, depending on (a) the
Exhibit No. 105
Case Nos, IPC-04-
IPC-04-
R, Sterling, Staff
8/05/04 Page 2 of
locations of the project and the end-use
buyer, and (b) the availability of firm
transmission along both transmission paths.
Storage& Shaping Service
Power Redelivery
Red~livery
Volumes
Production
~~r"..jwt-"",
.:\cl\....4i..81'A~ri\~,j - -
:'of.
'N",~kl
~~I;~"MfW""","..,."",,_a~1\
W~k2 W~6k,
-- -
1~""""'OotW!,~iolb'(~~~~% ",%!,*r-V"Aw.:4ikw","~~.-.t,~W;4woJ"'t
-W~;.I~"~Wj(~'f;-
1hiS$~rvkEJi~f'foef gy neutr;:\ I.
BP A is committed to working with
potential customers to minimize the
transmission costs associated with Storage
and Shaping Service. So far, we have been
able to limit the cost of the wheel out of our
system by agreeing to cap returns at 50% of
the nameplate rating of the participating
project. During periods when generation
exceeds the 50% threshold (i,e. greater than
50 MW on a 100 MW project), BPA will
bank this excess energy in a storage account.
When generation falls below the 50%
threshold, BP A will draw from the Excess
Storage & Shaping Service
Transmission
,2J!!E 1/Ml4ri6$i,,". m1,,1IfA $Ylwm.
",,:
r,""""Mi~"~"1 (I/'$!'A); ""PI""! 0\ W*,~.fw"J;"1 """"1iol"o"1'",Jly.
Customer pun:hases point-to.poil\t transmission out of W'A's
Control Area Into their own area.
March 2004
Energy account and redeliver additional
quantities above and beyond the current
redelivery obligation. This will reduce the
amount of transmission required to move the
stored energy out of the BP A system. We
are also examining a number of potential
cost-saving approaches to the transmission
wheel into our system.
BP A plans to work closely with project
developers, Investor Owned Utilizes and
other entities with well-developed and active
purchasing plans to help determine which
projects can be most efficiently integrated
into the BP A system. Siting projects in areas
of the grid with minimal congestion and in a
way that takes advantage of regional
diversity in wind patterns is essential to the
growth of cost-effective wind energy in the
Pacific Northwest.
For More Information
To learn more about Network Wind
Integration Service or Storage and Shaping
Service, please contact your PBL or TBL
Customer Account Executive or the BP
PBL Renewable Power Group at (503) 230-
3530. We look forward to working with you
on these exciting new services.
Exhibit No.1 05
Case Nos. IPC-04-
IPC- E-04-1 0
R. Sterling, Staff
8/05/04 Page 3 of 3
. ON HIYI L l Ii~":!Xi'
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 5TH DAY OF AUGUST 2004
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE
NOS. IPC-04-08 / IPC-04-, BY MAILING A COpy THEREOF POSTAGE
PREPAID TO THE FOLLOWING:
BARTON L KLINE
MONICA MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
JOHN P PRESCOTT
VP - POWER SUPPLY
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
CONLEY E WARD
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
DANIEL KUNZ
PRESIDENT
S. GEOTHERMAL INC
1509 TYRELL LANE SUITE B
BOISE ID 83706
PETER J RICHARDSON
RICHARDSON & O'LEARY PLLC
PO BOX 1849
EAGLE ID 83616
DON READING
BEN JOHNSON ASSOICA TES
6070 HILL ROAD
BOISE ID 83703
JAMES F FELL
STOEL RIVES LLP
SUITE 2600
900 S W FIFTH AVE
PORTLAND OR 97204
BOB LIVELY
ACIFICORP
ONE UTAH CENTER, 23 RD
201 S MAIN ST
SALT LAKE CITY UT 84140
R BLAIR STRONG
PAINE HAMBLEN COFFIN BROOKE
& MILLER LLP
SUITE 1200
717 W SPRAGUE AVE
SPOKANE WA 99201-3505
CLINT KALICH
MANAGER OF RESOURCE PLANNING
AND ANALYSIS
VISTA CORPORATION MSC- 7
PO BOX 3727
SPOKANE WA 99220-3727
~llv~. k'~.
SECRETARY
CERTIFICATE OF SERVICE