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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
U . S. GEOTHERMAL, INC.,an Idaho corporation,
Complainant,
vs.
IDAHO POWER COMPANY,an Idaho corporation,
Responden t .
BOB LEWANDOWSKI and MARK
SCHROEDER
Complainants,
vs.
IDAHO POWER COMPANY,an Idaho corporation,
Responden t .
CASE NO. IPC-O4-
CASE NO. IPC-O4-
IDAHO POWER COMPANY
DIRECT TESTIMONY
JOHN R. GALE
Please state your name and business address.
My name is John R. Gale and my business
address is 1221 West Idaho Street, Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by Idaho Power Company Idaho
Power or the Company) as the Vice President of Regulatory
Affairs.
Please describe your work experience.
In October 1983, I accepted a posi tion as
Ra te Analys t wi th Idaho Power Company.In March 1990, I was
assigned to the Company s Meridian District Office for one
year where I held
March 1991,I was
1997,I was named
the posi tion of Meridian Manager.
promoted to Manager of Rates.In July
General Manager of Pricing and Regulatory
Services.In March of 2001, I was promoted to Vice
President of Regulatory Affairs.As Vice President of
Regulatory Affairs, I am responsible for the overall
coordination and direction of the Pricing & Regulatory
Department, including development of jurisdictional revenue
requirements and class cost-of-service studies, preparation
of rate design analyses, and administration of tariffs and
customer contracts.In my current posi tion, I am
responsible for policy matters related to the economic
regula tion of Idaho Power Company.I am also a member of
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the Company s Risk Management Committee which is charged
wi th balancing the Company s loads and resources on a short-
term basis.Finally, in conjunction with the Company
Senior Vice President for Power Supply, I am sponsoring the
Company s 2004 Integrated Resource Plan which assesses the
Company s loads and plans for resources on a long-term
basis.
What topics will you discuss in your
tes timony in thi s proceeding?
I will explain why the Company has developed
a standardized Firm Energy Sales Agreement ("FESA") that can
be uniformly applied to all small qualifying facili ty ("QF"
generating technologies.
I will explain why the Company is proposing to
include provisions in the FESA that encourage QF developers
to provide firm energy rather than non-firm energy.I will
discuss the specific provisions the Company is proposing
include in the FESA to encourage greater "firmness " and
explain why these provisions are fair to both QFs and to the
Company s cus tomers .
I will also discuss why the Commission needs to
approve a standard methodology the Company can apply to
determine if a particular QF project is larger than 10 MW.
I will discuss the pros and cons of using ei ther average
annual energy or nameplate capaci ty to decide if a QF
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proj ect is larger than 10 MW.I will also explain why the
Company believes using metered energy amounts to determine
whether or not a particular QF is larger than 10 MW is the
best approach to this problem.
I will explain why the Company needs to include a
contract provision that gives the Company the right to
terminate QF contracts if electric utili ty industry
deregulation prevents the Company from recovering stranded
expense associated wi th above-market QF contracts.
I will also address other issues raised by
Complainants ' prefiled direct testimony.
Why is the Company proposing a standardized
contract for QF' s smaller than 10 MW?
The Company has developed a s tandardi zed
contract approach that can be applied uniformly to all QF
proj ects wi th a capaci ty smaller than 10 MW regardless of
generation technology.It works equally well for
intermi t tent resources like wind and solar, resources wi
seasonal variations, like hydro and geothermal, and process-
driven resources such as industrial cogeneration and
biomass.This standardized approach simplifies the
contracting process and provides economic incentives for
the QF developer to accurately estimate the amount of energy
it will provide each month.By providing economic
incentives for QF developers to more accurately estimate the
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amounts of firm energy they will deliver each month, the
Company is hoping to encourage QF developers to deliver firm
energy rather than non-firm energy.Obtaining better
estimates of the monthly amounts of firm energy to be
provided will improve Idaho Power s abili ty to integrate QF
resources into its resource planning and acquisi tion process
as firm resources.
Idaho Power also believes that a key benefit of the
Company s contract approach is that it allows intermittent
QF resources such as wind and solar that are inherently non-
firm an opportuni ty to be paid firm energy prices for at
least a portion of their generation.
Please describe the difference between firm
and non-firm energy purchases.
Idaho Power s rate Schedule 86 governs
purchases and sales of non-firm energy from QF' s.Non-firm
energy is defined in Schedule 86 as energy sold by the QF to
the Company on a "non-firm, if, as, and when available
basis. "(Idaho Power Company, IPUC No. 26, Tariff No. 101,
Third Revised Sheet No. 86-A QF seller of non-firm
energy can increase or curtail its energy deliveries to
Idaho Power at any time without prior notice and without any
economic consequence.
Idaho Power purchases hundreds of thousands of MWh'
of firm energy each year.Sellers under these firm energy
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purchases contractually commi t to deliver energy at the
times and in the amounts specified in the contract.In non-
QF firm energy contracts, failure to provide the specified
amount of energy at the agreed-upon time results in the
payment of damages, ei ther actual damages or liquidated
damages
Aren't most of the 71 contracts Idaho Power
has signed with QF's "firm energy " contracts?
The contracts Idaho Power signed wi th
developers prior to 2003 describe the energy deliveries as
firm. "In reali ty, the actual firmness of the energy
deliveries under these pre-2003 contracts more closely
resembles non-firm energy deliveries than firm energy
deliveries.This is because there is no requirement for QF
developers to actually deliver energy in the amounts and at
the times they say they will in the Firm Energy Sales
17 . Agreement.As a resul t, the utili ty only has a general idea
how much energy it can expect to receive from any QF at any
time.The amount of energy delivered can fluctuate between
0 MW and 10 MW, hour to hour, day to day, month to month,
completely at the discretion of the QF.
If this type of contract has been the norm
historically, why is the Company now seeking to improve the
firmness or predictability of QF energy deliveries?
Condi tions have materially changed since
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1996, when the Company entered into the last Firm Energy
Sales Agreements that did not require any monthly energy
commitment from the QF developer.These changed condi tions
inc 1 ude :(1) Wholesale markets have standardized the terms
and condi tions of wholesale firm energy transactions. As a
resul t, wholesale firm energy purchases from credi tworthy
counterparties are now generally accepted as a prudent and
cost-effective way of meeting a portion of a utili ty ' s
resource needs.Idaho Power s recent IRP's reflect that
reali ty.(2) Idaho Power has changed from an energy-
constrained company to a capaci ty-constrained company.
Seasonal peaks require the Company to have a high degree of
confidence that energy purchases will be delivered in the
amounts and at the times specified to match seasonal peak
energy demands.(3) Transmission constraints require that
the Company more precisely anticipate its needs for firm
energy imports.The abili ty to predict the output of
resources within the utility s control area is increasingly
important.(4) The growing prominence of intermi t tent
genera ting technologies, such as wind and solar, require a
new approach in the Company s PURPA contracting procedures.
(5) The Company s increased use of firm market purchases as
hedges to manage risk under its Commission-approved Risk
Management Policy escalates the importance of predictable
resource availabili ty.
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Complainants ' wi tness Dr. Reading testifies
that QF contracts are "a mere drop in the bucket to a
utili ty the size of Idaho Power.Does QF ou tpu t really
have any impact on Idaho Power s resource planning?
Yes.QF resources are no longer "a mere drop
in the bucket to a utili ty the size of Idaho Power.
(Reading, Direct, page 9) .As a result of my involvement in
the development of the Company s 2004 Integrated Resource
Plan, it has become clear to me that Idaho Power
assumptions on QF output, especially during summertime peak-
load hours, has a direct impact on Idaho Power s need for
fu ture resources.As I noted earlier in my testimony, Idaho
Power has changed from an energy cons trained company to a
capaci ty constrained company.Idaho Power s need for
additional resources is driven by transmission constraints
encountered during summertime peak-hour load periods.Since
almost of Idaho Power s QF' s are located east of the
Brownlee East constraint and inside Idaho Power s control
area, QF output has a direct impact on Idaho Power
calculation of transmission deficits or transmission
overload.proj ected summertime transmission overloads will
drive the need for new peaking resources.
During 2003, Idaho Power purchased about 75 aMW of
QF generation, yet the nameplate capaci ty of the QF
facili ties under contract is 182 MW.Idaho Power is
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currently aware of approximately 200 MW (nameplate rating)
of addi tional QF proj ects in various stages of development.
that are interested in selling energy to Idaho Power.
these potential proj ects are combined wi th the existing QF
proj ects currently under contract, the total is close to
400 MW.This is not an insignificant amount of capacity.
The better that Idaho Power unders tands the month - by-mon
capability and projected out put of these projects, the
better Idaho Power can assess its future resource needs.
Can you summarize the contract provisions
that Idaho Power has proposed to include in FESA's to
provide the higher level of resource predictabili ty you
describe?
Yes.In Section 6.2 of the FESA, Idaho Power
requests that the QF developer quantify the amount of Net
Energy, in kilowat t hours, that the developer intends to
deliver each month.
When you cite a FESA Section number, what
FESA are you referring to?
The section references in this testimony
refer to the sections in the Draft FESA identified as
Exhibi t C to U. S. Geothermal's Complaint.
Please continue.
Section 6.1 allows the QF developer to
revise its monthly Net Energy amounts six months after the
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initial operation date, twelve months after the operation
date, and then every two years thereafter.At any time the
net energy commitment amount can be temporarily reduced
(Section 6.2) if the proj ect is affected by an event of
force maj eure or if the proj ect experiences a forced outage
(Sections 14. 3 . 1 and 14.4. 1) .
As a resul t , Idaho Power s proposed FESA provides
substantial flexibility to allow the QF developer to
determine, based on its own judgment and experience, the
amount of net energy that the project will commit to deliver
each month, and provides flexibility to make adjustments to
that commi tment if unforeseen circumstances arise.
Please continue.
Once the developer has determined how much
energy it is comfortable in commi tting to provide each
month, Idaho Power will include that firm energy amount in
its resource planning and acquisi tion process.
If the QF developer subsequently delivers more
energy in a month than Idaho Power had planned for, it is
possible that Idaho Power will have to sell that energy in
the surplus market or back-down a more economic production
plant.If the QF subsequently provides less than the amount
committed, it is possible Idaho Power would have to make
addi tional firm purchases on the wholesale market to cover
that shortfall.
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To address that situation, the proposed FESA
includes provisions to provide an economic incentive for the
QF developer to actually deliver the amount of energy it
indicated it would provide to the Company each month.
the QF delivers a monthly average amount of energy that
exceeds 110% of the commitment amount, such excess energy
(up to 10,000 kWh per hour) is purchased at the same rate
the Commission has approved for non-firm energy purchases in
Schedule 86.Surplus Energy , Section 1.
If the QF fails to deliver 90% of the energy it had
committed to provide, and that failure is not due
circums tances beyond its con trol such as forced au tages
force maj eure even ts, the proposed FESA provides for
liquidated damages to compensate the utili ty and its
customers for having to acquire energy to make up the
shortfall.Shortfall Energy , Section 1.21)
What do you mean by "events of force majeure
and forced outages
Section 17.1 of the FESA is the force majeure
section.If the QF developer is unable to meet its
commi tment amount as a resul t of events of force maj eure
(acts of God, etc.), its performance obligation is excused
and any shortfall energy amount is reduced accordingly.
addi tion, Section 6.2 provides that if the QF facili ty
experiences a forced outage during the month, any shortfall
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energy amount is appropriately reduced.Forced outages
include generating equipment breakdowns, geothermal well
breakdowns, Idaho Power line maintenance outages, etc.As a
result, events that are truly beyond the control of the QF
developer do not expose the QF developer to any liquidated
damages.
Does the FESA provide other limi ts on the
QF's obligation to pay for energy shortfalls?
The FESA proposed by Idaho Power places
reasonable limi ts on the QF developer s obligation to pay
for shortfall energy in several ways.First, as noted
above, if the QF project's failure to supply the 90% of
commi tted energy is due to ei ther force maj eure condi tions
or a forced outage, Section 6.2 provides relief.Second,
as provided in Section 1.9, the market price used to compute
liquidated damages is only 85% of the monthly weighted
average of the actual Mid-C prices. By using 85% of the
monthly weighted average of the Mid-C prices, QF developers
are immediately shielded from 15% of the actual Mid-C price.
If 85% of the Mid-C market price is less than the monthly
price in the FESA, the QF pays nothing.Third, Idaho Power
has offered to limi t the Complainants ' shortfall exposure
when 85%the Mid-
monthly FESA price by
the contract price.
market price is greater than the
capping liquidated damages at 150% of
This protects the QF from extreme price
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run-ups such as those occurring in 2000-2001.
Is this offer to cap the liquidated damages
to 150% of the contract price contained in the FESA?
No.Idaho Power made this offer in letters
to each of the Complainants dated May 21, 2004.Copies of
the letters are attached as Exhibits 201 and 202.
In their testimony the Complainants argue
that requiring them to commi t to a monthly firm energy
amount is extremely unfair.Do you agree that requiring
such a commi tment is unfair?
No.While I can understand that the QF' s
would like to have complete discretion in scheduling energy
deliveries, I do not believe it is unfair for Idaho Power to
require some commi tmen t on their part.All of the
Complainants have testified that their projects are
extremely reliable.The Complainants are in complete
control of the amounts they commi t to provide and Idaho
Power will rely on the representations of the QF developer
in making its resource and system planning decisions.
The FESA provides that if the proj ect experiences
events of force maj eure or forced outages, the commi tment
level is adjusted to recognize those contingencies.
Are there other measures that you believe
make the commitment obligation equitable?
Yes.The commitment amount is a total
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monthly kWh amount.The QF is free to generate at maximum
levels (up to 10,000 kWh per hour) for some hours during the
month and generate at lower levels in other hours in order
to meet the monthly commi tment amount the QF chose.
In my mind, the only things that would subj ect the
QF developers to shortfall energy payments is if their
proj ections of monthly generation amounts are too high
because they have overestimated the efficiency of their
proj ects or equipment, or they assumed temperature
variations that are not realistic or, in the case of the
wind generation, the developers have overestimated the
amount of wind that will be available.All of those
estimates are completely within the control of the QF
developers, not Idaho Power.In the case of U. S .
Geothermal, a shortfall could also occur if U. s. Geothermal
decided to divert energy from Idaho Power to serve other
internal loads or to make sales to another enti ty who is
willing to pay a higher price.
Throughout their testimony, various
Complainants ' Wi tnesses refer to Idaho Power s proposed
shortfall energy amount as a "penalty.Dr. Reading takes
specific issue wi th Idaho Power s characterization of
shortfall energy as liquidated damages.Could you address
these cri ticisms?
I expect that Complainants ' wi tnesses are
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repea tedly using the term penal ty because they know courts
generally do not enforce penal ties in contracts.I believe
that the Company s proposal to use average Mid-C pricing is
not a penalty but is a reasonable way of computing
liquidated damages.
Dr. Reading s brief definition of liquidated damages
contained in his testimony is generally correct.Where Dr.
Reading s analysis falls down is his assumption that the
Company could precisely calculate the damages it suffered
the QF fails to deliver the agreed-upon amount of energy.
Dr. Reading states:First, the underlying reason for
liquidated damage clause is missing.If a power supplier
breaches its commitment to deliver power to an investor-
owned utili ty such as Idaho Power, that IOU has tools
readily at its disposal for calculating whether, and by how
much, it is damaged.
I believe Dr. Reading is incorrect when he states
that Idaho Power can readily calculate whether and how much
it was damaged by the QF developer s fai ure to supply an
agreed-upon amount of energy.First, the amount of energy
shortfall is based on a monthly total. Idaho Power engages
in numerous wholesale purchases and sales during a month.
Sometimes Idaho Power makes purchases and sales
simultaneously in an hour as a result of changed conditions,
prior commi tments, etc.The Company may also run different
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generating resources at different times during a month.
the QF developer has failed to deliver the required amount
of energy in a month, would it be fair to allow Idaho Power
to choose which transactions in the month it will attribute
to the QF' s failure to perform? Could the Company select,
for example, all purchases at Palo Verde prices during
heavy-load hours or all hours when Danskin is generating as
the measure of its damages for the QF' s failure to perform?
I don t think that would be fair to the QF.At the same
time, it is unfair to assume that the QF' s failure to
deliver has no cost impact on the Company s power supply
expens e This is why a liquidated damages solution is the
most equi table approach for both the utili ty and the QF.
Complainants ' wi tness Dr. Reading states that
the fact that in 2002-2003 the QF' s currently selling energy
to Idaho Power provided approximately 70% to 75% of the
energy they originally agreed to provide demons tra tes
proj ects are reliable.Could you please comment on this
portion of Dr. Reading s testimony?
Dr. Reading correctly notes that in the
aggregate the QF's selling energy to Idaho Power in 2002-
2003 provided approximately 70% to 75% of the energy they
originally agreed to provide.However, this statistic
really does not provide much useful information on QF
reliabili ty. The percentage only measures the difference
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between the QF developer s estimates of annual generation
made 10 or 20 years ago and their actual generation for 2002
and 2003.In addi tion, the 70% figure Dr. Reading quotes is
an average of all 69 proj ects currently selling energy to
Idaho Power.In actuali ty, the percentage variation between
developers ' estimates and actual performance varies greatly
by generation type.For example, in 2003 the thermal QF
projects selling to Idaho Power delivered from 80% to 100%
of the amount they estimated originally.The QF hydro
projects using spring water or located on waterways with
access to upstream storage generally (but not always) had
higher levels of performance than did QF hydro projects
located on rivers or creeks without upstream storage.
Lumping the performances of all types of QF proj ects
together and computing an average number for all of the
different QF projects really does not provide much useful
information to predict QF performance on a monthly basis. It
is this monthly generation information that resource
planners really need to make the most efficient resource
acquisi tion decisions.
All of the Complainants in this case have testified
as to how reliable they will be.Idaho Power has no way to
independently assess the accuracy of those predictions.
Under the contract form that Complainants desire to receive,
there is no economic incentive to accurately estimate
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potential generation.As a resul t, for resource planning
purposes, Idaho Power will never really know how much energy
to expect from a particular QF in any month under these old-
style contracts.That is one of the reasons Idaho Power is
asking the QF developers to make a commi tment to provide a
firm amount of energy each month.Without such a provision,
QF developers have no incentive to provide an accurate
estimate of the energy they will actually provide.
Complainants ' wi tness Dr. Reading states that
Idaho Power s proposal to require QF developers to commi t to
a monthly energy amount is intended to prevent the
development of new QF' s.Is he correct?
Of course not.Idaho Power included this
requirement to encourage QF developers to provide firm
energy in exchange for firm energy prices.As I noted
earlier in my testimony, much has changed since the early
1980'The types of resources Idaho Power needs, the ways
Idaho Power plans to acquire resources and the ways it makes
resource purchases is much different today than it was just
a few years ago.I do not believe it is unreasonable for
the Company to ask QF developers to accept reasonable
contract requirements that enable the Company to integrate
QF resources in today s resource planning and acquisition
environment.
Wi tnesses for both Complainants argue that by
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Idaho Power Company
requiring them to contractually commit to a monthly energy
amount, Idaho Power is requiring QF proj ects to comply wi
more stringent standards than its own proj ects are subj ected
to.How do you respond to this cri ticism?
The cri ticism is inaccurate.For example, on
page 7 of his testimony, Dr. Reading states:When a
utility s own plant fails to produce or has an unscheduled
outage, the ratepayers cover the cost associated wi
replacing the output from that plant.The shareholders are
held harmless.In making that s ta temen t , Dr. Reading
(1) inaccurately characterizes the operation of the
Company s PCA mechanism;(2) fails to acknowledge the
ongoing oversight by the Commission and its Staff; and
(3) ignores the terms and conditions of the FESA.
Why do you say Dr. Reading inaccurately
represents the operation of the PCA?
Except for QF purchases between general
revenue requirement proceedings, the Company only collects
90% of increases to its purchase power expense.The
Company s shareholders bear a portion of the Company
purchase power risk and thus the Company is incented to make
the best decision on every purchase transaction it
undertakes.This risk sharing is not unlike the 90%-110%
band Idaho Power has included in its FESA.
Why do you say Dr. Reading fails to
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acknowledge the ongoing oversight of the Commission and the
Staff?
In each PCA proceeding, the Commission Staff
closely audi ts the Company s power supply expenses.The
most recent example of this oversight occurred in the
Company s most recent PCA case.In Order No. 29506, the
Commission ci ted the Staff audi t and directed Idaho Power
and the Staff to undertake additional analysis of a specific
forced outage that occurred at the Valmy Plant last summer.
Under the PCA specifically and as a regulated electric
utili ty generally, the Company s operating practices and the
costs of power from its generating plants are subj ect
prudency review on an ongoing basis.
Why do you say Complainants ' cri ticism
ignores the terms and condi tions of the FESA?
Complainants' testimony ignores material
provisions of the FESA.On page 7, ine 5, Dr. Reading
states:Idaho Power wants to have the best of both worlds
by placing the risk of unscheduled outages on QF developers
while enjoying the advantage of placing the risk of
unplanned outages at their own plants on the ratepayers.
In fact, in the FESA Idaho Power does not place the risk of
unplanned outages on the QF developers.As noted above,
force maj eure events and forced outages reduce or eliminate
shortfall energy amounts.(Section 6.2 and Section 17.1) .
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This includes outages due to Idaho Power line construction.
(Section 6.2) .Idaho Power is providing symmetrical
treatment between QF contracts and Company owned generating
resources.
Are there other problems wi th Complainants
comparison of QF contracts and Company owned rate based
plants?
Yes.Comparing a QF Firm Energy Sales
Agreement to a utility s regulated generating resources
comparing apples and oranges.A utility-owned resource,
once it is included in the utility s rate base and becomes
operating property, is subject to ongoing regulation by the
Commission in a number of ways.For example, the Company
return on its plant investment changes depending on the
then-current rate of return allowed by the Commission.
the utility s costs of capital decline, the Company s return
on its investment in generating facilities is reduced.This
benef i ts cus tomers .That's not the case for a QF proj ect.
Because the QF sells energy under a firm power purchase
agreement and is not rate regulated, if interest costs
decline, the QF can refinance its project at the lower debt
cost and its equi ty owners retain 100 percent of the benefi
of the refinancing.
Another difference between the utility s rate-
regula ted generating resource and the FESA power purchase
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agreement is that the utili ty ' s generating plant is
dedicated to serve utility customer loads.Onc e the
utili ty-owned generating plant becomes operating property,
the utility does not have the right to sell the plant or
direct the output away from serving its native load
customers wi thout commission approval.A QF is not so
encumbered. For example, when Boise Cascade decided to close
the Emmett mi 11 and cancel the Emmett QF con trac t , it did so
at the height of the Western Energy Crisis.The
cancellation occurred at the only time during the life of
the Emmett FESA that prices under the FESA were less than
wholesale market prices.Our customers would have benefited
if Boise Cascade had not cancelled the Emmett FESA.Boise
Cascade paid the liquidated damages and immediately began to
investigate if it would be cost-effective to operate the
Emmett QF facili ty at the higher wholesale market prices.
Ultimately they determined not to continue to generate at
Emmett.
I provide this example not to cri ticize Boise
Cascade.They did not cancel the Emmett QF FESA to take
advantage of high wholesale electrici ty prices.Bu t they
did act in a manner consistent wi th their business interest
wi thout regard to the impact on Idaho Power or its
cus tomers .I believe this example illustrates a key
difference between a utility resource dedicated to serve
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cus tomer loads and a FESA.
I am not pointing out these differences to
demonstrate that utili ty resource ownership is superior to a
power purchase agreement wi th a QF.Both types of resource
have a place in Idaho Power s resource portfolio.My only
intent is to demonstrate that it is impossible to draw
direct comparisons between a utili ty-owned, rate-regulated
generating plant and a power purchase agreement with a QF.
The appropriate comparison is between a firm energy purchase
from the QF and a firm energy purchase from another
credi tworthy wholesale market participant.
u. S. Geothermal Wi tness Runyan testifies that
the contract provisions the Company is proposing to include
to increase the firmness of the QF's commitment are
inconsistent wi th PURPA avoided cost pricing.Do you concur
with his analysis?
No.In considering Mr. Runyan s testimony,
it is important to remember that PURPA provides that avoided
costs are based on the costs the utili ty can avoid by
purchasing from the QF rather than building a resource
itself or purchasing addi tional resources on the wholesale
market.(16 U.C. ~824a3 (d))By including the firming
provisions in the QF contracts, the Company is attempting to
more closely align the firmness of energy purchases under
the QF contracts with firm energy purchases it makes every
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Idaho Power Company
day in the wholesale market.Idaho Power believes including
contract provisions to encourage firm energy deliveries from
QF's is consistent with PURPA.
Do the FERC regulations implementing PURPA
support the Company s posi tion?
I believe they do.18 CFR ~ 292, et. seq.
are the FERC regulations which govern QF purchases.18 CFR
~ 292.304 (e) states in pertinent part:
(e) Factors affecting rates for
purchases. In determining avoided cos ts, the
following factors shall, to the extent
practicable, be taken into account:(2) The availabili ty of capaci ty
energy from a qualifying facility during the
system daily and seasonal peak periods,
inc 1 uding (i) the abili ty of the utili ty
dispatch the qualifying facility;(ii) The expected or demonstratedreliabili ty of the qualifying facili ty;
(iii) The terms of any contract or
other legally enforceable obligation,
including the duration of the obligation,
termination notice requirement and sanctions
for non-compliance;
(iv) The extent to which scheduled
outages of the qualifying facility can be
usefully coordinated wi th scheduled outages of
the utility s facilities;(v) The usefulness of energy and
capaci ty supplied from a qualifying facili ty
during system emergencies, including itsabili ty to separate its load from itsgeneration;
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Idaho Power Company
(vi) The individual and aggregate
value of energy and capacity from qualifyingfacili ties on the electric utili ty ' s system;and
(vii) The smaller capaci ty incrementsand the shorter lead times avai lable wi
addi tions of capaci ty from qualifyingfacili ties; and
I believe that all of the provisions that Idaho
Power is proposing to include in QF contracts are consistent
wi th the factors described in subsection (2) stated above.
The provisions are intended to increase Idaho Power
ability to predict when QF generation will be available so
the Company can integrate QF generation into the utility
resource and system planning process.They are intended to
increase the firmness and dispatchabili ty of the QF
resources.They are intended to define any sanctions for
non-compliance.It certainly appears to me that what the
Company is proposing to do is completely consistent with the
intent of PURPA.
You indicated previously that the Commission
needs to decide how the Company will determine if a
particular QF proj ect is larger than 10 MW.Could you
please explain what you meant?
The Commission has never definitively
addressed how Idaho Power should determine if a particular
QF project is a "less than 10 MW project" and therefore
enti tled to the published avoided cost rates.In 2002, in
GALE, DI
Idaho Power Company
its peti tion for Reconsideration, which was ul tima tely
granted and led to the determination of the "published
rates " in Case No. GNR-02-1, Idaho Power requested that
the Commission designate "nameplate capaci ty " as the test
the Company should apply to determine whether a QF proj ect
is entitled to receive the published rates.(Exhibit 203)
The Commission did not address the Company s request in its
final order, and as a result we still have no definitive
Commission ruling as to the test to be applied to determine
the capaci ty of a QF and its enti tlement to the published
ra tes
What is your understanding of the rationale
for limi ting the availabili ty of published rates to QF
proj ects 10 MW and smaller?
My understanding of the rationale supporting
the differentiation between QF projects larger and smaller
than 10 MW is a recognition that large QF projects may have
individual characteristics that should be recognized in a
negotiated contract between the utili ty and the QF.
addi tion, it is logical to assume that developers of large
QF's will tend to be more financially sophisticated and the
transaction costs associated with an individually negotiated
QF contract would be more easily absorbed into the mul ti-
million dollar costs of developing a large QF project.
Conversely, it is also logical to assume that the developers
GALE, DI
Idaho Power Company
of smaller QF projects may be less sophisticated developers
and more sensitive to the transaction costs associated with
individually-negotiated contracts, and as a result,
standardized contracts and published rates would encourage
small QF development.I believe these are generally logical
assumptions and I support the Commission s decision to
acknowledge the difference between larger and smaller QF
proj ects
In the past, how has the Company decided
which proj ects have a capaci ty greater than 10 MW?
Unfortunately, the process has been somewhat
ad hoc.In most instances the Company used nameplate
capac i ty as the tes t .Using nameplate capaci ty led to a
succession of 9.9 MW QF proj ects being presented to the
Company. In those instances the Company included a contract
provision in the FESA's that put the QF developers on notice
that if their 9.9 MW proj ects generated more than 10,000 kWh
per hour, Idaho Power could declare that they were not
enti tled to the published rates.In the few instances where
generation exceeded 10,000 kWh/hour, Idaho Power notified
the QF' s and the QF' s immediately took steps to make sure
tha t they did not generate more than 10, 000 kWh per hour in
the future.
The Company hopes that the Commission will use this
case to establish the methodology the Company should use to
GALE, DI
Idaho Power Company
determine which proj ects have a capaci ty less than 10 MW and
are therefore entitled to receive the published rates.
Why is it important that the Commission
establish the methodology that defines the 10 MW capacity
limi t?
The recent Commission order in the Renewable
Energy case has certainly increased Idaho Power s desire for
certainty in this area.It would be in everyone s best
interest if the Commission establishes a specific test that
will identify those situations where the QF is larger than
10 MW and therefore the Company should use the AURORA model
to compute avoided costs to be used to negotiate individual
contracts wi th large QF' s.
Does the Company have a recommendation as to
how the 10 MW threshold should be determined?
The Company believes that 10 MW is a
measuremen t 0 f capac i ty As will be discussed later in my
testimony, nameplate capaci ty rating is not very precise and
annual average energy production is only indirectly related
to capaci ty .The Company believes that using actual metered
generation is the preferred method to determine if the
capaci ty of a QF exceeds the 10 MW capaci ty limi If a QF
project's metering shows that the QF facility generated more
than 10,000 kWh per hour, that facility s generating
capaci ty must be greater than 10,000 kW or 10 MW.This test
GALE, DI
Idaho Power Company
is simple, definitive and the least susceptible to
manipulation of all of the tests.For purposes of my
further testimony, I will refer to this test as the "Metered
Energy Test.
What are the various ways of measuring the
capacity of QF projects?
Certainly the mos t commonly used measurement
of a generating resource's capaci ty is the manufacturer
nameplate rating.However, as U. s. Geothermal's Wi tness
Kitz indicates on pages 9 and 10 of his testimony,
nameplate " rating means different things to different
people.Nameplate rating can vary substantially from one
machine to another simply based on the formula used by the
manufacturer to compute the rating.For example, the
nameplate rating of a generator at an 80% power factor is
different from the nameplate rating of the same generator
measured at a 90% power factor.In fact, a genera tor
manufacturer can essentially say to a QF developer,How
much do you want to be?"and be truthful depending on
the test applied.Nameplate rating could be used to
determine enti tlement to the published rates if the
Commission would specify a particular methodology to be used
to measure nameplate rating.
The need to precisely define nameplate capacity
eliminated if the Company is permi tted to use the metered
GALE, DI
Idaho Power Company
energy test as a check against nameplate ratings.I f energy
purchases are limi ted to energy up to 10,000 kWh per hour,
QF developers will have no incentive to "fudge " on the
namepla te capaci ty rating.
Please comment on U. s. Geothermal'
suggestion that the Commission use annual average energy
production to determine the capaci ty of its QF proj ect?
The annual average energy tes t is only
indirectly related to the engineering concept of generating
capaci ty It deviates too far from the Commission s use of
10 MW of capaci ty to be valid. For example, the average
annual energy test would allow a QF proj ect wi th a capaci
of 100 MW to generate at its maximum rate of 100,000 kWh per
hour for only 876 hours during the year and still qualify
for the less than 10 MW" rates.The average annual energy
test would also allow a 30 MW QF proj ect to contract to sell
10 aMW to each of three different utilities and qualify for
the "less than 10 MW" rates from each of the three
utili ties.
While the ini tial reaction might be that these are
extreme examples, in fact they are not.It is very likely
that the Company will ultimately be presented with a wind
proj ect wi th an aggregate nameplate rating well in excess of
10 MW.In preparing its 2004 Integrated Resource Plan,
Idaho Power has determined that the usual capaci ty factor
GALE, DI
Idaho Power Company
for wind resources is approximately 35%.As a resul t,
the Commission adopts an average annual energy production
test, very large wind projects that are creatively
configured could qualify for the "less than 10 MW" rate.
This would allow these large QF proj ects to bypass
individual negotiations wi th the utili ty. This is exactly
opposite of the result the Commission intended when it
decided that QF projects larger than 10 MW should
individually negotiate con trac t s wi th the uti 1 i ty
Are there other issues you want to address
concerning Complainants wind resources and QF resources ln
general?
Wind generation presents several significant
problems for utili ty resource and system planners.Wind is
an intermi t tent resource.It li terally can fluctuate
between zero and the machine s maximum capaci ty on a minute-
to-minute basis.This fluctuation can be due either to
periods when the wind does not blow or to periods when the
wind blows so hard that the wind generating resource shuts
off to protect itself.A wind resource is a good example of
a non-firm, "if, as, and when available " resource.Wind
resources, unless they are firmed by other dispatchable
resources, simply cannot be described as providing firm
energy.On a long-run average basis, wind energy may be as
predictable as hydro generation.However, hydro generation
GALE, DI
Idaho Power Company
is not subject to the instantaneous increases and decreases
that wind generation is subj ect to.
Large intermi ttent resources also place significant
demands on utili ty transmission and distribution resources.
Tying up firm transmission capability on the Company
constrained system to accommodate intermittent generation
from wind resources presents serious questions of prudency.
Dr. Reading testifies on page 4 of his Direct
Testimony that wind generators are enti tled to be paid full
avoided costs for all of their production.Do you concur?
Yes.Idaho Power believes that wind
generation is enti tled to be paid full avoided costs.The
important distinction that must be drawn, however , is that
wind-generated energy is non-firm energy and the full
avoided cost for non-firm energy is not the published rate
for firm energy.The appropriate full avoided cost for wind
resources is a non-firm rate under the Company
Schedule 86.
If that's the case, why is Idaho Power
offering to pay firm energy prices for energy from the
Lewandowski and Schroeder wind genera tors?
The FESA Idaho Power has proposed to
Lewandowski and Schroeder (as well as to U. S. Geothermal)
provides them wi th the opportuni ty to commi t a portion of
GALE, DI
Idaho Power Company
their projects total monthly energy generation as firm.
the amount they specify is actually provided, firm prices
will be paid.Additional energy delivered up to 10,000 kWh
per hour would be purchased at non-firm prices.The FESA
Idaho Power has proposed places wind resources and all other
QF resources on an equal footing and does not differentiate
between technologies.
u. S. Geothermal is requesting that the
Commission rule that the Raft River Geothermal Project has a
capaci ty of 10 MW or less and as such is enti tled to the
published rates.Does Idaho Power agree that the Raft River
Plant has a capacity of 10 MW or less?
From the inception of its implementation of
PURPA, the Commission has condi tioned enti tlement to
published rates based on a measurement of capaci ty:10 MW,
5 MW or 1 MW.As indicated earlier in my testimony, Idaho
Power believes that the Commission s current orders
referring to the 10 MW limi t connotes 10 MW of capaci ty.
s. Geothermal has indicated that its Raft River facility
will have a combined generation nameplate capacity greater
than 10 MW and will regularly generate more than 10,000 kWh
per hour.Under ei ther of those tests, the Raft River Plant
will have a capacity that exceeds 10 MW.
However, because nameplate capaci ty rating is
subj ect to so much variabili ty, Idaho Power recommends that
GALE, DI
Idaho Power Company
the Metered Energy Test be applied.Thi s means tha t even if
the nameplate capacity of the QF is larger than 10 MW, so
long as the actual energy delivered in any hour does not
exceed 10,000 kWh, the proj ect should qualify for the
published rates.This Metering Energy Test has worked well
for Idaho Power in the past.It recognizes that nameplate
capaci ty is a somewhat fluid defini tion.Using actual
metered generation provides readily verifiable evidence of
the actual generating capaci ty of a QF facili ty. This
Metered Energy Test is included in the FESA's for the
Horseshoe Bend Hydroelectric proj ect and the Magic West
(Glenns Ferry) Cogeneration and Magic Valley (Rupert)
Cogeneration Proj ects.Each of these three QF projects has
9. 9 MW nameplate capaci ty rating.These three FESA's were
approved by the Commission on September 26, 1991 in Order
No. 23946, January 22, 1993 in Order No. 24674, and July 23,
1993 in Order No. 25050, respectively.The metered energy
test approach is also included in the contract between Idaho
Power Company and the J.R. Simplot Company which is
currently pending before this Commission.
If U. S. Geothermal is unwilling to agree to limi t
its deliveries for the Raft River facility to no more than
10,000 kWh per hour, then I believe the Raft River project
fails the test for enti tlement to published rates.In tha
event, it will be necessary for Idaho Power to use the
GALE, DI
Idaho Power Company
AURORA model to develop avoided costs to be included in a
contract to be negotiated wi th U. S. Geothermal for the Raft
River Project.
Has Idaho Power utilized its AURORA model to
compute avoided costs for the Raft River Project?
No.Idaho Power is hopeful that the
Commission will use this case to make a determination as to
the test to be applied to determine if a particular QF
qualifies for the published rates.At this point Idaho
Power does not know how the avoided costs that the AURORA
model would compute for the u.s. Geothermal Project will
compare to the published rates.If the Commission agrees
wi th U. S. Geothermal's proposal to utilize average annual
energy as the test for qualification for published rates,
there would be no reason to go further.If the Commission
determines that u.s. Geothermal's Raft River Project is
larger than 10 MW and a negotiated contract is appropriate,
Idaho Power would use the AURORA model to develop avoided
costs and would expedi tiously negotiate a Firm Energy Sales
Agreement wi th U. S. Geothermal based on those avoided costs.
It seems to Idaho Power that it would be better for
the Commission to make its determination of the proper
capaci ty test regardless of whether its decision would
resul t in a benefi t or detriment to U. S. Geothermal.
Complainants have obj ected to the Company
GALE, DI
Idaho Power Company
proposed contract provision addressing utility deregulation.
Could you please discuss why Idaho Power needs a contract
provision permitting it to terminate QF contracts
deregulation of the utility industry prevents the Company
from recovering stranded QF contract expenses?
Yes.In the mid to late 1990s, led primarily
by large industrial customers and potential independent
power producers and energy marketers, such as Enron and
CalPine, there was a strong push at both the state and
federal level for restructuring the electric utili ty
indus try.In March of 1996 the Commission initiated a
docket, Case No. GNR-96-1, in which the Commission
considered the benefi ts and detriments of restructuring the
electric power industry to separate generation, transmission
and distribution, and to allow customers to choose their own
electric suppliers without regard to exclusive utility
service terri tories.In 1997 the Idaho legislature created
an interim committee to study electric utility
restructuring.
In each of those two forums, one of the more
difficult problems discussed was the question of "stranded
costs or stranded investment.In Idaho Power s case, its
QF contracts represented a sizable share of the Company
potentially stranded costs.
Of course, there was a great deal of debate about
GALE, DI
Idaho Power Company
whether Idaho Power would, in fact, have any stranded costs.
A number of representatives of industrial customers and
other argued that the market value of a number of Idaho
Power s generation assets might exceed book cost, and if the
above-market assets were less than the below-market assets,
the utili ty would have no stranded costs.Dr. Reading
espouses this view in his testimony on page 11.
Other mechanisms for recovering stranded costs that
were discussed included exi t fees, non-bypassable
surcharges, and the issuance of bonds to reimburse the
utility for its stranded costs.Under any 0 f tho s e
scenarios, it is unlikely that the provisions of
Section 23.2 would be triggered because the Company would,
in fact, be fully compensated for its stranded QF expense.
However, during the course of the discussions on
stranded costs, several parties argued that the electric
utilities had been on notice for some period of time that
the regulatory environment is in a state of flux and that
the utili ties have done nothing to protect their posi tion.
As a result, these parties asserted that the utilities have
no right to claim an enti tlement to stranded cost recovery.
I recall that QF contracts were specifically mentioned as
examples of stranded expenses that the utility could have
addressed and had not done so.
Exhibit 204 is an excerpt from the report of the
GALE, DI
Idaho Power Company
Attorney General's Office to the 54th Idaho Legislature
dated January 11, 1999, in which the Attorney General
reported on electric utili ties ' restructuring.The
highlighted portion on page 2 of Exhibi t 204 discusses the
argument that utilities can waive their right to
reimbursement for stranded costs by failing to protect their
rights today.
Obviously, it is impossible to know today whether,
in some future electric industry deregulation process, the
costs of Idaho Power's QF contracts will still be above-
market and therefore consti tute stranded expenses.It is
not the purpose of my testimony to debate the meri ts or
demeri ts of increased competi tion or the restructuring of
the electric industry.If such restructuring occurs, it
will likely come as a mandate from ei ther Congress or the
Idaho legislature.Idaho Power s only concern is, if it
does occur, the Company needs to be protected from unfair
resul ts Idaho Power is legally compelled to enter into
contracts.It cannot refuse to enter into such contracts,
even if it believes that the prices in QF contracts will
exceed market prices over the long term.
Complainant Wi tnesses Reading and Runyan both
argue that the Commission approval of a QF contract
sufficient to protect the Company from stranded cost loss in
the event of utili ty deregulation.Do you agree?
GALE, DI
Idaho Power Company
No, I do not.My legal counsel advises me
that until the Commission issues an order either approving
or disapproving the contract language Idaho Power has
requested, the Company will be vulnerable to assertions that
it voluntarily waived its rights to claim confiscation of
its property if it cannot recover stranded QF expenses in
the future.
Do you have any comment on the testimony from
the various Complainants ' wi tnesses that allege that the
Complainants will be unable to cost-effectively finance
their proj ects unless the Commission rej ects the contract
provisions they identify in their Complaints?
On several occasions in the pas t, the
Commission has ruled that Idaho Power is precluded from
conducting discovery to examine the finances of a QF
proj ect.As a resul t, there is really no way for Idaho
Power to determine the extent that such assertions may
may not be exaggerated.I can only note, however, that in
the last six months the Company has entered into four FESA'
with smaller QF's which FESA's contain all of the contested
terms and condi tions To the limi ted extent Idaho Power is
permi t ted to inquire, the Company has been advi sed that in
the case of three of the four FESA's, it will be necessary
for the QF developers to obtain project financing.The
Company was further advised that in those three instances,
GALE, DI
Idaho Power Company
all of the QF developers believed that they would be able to
obtain proj ect financing.
Does this conclude your direct testimony?
Yes.
GALE, DI
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NOS. I PC-E-04-08/1 PC-04-1 0
IDAHO POWER COMPANY
EXHIBIT NO. 201
JOHN R. GALE
IDAHO IDAHO POWfR COMPAN1
O, BOX 70POWER,BOISE, IDAHO 83707
An IDACORP Company
BARTON L. KLINE
Senior Attorney
May 21 2004
Conley E. Ward
Givens Pursley LLP
601 W. Bannock Street
O. Box 2720
Boise , 10 83701-2720
Re:Case No. IPC-04-
S. Geothermal, Inc. v. Idaho Power Company, Raft River
OF Project
Dear Conley:
The purpose of this letter is to advise U.S. Geothermal of several items
that you will want to take into consideration in preparing U.S. Geothermal's testimony in
the above-referenced complaint proceeding.
First , I don t believe there is any dispute that the U.S. Geothermal Raft
River Project will have a nameplate capacity in excess of 10 MW. U.S. Geothermal has
also indicated that there will be times when the Raft River Project will generate and
deliver energy to Idaho Power at a delivery rate in excess of 10 MW. As a result, in this
proceeding Idaho Power must take the position that the Raft River Project is not entitled
to the published rates for OF projects smaller than 10 MW that are contained in the
Exhibits to your complaint.
In accordance with the provisions of Commission Order No. 26576, Idaho
Power will utilize the AURORA model to compute avoided cost rates for the Raft River
Project based on the generation data provided in the complaint. It will be Idaho Power
position in this case that the Commission should not approve the rates contained in any
of the Exhibits to your complaint but should approve rates computed using the
AURORA computer model.
Idaho Power recognizes that U.S. Geothermal takes the position that it is
entitled to the less-than-10 MW rates contained in your Exhibit A because , on an
annual average basis, the Raft River Project generation will not exceed 10 MW. The
purpose of this letter is not to argue that point but to make sure there is no
misapprehension on U.S. Geothermal's part that Idaho Power is offering to purchase
S. Geothermal's energy at the rates contained in Exhibit C to your complaint. It is
not.
Exhibit No. 201
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Telephone [phone], Fax [phone], E-mail BKlinerEYj Page 1 of 3
Conley E. Ward
Page #2
May 21 2004
Second , in its complaint, U.S. Geothermal objects to Idaho Power
proposed contract provisions contained in Exhibit C to your complaint that require U.
Geothermal pay Idaho Power liquidated damages based on additional market purchase
expenses Idaho Power may incur if U.S. Geothermal does not deliver 90 percent of the
energy it has agreed to provide in any month (shortfall energy). U.S. Geothermal (and
others) have expressed concern that this liquidated damage obligation could be
prohibitively expensive.
Idaho Power has considered this concern further and is hereby offering to
place a cap on U.S. Geothermal's liquidated damages exposure if U.S. Geothermal
fails to provide 900/0 of the agreed-upon energy in any month. Idaho Power proposes to
limit U.S. Geothermal's exposure in any month to a dollar per MWh amount equal to
1500/0 of the net energy price for the month in which the shortfall occurs multiplied by
the shortfall amount.
As an example of how this cap would operate , assume hypothetically that
S. Geothermal had agreed to provide 6 MW (4 464 MWh) during the month of July.
Further assume the contract price for net energy delivered in the month of July was $50
per MWh and the weighted average Mid-C market price in July was a highly abnormal
$200 per MWh. If U.S. Geothermal only delivered 2 MW (1 488 MWh) in the month of
July and the shortfall in energy delivery was not excused because of an event of force
majeure or because a forced outage had prevented U.S. Geothermal from generating
the full 6 MW (Paragraph 14., Exhibit C to Complaint), the shortfall would be 2 976
MWh (4 464 MWh less 1 488 MWh = 2 976 MWh shortfall). Using the assumed
monthly weighted average Mid-C market price for energy of $200, the potential
additional expense Idaho Power might incur as a result of this energy delivery shortfall
would be ($200 - $50) x 2 976 MWh = $446,400.
However, Idaho Power is proposing to limit U.S. Geothermal's exposure to
potential liquidated damages in two (2) ways. First, as provided in Paragraph 1.9 of
Exhibit C to your complaint, the market price used is only 850/0 of the monthly weighted
average of the actual Mid-C prices. By using 850/0 of the monthly weighted average of
the Mid-C prices , U.S. Geothermal is immediately shielded from 150/0 of the actual Mid-
C average price. As a result, using the above-referenced assumptions , the liquidated
damage amount would be (850/0 x $200 - $50) = $120 x 2 976 = $357 120.
Second , the proposed 1500/0 cap would further limit U.S. Geothermal'
exposure. Applying the 1500/0 cap, the liquidated damages amount would be (1500/0 x
$50) x 2 976 = $223,200.
Exhibit No. 201
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Page 2 of 3
Conley E. Ward
Page #3
May 21 2004
Of course , using Mid-C market prices that are more in line with
expectations shows that U.S. Geothermal's exposure is quite limited. For example
the current month's contract price is $50 and the month's Mid-C weighted average was
$58 or less, the Raft River Project would have no shortfall energy payment exposure
because 850/0 x $58 = $49., and as stated in Paragraph 7.3 of Exhibit C, the
calculated Mid-C price of $49.30 is less then the current month's contract price of $50
therefore no shortfall payment would be due from the project.
Coupling the 850/0 of Mid-C price limit with the 1500/0 cap provides a
manageable exposure if U.S. Geothermal fails to perform as agreed. Obviously the
1500/0 cap exposes the Company and its customers to greater potential expense if U.
Geothermal does not perform. The Commission will ultimately have to determine if
assuming this additional exposure is in the public interest because it encourages the
development of OF resources.
Finally, you should note that the Paragraph 23.2 offered to U.
Geothermal by Idaho Power in Exhibit C is different than the description of Idaho
Power s position contained in Paragraph 10 of the Complaint.
Idaho Power realizes that none of these items is likely to cause U.
Geothermal to change any of its basic positions in this proceeding. Nevertheless, the
Company thought it was appropriate to advise you of the positions Idaho Power will
take in its testimony in this case.
3=~
Barton L. Kline
BLK:jb
cc:John Prescott
Peter Richardson
Scott Woodbury
Exhibit No. 201
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Page 3 of 3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. I PC-04-08/1 PC-E-04-1 0
IDAHO POWER COMPANY
EXHIBIT NO. 202
JOHN R. GALE
IDAlia IDAHO POWER COMPANY
~.
POWER O. BOX 70
. .
BOISE, IDAHO 83707
An IDACORP Company
BARTON L. KLINE
Senior Attorney
May 21 , 2004
Peter J. Richardson
Richardson & O'Leary, PLLC
99 E. State Street, Suite 200
O. Box 1849
Eagle,IO 83616
Re:Case No. IPC-04-
Lewandowski and Schroeder v. Idaho Power Company
Dear Peter:
The purpose of this letter is to advise you and your clients of a change
Idaho Power is proposing to make to respond to one of the concerns raised in your
complaint. Idaho Power will present this change as a part of its case in the above-
referenced proceeding, and I wanted to advise you of this change so that you can take
it into consideration in preparing your testimony.
In its complaint, Lewandowski-Schroeder ("Developers ) object to Idaho
Power s proposed contract provisions that require Developers to pay Idaho Power
liquidated damages based on additional market purchase expenses Idaho Power may
incur if Developers do not deliver 900/0 of the energy they have agreed to provide in any
month ("Shortfall Energy
).
Developers have expressed concern that this liquidated
damage obligation could be prohibitively expensive.
Idaho Power has considered this concern further and is hereby offering to
place a cap on Developers' liquidated damages exposure if Developers fail to provide
900/0 of the agreed-upon energy in any month. Idaho Power proposes to limit
Developers' exposure in any month to a dollar per MWh amount equal to 1500/0 of the
net energy price for the month in which the shortfall occurs multiplied by the shortfall
amount.
As an example of how this cap would operate , assume hypothetically that
Developers had agreed to provide 6 MW (4 464 MWh) during the month of July.
Further assume the contract price for net energy delivered in the month of July was $50
per MWh and the weighted average Mid-C market price in July was a highly abnormal
$200 per MWh. If Developers only delivered 2 MW (1 488 MWh) in the month of July
Exhibit No. 202
Case Nos. IPC-04-08/IPC-04-
Telephone [phone], Fax [phone], E-mail BKlinerEY, Gale, IPca
Page 1 of 3
Peter J. Richardson
Page #2
May 21 2004
and the shortfall in energy delivery was not excused because of an event of force
majeure or because a forced outage had prevented Developers from generating the full
6 MW (Paragraph 14., Exhibit A to Complaint), the shortfall would be 2,976 MWh
464 MWh less 1 488 MWh = 2 976 MWh shortfall). Using the assumed monthly
weighted average Mid-C market price for energy of $200, the potential additional
expense Idaho Power might incur as a result of this energy delivery shortfall would be
($200 - $50) x 2 976 MWh = $446,400~
However, Idaho Power is proposing to limit Developers' exposure to
potential liquidated damages in two (2) ways. First, as provided in Paragraph 1.9 of
Exhibit A to your complaint, the market price used is only 850/0 of the monthly weighted
average of the actual Mid-C prices. By using 850/0 of the monthly weighted average of
the Mid-C prices, Developers are immediately shielded from 150/0 of the actual Mid-
average price. As a result, using the above-referenced assumptions , the liquidated
damage amount would be (850/0 x $200 - $50) = $120 x 2 976 = $357 120.
Second, the proposed 1500/0 cap would further limit Developers' exposure.
Applying the 1500/0 cap, the liquidated damages amount would be (1500/0 x $50) x 2 976
= $223,200.
Of course , using Mid-C market prices that are more in line with
expectations shows that Developers' exposure is quite limited. For example if the
current month's contract price is $50 and the month's Mid-C weighted average was $58
or less , the Developers' project would have no shortfall energy payment exposure
because 850/0 x $58 = $49., and as stated in Paragraph 7.3 of Exhibit A , the
calculated Mid-C price of $49.30 is less then the current month's contract price of $50
therefore no shortfall payment would be due from the project.
Coupling the 850/0 of Mid-C price limit with the 1500/0 cap provides a
manageable exposure if Developers fail to perform as agreed. Obviously the 1500/0 cap
exposes the Company and its customers to greater potential exposure if Developers do
not perform. The Commission will ultimately have to determine if assuming this
additional exposure is in the public interest because it would encourage the
development of OF resources.
Exhibit No. 202
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Page 2 of 3
Peter J. Richardson
Page #3
May 21 2004
Idaho Power realizes this is just one item in your complaint. Nevertheless
the Company thought it was appropriate to advise you ahead of time as to the position
Idaho Power will take on this issue in its testimony in this case.
Very
~ y
~urs, J;t~
Barton L. Kline
BLK:jb
cc:John Prescott
Scott W oodbu ry
Exhibit No. 202
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Page 3 of 3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. I PC-E-04-08/1 PC-04-1 0
IDAHO POWER COMPANY
EXHIBIT NO. 203
JOHN R. GALE
conclusion were not presented as a part of Staff's comments. As a result, none of the
other Parties had an opportunity to examine the factual basis supporting Staff'
conclusions. Because the Commission declined Idaho Power s and PacifiCorp
requests to convene a proceeding to consider current avoided costs, these parties were
denied the opportunity to test the validity of Staff's analysis and conclusions cited in the
Order. For the Commission s Order to cite the Staff's conclusion that the published
rates are equivalent to current avoided costs (1) without any further discussion of that
critical issue in the Order; (2) without giving the other Parties an opportunity to review
and challenge the Staff's conclusion; or (3) without allowing other Parties to present
evidence demonstrating that the published rates do not represent current avoided
costs, is unreasonable and constitutes arbitrary and capricious decision making.
Order No. 29029 fails to specify how the 5 MW limit would be
established.
In Order No. 29029, the Commission decided to increase the eligibility
threshold for published rates from 1 MW to 5 MW. OFs larger than 5 MW would not be
eligible for the published rates. However, Order No. 29029 does not specify how the
5 MW limit would be established. Idaho Power has already received inquiries from one
OF developer with four separate qualifying facilities , all of which have a nameplate
capacity rating that exceeds 5 MW. This OF is requesting that Idaho Power pay the
published rates for 5 MW generated by a 11.2 MW rated facility and 5 MW generated
by a 12.5 MW rated facility.
It is Idaho Power s position that the entitlement to published rates should
be based on the nameplate capacity of the generating facility. Idaho Power believes
Exhibit No. 203
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
IDAHO POWER COMPANY'S PETITION FOR RECONSIOERA1 Page 1 of 2
that its position is consistent with the Commission s intent expressed in Order Nos.
25884 and 29029 that published rates are intended to facilitate the development of
smaller OF projects that might feel that they were disadvantaged by having to negotiate
project-specific rates with the utility.
Order No. 25884 issued January 3, 1995 in Case No. IPC-93-28 was
the order in which the Commission established the current distinction between the
avoided cost rates available to smaller or larger OF projects. In Order No. 25884 the
Commission ordered that small OF projects could be eligible for published rates and
large OF projects would negotiate avoided cost rates based on the individual
characteristics of their project. The principal reason the Commission cited in Order No.
25884 to support its decision to establish published rates for smaller projects , was the
concern that smaller project developers would be less capable of negotiating avoided
cost rates with utilities. This same concern was echoed in Order No. 29029, Le., the
alleged "black box" cited on Page 6 of Order No. 29029. Idaho Power has found
nothing in any Commission order to support a contention that it was the Commission
intent that the published rates would apply to a 5 MW portion of the generation from a
qualifying facility larger than 5 MW. Construing Order No. 29029 in this manner would
certainly defeat the intent expressed in Order No. 25884 requiring larger QF projects
(above 5 MW) to negotiate project specific purchase prices with the utility based on the
individual characteristics of the larger generation project.
The Commission should order a stay of the effectiveness of Order
No. 29029 to allow adequate time to update the assumptions in the existing
methodoloQY;.
Exhibit No. 203
Case Nos. IPC-04-08/IPC-O4-
Gale, IPca
IDAHO POWER COMPANY'S PETITION FOR RECONSIOERAT Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-04-08/IPC-04-
IDAHO POWER COMPANY
EXHIBIT NO. 204
JOHN R. GALE
$0.50 of investment, unless some disposition is made somewhere, earns less than a reasonable
return (here, 0%). Consequently, this portion of the investment has become stranded.
Negative stranded costs or investment" may also emerge. Instead of producing a decline in
the economic value of generating facilities, competition may result in a net positive gain.
Referring to the earlier simple example, it may be that the book value of the original $1
investment has declined to $0.25 (e., through depreciation), although the facility is fully
functional. At the competitive market rate reflecting a return of $0.05 per unit/per period, the
return on the residual book investment is 20%, implying an economic asset value of $0.50.
The difference between the book and economic value (+$0.25) is sometimes termed a
negative stranded investment.,,79 Some states both recognize the concept and require an
offsetting of negative and positive values to determine the net amount of stranded cost
recognizable for recovery.80 For example, Montana Power Company recently sold mostofits
generating facilities for 155% of book value. In Maine, Bangor Hydro agreed to sell its hydro
facilities for $89 million, when book value was about $50-$55 million.
Should Stranded Investments be Recoverable?
As an initial matter, disagreement may exist whether stranded costs should be recognized at
all. Theories (for) and (against) such recognition may be briefly summarized as follows:
Social Compact Theory (For) -- Under this theory, investor-owned utilities
undertook various obligations imposed by regulation 1) beyond or different from those
warranted by ordinary free market considerations; 2) in order to address the public
interest; 3) with an expectation that they would have a reasonable opportunity to
recover those investments over time; and 4) over that period, the opportunity to earn a
reasonable return thereon, as well. This theory derives from U.S. Supreme Court
cases (Federal Power Commission v. Hope Natural Gas Co.320 U.S. 591(1944);
Bluefield Water Works v. West Virginia Public Service Commission, 262 U.S. 679
(1923); Smytj1 v. Am , 169 U.S. 466 (1898)), which recognize that a company "
entitled to ask (for) a fair return upon the value of that which it employs for the public
convenience (Smyt.h, supra). Idaho s Supreme Court has adopted this principle.
More recently, the Court reiterated similar concerns in terms of the reasonable
expectations of investors in D.Yguesne Light Co. v. aarascn, 488 U.S. 299 (1989).
78 FERC stranded costs are defined in tenns of "wholesale stranded costs." See FERC Order No. 888 at 618-
29.79 Fox-Penner at 397.80 See, e., Public Utilities Code, State of California, Chapter 2.3 "Electric Restructuring" Section 330(s): "
. .
. In detennining the costs to be recovered, it is appropriate to net the negative value of above market assetsagainst the positive value of below market assets" (hereinafter
, "
CPUC Code81 Bangor Daily News (Sept. 29, 1998).
82 Hayden Pines Water Co. v. Idaho PUC, 122 Idaho 356, 834 P.2d 873 (1992); Utah Power & Light Co. v.
Idaho PUC, 102 Idaho 282, 629 P.2d 678 (1981); Intennountain Gas Co. v. Idaho PUC, 97 Idaho 113, 540
2d 775 (1975); In re Mtn. States Tel. & Tel. Co., 76 Idaho 474 284 P.2d 681 (1955).
Exhibit No. 204
Case Nos. IPC-O4-08/IPC-04-
Gale, IPCO
Page 1 of 3
Confiscation (F or) -- This theory asserts the right of private property and the
obligation to pay compensation in the case of governmental takings (U.S. Const.
Amend. V: ". nor shall private property be taken for public use, without just
compensation. "
).
Historically, such arguments were sometimes allied with the due
process clause, as well (Id: ". . . nor be deprived of. . . property, without due process
of law see Smytj1 v. Am , supra).
!jJh'*:!:f;:"iJ';P;;Ih
. Basic risk of business (Against) -- This theory asserts that all businesses are subject
,~!
to the police powers of the state and to any necessary change in the exercise of those
;:q
powers over time.83 Where property remains in the owner
s hands and can still be put i4:'
to the production of income, no unlawful taking or confiscation occurs and no Et):
separate cost recognition or recovery is required. This is argued to be especially true !$ti
of electric utilities which have been on notice for some time that the regulatory J~~environment is in a state of flux.
"""
,c":t:;I%'~?;i~R!i;, "1!."~'
~" "..
~~i'~~;%i't~'
. Adverse competitive impacts (Against) -- In the view of some, recognition of
stranded costs will unfairly advantage the incumbent utilities who benefit from such
cost recovery, as against new competitors who receive no such compensation. In this
regard, the D.C. Circuit in Cajun Electric Power Cooperative. Tnc. v. , 28 F.
173 (D.C. Cir. 1994), suggested two competitive concerns. First, that stranded cost
recovery could effect a tying between stranded cost charges and charges for bottleneck
transmission facilities. Second, stranded cost charges could result in competitive
asymmetry, whereby the incumbent utility could compete outside its territory without
paying the stranded cost charge, but all competitors within its territory would pay the
cost charge to it.
Public Policy ( Against) -- This view asserts that recognition of stranded costs
penalizes competitors and prudently run incumbent utilities for the efficiency of their
operations, by rewarding inefficient utilities for past inefficiencies.
Sharing principles (Intermediate) -- This approach suggests that stranded cost
recovery mechanisms should require that amounts recovered by a utility for stranded
costs be shared with consumers under certain circumstances (for example when
expected levels of stranded cost are not realized or when offsetting benefits are
realized) .
. Forced costs (Intermediate) -- Here, cost recovery would be permitted but limited
to instances where affirmative regulatory mandates, initiated by the regulators, were
the clear cause of the cost for which stranded recovery is sought. Some versions
require such imposition to be over the active objection of the utility, as well.
83 Idaho s Constitution provides that "the police powers of the state shall never be abridged or construed as to
pennit corporations to conduct their business in such a mariner as to infringe the equal rights of individuals, or
the general well being of the state. Art. XI, ~ 8.
Exhibit No. 204
Case Nos. IPC-04-08/IPC-04-
Gale , IPca
Page 2 of 3
Types and Characteristics of Stranded Costs.
The pursuit of restructuring and competition in the states has led to an expanded scope of
matters encompassed by stranded investment. Current inquiries and debates generally
recognize three sources or types of stranded costs. They are:
Utility-owned generating facilities;
Long-term fuel and purchase power contracts, such as those arising
from PURP A requirements;
Regulatory assets, including:
Deferred taxes;
Post-retirement employee benefits;
Nuclear decommissioning costs; and
Demand-side management (DSM) costS.
Other types of costs may be also recognized for recovery purposes, depending upon the
policies and goals of restructuring. F or example, costs associated with environmental
protection, natural resource preservation, and DSM address the public good. In a competitive
market, however, unregulated sellers may choose not to incur these costs (such costs tend to
produce no current income) and, thus, will obtain a price advantage over regulated utilities.
As a result, the costs and the associated with these public benefits may, in a sense, become
stranded.
FERC and related judicial proceedings have identified several criteria for characterizing costs
as stranded. These characteristics may be summarized as: 1) prudently incurred; 2) legitimate;
3) verifiable; and 4) accurately calculated. From a different perspective, economic analysis
may describe the essential characteristics of stranded costs in such terms as: 1) sunk in a prior
period (before deregulation actual or impending); 2) stranded by the transition to
competition; and 3) not marginal in nature (since marginal costs are avoidable).
Measurement of Stranded Costs.
The measurement of stranded costs requires examination of the cost structure of each affected
entity and econometric analysis of the affects of any given stranded cost recognition policy on
resulting transition costs, residual utility investment, future utility revenues, and consumer
price and choices. Stranded costs can be measured in several different ways, including:a. Revenues Lost -- The volume of energy produced by a generation facility times
the anticipated market price of that energy per unit (under regulation) is compared to
the same output times the anticipated price under competition. The differential (if any)
represents the amount of cost stranded by the transition to competition. Such
computations can be based on projections (determined up front or ex ante) or upon
84 Fox-Penner at 385-86.
Exhibit No. 204
Case Nos. IPC-04-08/IPC-04-
Gale, IPca
Page 3 of 3
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 15th day of July, 2004, I served a true
and correct copy of the DIRECT TESTIMONY AND EXHIBITS OF JOHN R. GALE upon
the following named parties by the method indicated below, and addressed to the
following:
Conley E. Ward
Givens Pursley LLP
601 W. Bannock Street
O. Box 2720
Boise , 10 83701-2720
Daniel Kunz, President
S. Geothermal, Inc.
1509 Tyrell Lane , Suite B
Boise , 10 83706
Peter J. Richardson
Richardson & O'Leary PLLC
99 East State Street, Suite 200
O. Box 1849
Eagle IO 83616
Don Reading
Ben Johnson Associates
6070 Hill road
Boise , 10 83703
Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, 10 83720-0074
CERTIFICATE OF SERVICE
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BARTON L. KLINE