20041122Final Order No 29632.pdf

Office of the Secretary
Service Date
November 22, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
s. GEOTHERMAL, INC. AN IDAHO
CORPORATION,CASE NO. IPC-O4-
Complainant,
vs.
IDAHO POWER COMPANY, AN IDAHO
CORPORATION,
Respondent.
BOB LEWANDOWSKI and MARK
SCHROEDER,CASE NO. IPC-O4-
Complainants,
vs.
ORDER NO. 29632
IDAHO POWER COMPANY, AN IDAHO
CORPORATION,
Respondent.
Two complaint proceedings are pending before the Commission against Idaho Power
Company, Case Nos. IPC-04-8 and IPC-04-10.The complainants are small power
producers and Qualifying Facilities (QFs) under the Public Utility Regulatory Policies Act of
1978 (PURP A) and the implementing regulations of the Federal Energy Regulatory Commission
(FERC). The respondent, Idaho Power, an electric utility, is required pursuant to PURP A and
the implementing rules and regulations of FERC and this Commission to purchase power from
eligible QFs.
Case No. IPC-O4-8 - U.S. Geothermal
On March 25, 2004, U.S. Geothermal, Inc. in Case No. IPC-04-8 filed a complaint
against Idaho Power Company (Idaho Power; Company) alleging that Idaho Power was
proposing PURPA contract terms that were unjust, unreasonable and unlawful. U.S. Geothermal
is the owner and developer of the Raft River Geothermal Power Plant (Raft River Facility), a
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proposed 15 MW air-cooled, closed cycle geothermal electric generating plant to be constructed
in Cassia County, Idaho. U.S. Geothermal proposes to develop a geothermal energy resource
underlying nearly six square miles in the Raft River Valley. The Raft River resource area may
be capable of producing up to 15.6 MW of electrical power from each square mile. Tr. at 13 , 14.
The Raft River Facility is a Qualifying Facility as that term is used and defined in the Public
Utility Regulatory Policies Act of 1978 (PURP A) and 18 C.F .R. ~ 292.207.
S. Geothermal alleges Idaho Power s contract demands are unjust, unreasonable
and contrary to law because:
1. Idaho Power refuses to purchase an annual average of 10 MW of power from U.
Geothermal at the Commission-approved non-Ievelized posted rates. Instead, Idaho Power
insists that it will only purchase a maximum of 10 MW in any given hour at the posted rates.
S. Geothermal contends that there is no basis in law or in fact for such a limitation.
2. Idaho Power insists on extreme financial penalties if U.S. Geothermal's total
output in any month falls below 90%, or above 110%, of its projected output. U.S. Geothermal
contends that there is no basis in law or in fact for such penalties.
3. Idaho Power insists that it must have the ability to terminate its contractual
obligation to purchase U.S. Geothermal's power if (1) Idaho law is modified to permit any other
party to sell electricity at retail in Idaho Power s service territory and (2) such change in law
results in Idaho Power being unable to recover in its retail revenue requirement all costs
attributable to the purchase agreement with U.S. Geothermal. U.S. Geothermal contends that
there is no basis in law or in fact for Idaho Power s position, and that such a provision would
effectively nullify this Commission s rules by making it extremely costly, if not impossible, to
finance PURPA projects.
On April 19, 2004, Idaho Power filed its Answer contending that U.S. Geothermal
had not stated a claim for relief which could be granted.
Case No. IPC-O4-10 - Mssrs. Lewandowski and Schroeder
On April 28, 2004, Bob Lewandowski and Mark Schroeder (the wind QFs) filed a
complaint against Idaho Power Company in Case No. IPC-04-10. Both Mr. Lewandowski and
Mr. Schroeder are in the process of developing wind power projects in Idaho that will be
Qualifying Facilities pursuant to PURP A. Mr. Lewandowski's wind proj ect, for the current
phase, will have a total capacity of 325 kW and will consist of 3 refurbished 108 kW micron
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turbines. Tr. at 258. Mr. Schroeder s wind project will consist of eleven 900 kW NEG-micron
turbines. Tr. at 258.
Mr. Lewandowski and Mr. Schroeder complain that:
1. Idaho Power is insisting on contract provisions that obviate the requirement that a
purchase of all of the output from these proj ects be at full avoided cost rates when said output is
less than 90% or more than 110% of proj ected output.
2. Idaho Power is also insisting on a contract provision called "shortfall energy
which would actually require the developer to pay Idaho Power for electricity not produced by
the proj ect with no cap or ceiling on the price.
3. By later amendment the wind QFs also incorporated a third count regarding Idaho
Power s proposal to terminate the agreement should retail deregulation be implemented in Idaho
and the utility as a result be unable to recover its contract costs. They contend there is no basis
in law or fact for this position and that it would effectively nullify the Commission s rules by
making it extremely costly, if not impossible, to finance PURPA projects.
On May 17, 2004, Idaho Power filed its Answer contending that Complainants had
not stated a claim for relief which could be granted.
Appearances
A technical hearing in Case Nos. IPC- E-04-8 and IPC- E-04-1 0 was held in Boise
Idaho on September 2 (3), 2004. The following parties appeared by and through their respective
counsel of record:
Idaho Power Company:Barton L. Kline, Esq.
S. Geothermal, Inc.Conley E. Ward, Esq.
Bob Lewandowski
Mark Schroeder:Peter J. Richardson, Esq.
A vista Corporation:R. Blair Strong, Esq.
PacifiCorp:James R. Fell, Esq.
Commission Staff:Scott D. Woodbury, Esq.
We have reviewed and considered the record in Case Nos. IPC-04-8 and IPC-
04-10 including the transcript of technical proceedings; filed public comments; and the post-
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hearing briefs of U.S. Geothermal, Bob Lewandowski and Mark Schroeder, Idaho Power and
A vista.
In this proceeding the complainants object to contract provisions that Idaho Power
insists be included in a Firm Energy Sales Agreement (FESA; Agreement). As reflected in our
initial notice in this case and as framed by the complainants, we find that there are only three
distinct issues or contract provisions presented for Commission consideration:
1. Regulatory Out Clause
If existing Idaho law is modified to allow persons or entities other than Idaho
Power to sell electric capacity or energy at retail in Idaho Power s exclusive
service territory, and such change in law results in Idaho Power being unable
to fully recover all costs associated with the QF Firm Energy Sales
Agreement, Idaho Power may terminate the Agreement on 60 days prior
written notice. Tr. at 178.
Should Idaho Power be allowed to include a contract clause that allows the
Company to unilaterally terminate PURP contracts if certain regulatory
actions occur in the State of Idaho? Tr. at 193.
2. 10 MW Definition - Eligibility for Posted (Published) Rates
What is the definition of the 10 MW size limit for entitlement to the
Commission s published avoided cost rates? Tr. at 191 , 192.
3. 90-110% Performance Band
Should Idaho Power be allowed to include contractual provisions that impose
financial penalties or liquidated damages if a PURP A generator s energy
deliveries vary by more than plus or minus 10% from its forecasted
performance? Tr. at 192.
fourth issue raised by U.S. Geothermal at hearing is related to the 10 MW
threshold and 90-110 band issues. The fourth issue is one of grandfathering. Can a project
greater than 10 MW generate more than the contract firm energy amounts and sell that excess
either to Idaho Power at market-based rates or to a third party and nevertheless remain eligible
for the published rates for the first 10 MW of generation, consistent with the terms and
conditions of the PURP A contracts approved by the Commission for Tiber Montana (Order No.
29232) and Renewable Energy (Order No. 29487)? U.S. Geothermal contends that it is entitled
to grandfathering because of extensive negotiations conducted with Idaho Power based on the
Company s contracting guidelines and previous Commission contract approvals. Tr. at 193.
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Other issues raised by the parties and intervenors are beyond the scope of this complaint
proceeding and will not be addressed.
1. Regulatory Out
Idaho Power s proposed regulatory out provIsIon would allow the Company to
terminate the power sales agreement should retail electric competition within its service area
result in its inability to recover the costs associated with the QF contract. Tr. at 27. Idaho Power
in support of inclusion of such contract language offers Company Exhibit 204, which is an
excerpt from an Idaho Attorney General Report to the Idaho Legislature wherein the Attorney
General cites a position advanced that a change in the regulatory environment is simply a
business risk and does not constitute confiscation. Tr. at 382. In the situation where legislation
or Commission action does not provide for recovery of stranded PURP A expenses, Idaho Power
contends that it needs to be able to assert that the government has confiscated its property. Tr.
382. Until the Commission issues an Order either approving or disapproving the regulatory out
language the Company has requested, Idaho Power witness Gale states that he is advised by his
legal counsel that there is some remaining risk that the Company will be vulnerable to future
assertions that it voluntarily waived its right to claim confiscation of its property. Tr. at 384.
Commission Staff does not support inclusion of a regulatory out clause. Tr. at 578.
Staff contends that such a clause is unnecessary to protect the Company s economic interest and
that such a clause is prohibited by PURP A and FERC regulations. Tr. at 605. Staff notes that
the utility has no discretion under PURP A whether or not to purchase QF power.The
Commission requires the Company to enter into contracts and pursuant to other contract
provisions approves the payments as prudently incurred expenses for ratemaking purposes.
Once a QF contract and price are approved by the Commission, Staff contends that the QF costs
pursuant to that price are no longer at issue as to prudency. Tr. at 606. The proposed regulatory
out clause, Staff contends, gives the Commission continuing jurisdiction over the avoided cost
rate and subjects the QF to the same "utility type regulation" precluded by PURP A Section
210(e); implementing FERC regulations, 18 C.R. Section 292.602(c)(1); by federal courts; by
state Supreme Courts and by the Idaho Supreme Court. Tr. at 607.
Staff contends further that 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 are-opener
clause, without rate revision, and assuming compliance with contract terms and conditions
ORDER NO. 29632
without termination. Staff notes that under PURP A and FERC regulations the QF is entitled to a
fixed rate contract for sale of power over a fixed period of time. The QF, Staff contends, should
not be denied the certainty of an arrangement and the benefits of its commitment as a result of
changed circumstances. Tr. at 606.
PacifiCorp supports Idaho Power s position that utilities need to act prudently to
mitigate their potential exposure if deregulation results in unrecovered stranded costs. Tr.
496.
A vista states that it does not propose to include stranded cost provisions in its
PURP A contracts. Tr. at 544. In the event of retail deregulation, A vista believes that the
Commission has the authority to approve charges for end-use retail customers that would
provide an opportunity for recovery of cost obligations resulting from PURP contracts. If
deregulation does occur at the retail level, the Company contends that it will be important that
such legislation address the stranded cost issues, and/or that the Commission retain all necessary
authority to address recovery of any PURP A-related stranded costs. Tr. at 544.
S. Geothermal witness Kunz contends that inclusion of a regulatory out clause
creates unnecessary uncertainty. It is also not needed, he states, because QF contracts must be
presented for Commission approval and Commission Orders include a finding that payments
made pursuant to the agreement shall be allowed as prudently incurred expenses for ratemaking
purposes. Tr. at 27; 178-179. Having received Commission approval, U.S. Geothermal
contends that it is unfair to the QF, its investors, and its lenders to provide for the termination of
the agreement as a result of actions and negotiations that would be conducted outside the scope
of the contract. Tr. at 79. Any negotiation, settlement and balancing of assets and liabilities as
a utility moves to deregulation, U.S. Geothermal witness Runyan contends, would be a
comprehensive solution that would undoubtedly include many offsetting compromises and
valuations. Tr. at 180; 264.
Don Reading, witness for the wind QFs contends that this seemingly innocuous
clause is fraught with ambiguity, danger, uncertainty and inaccuracies. As an example, he states
there is no such thing as "exclusive service territories.Secondly, he states the phrase "fully
recover all costs associated with this Agreement" is very problematic. In a deregulation scheme
IOU', such as Idaho Power, would likely be expected to net out their stranded costs from their
stranded benefits resulting in an overall settlement of who is owed what. Thirdly, he queries
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who would make the call relative to whether or not Idaho Power had recovered all its costs. Tr.
at 273-275.
Commission Findings
Idaho Power is required to purchase energy and capacity from eligible QFs pursuant
to PURP A and FERC rules and regulations. The Company has never regarded purchases from
QFs as voluntary. The Company includes in its Firm Energy Sales Agreements a provision
conditioning the purchase on Commission acknowledgement that utility payments to the QF will
be treated as prudently incurred expenses for ratemaking purposes. This Commission is the state
regulatory authority that by Order requires QF purchases and establishes the avoided cost rate.
This Commission has always provided Idaho Power with the assurance it requested. Weare now
being asked to allow the Company to include a regulatory out clause in QF contracts. While the
rights and obligations of the contracting parties should be delineated and identified risks should
be mitigated, the Company should not lose sight of the underlying nature of the transaction and
the advantages to the utility and its customers of securing a greater diversity in its resource base
by acquiring renewable resources. Idaho Power has an obligation to purchase QF power. A QF
willing to enter into an enforceable obligation, has a right to a contract for an established term.
Pursuant to Commission policy, utilities are required to submit QF contracts for Commission
review and approval. We will not permit Idaho Power to terminate QF contracts for reasons
other than the default of the QF. We will not allow the Company to require a QF to accept a
regulatory out clause as a condition of contract.
2. 10 MW Threshold
Idaho Power proposes a metered energy test as a method of determining published
rate eligibility.U sing actual metered generation, it contends, is the preferred method to
determine if the capacity of the QF exceeds the 10 MW capacity limit. If a QF meter reads
greater than 10 000 kWh per hour, then the QF is greater than 10 MW and not entitled to
published avoided cost rates. Tr. at 342-343. A technology-by-technology analysis, Idaho
Power contends, would inject an unreasonable level of complexity into the process. Tr. at 370.
Idaho Power contends that the 10 MW threshold limit question has arisen because
the Commission has issued no definitive ruling as to the test to be applied to determine the
capacity of a QF and its entitlement to the published avoided cost rates. Tr. at 338. The
Company s practice has been ad hoc. In most instances, the Company states that it has used
ORDER NO. 29632
nameplate capacity as the test. Tr. at 340. This practice led to a succession of 9.9 MW QF
projects. Administratively the Company included a provision in those 9.9 MW QF contracts that
put the developers on notice that if their projects generated more than 10 000 kWh per hour
Idaho Power could declare that they were not entitled to the published rates. Tr. at 340. The
Commission s recent Order No. 29487 in the Renewable Energy case, Idaho Power states, has
increased the Company s desire for greater certainty in this area. Tr. at 342. In Renewable
Energy the Commission stated that Idaho Power s failure to follow Commission-approved
avoided cost methodology for calculating QF rates was both unacceptable and inexcusable. For
QFs larger than 10 MW, purchases, the Commission stated, are to be priced pursuant to the
approved IRP-based methodology. Published rates are for QFs smaller than 10 MW. Case No.
IPC-04-, Order No. 29487 at 10 issued May 4, 2004.
Regarding wind, Idaho Power states that in preparing its 2004 IRP the Company
determined that the usual maximum capacity factor for large wind resources is approximately
35%. Tr. at 345-346. Wind, it states, is an intermittent resource. As such, wind presents
significant problems for utility resource and system planners. It can literally fluctuate between
zero and the machine s maximum capacity on a minute-to-minute basis. Tr. at 346. A wind
resource, Idaho Power states, is a good example of a non-firm ", as, and when available
resource. Tr. at 346. Wind resources, unless they are firmed by other dispatchable resources, the
Company contends, simply cannot be described as providing firm energy. Tr. at 346. On a long
run average basis wind energy, the Company concedes may be as predictable as. hydro
generation. However, hydro generation, it states, is not subject to the instantaneous increases
and decreases that wind generation is subject to. Tr. at 346-347. Large intermittent resources
the Company contends, also place significant demands on utility transmission and distribution
resources. Tr. at 347.
Idaho Power states that the avoided cost for non-firm energy is not the published rate
for firm energy. The appropriate full avoided cost for wind resources, the Company contends, is
a non-firm rate under Schedule 86. Tr. at 347. The Firm Energy Sales Agreement provided by
the Company, it contends, provides wind with the opportunity to commit a portion of a
project's total monthly energy generation as firm. If the amount they specify is actually
provided, firm prices will be paid. Tr. at 348. Additional energy delivered up to 10 000
kWh/hour would be purchased at non-firm prices. Tr. at 348.
ORDER NO. 29632
The U.S. Geothermal Raft River project will be a binary power plant using
geothermal heated water. Hot geothermal water is extracted from the earth and once the
necessary heat has been extracted for the binary cycle use and the water has been cooled, it is
injected back into the geothermal reservoir. The process will rely on air-cooling to achieve the
electrical output. Air-cooling is subject to seasonal variations, with the cold of winter supplying
very high efficiencies in cooling; and the heat of summer producing the opposite effect. Due
the seasonal ambient temperatures, the plant output will swing from 8 MW in the peak of
summer to just over 12 MW in the dead of winter. The overall annual plant output however will
average 10 MW. U.S. Geothermal feels strongly that the Raft River plant should qualify as a
MW QF and be measured on its performance on an annual basis. If it is limited to a 10 MW
turbine, U.S. Geothermal contends that Raft River could never deliver anything close to an
average of 10 MW per year. This is because of the seasonal variations in ambient temperature
and because Raft River will have a relative large "in-house" or parasitic load (the draw of
electrical power for pumps and cooling fans). Tr. at 22-, 72, 75. U.S. Geothermal witness
Kunz recommends that the definition of the cap for published rates be based on 10 MW annual
average energy production, and not 10 000 kWh in any single hour. Tr. at 25.
The maximum plant output of Raft River (the expected output of the plant in the
middle of winter) is approximately 12.7 MW. Tr. at 94. U.S. Geothermal notes that it is not
asking Idaho Power to purchase "excess energy" above the 10 aMW.Tr. at 102.
Geothermal requests an "engineering definition" of a 10 MW geothermal power plant: i., (1)
the ability to deliver no more than 10 MW as an annual average; and (2) a recognition that at the
average design condition the power plant will deliver no more than 10 MW. At temperatures
above the design point, the generation will be lower. At temperatures below the design point
the output will be higher. Tr. at 106.
U. S. Geothermal's last draft of a contract proposes that the "maximum capacity
amount" be defined as 12.7 MW in any hour. In addition, in Article VI of the Agreement, U.
Geothermal introduces the concept of "maximum monthly energy amounts." This concept limits
the maximum energy deliveries in any month to a specified amount. The total of all 12 monthly
(maximum monthly energy) amounts is 87 661 MWh, or an average output of 10
(multiplied by 8766 hours in an average year). Tr. at 164-165. Article 14.2 of the U.
Geothermal contract states that "sellers failure to limit deliveries by the transmitting entity to the
ORDER NO. 29632
maximum capacity amount will be a material breach of this agreement." Tr. at 199.
alternative suggested by U.S. Geothermal is that contracts could simply expand the definition of
the "maximum capacity amount" to include an appropriate capacity amount for each month
determined by utilizing accepted engineering principles. That provision, along with the
maximum monthly energy amounts would eliminate any risk of abuse. Tr. at 201.
S. Geothermal contends that generator nameplate is not relevant to the contracted
amount, and should not be used to determine the size of the QF. During the extreme heat of
summer months, the generator nameplate could be as much as 17 MW, in order to supply 10
MW of annual average power to the utility. Tr. at 75. Moreover, U.S. Geothermal witness Kitz
contends that there is no actual physical power plant "nameplate " only a power plant design
rating. The rating for thermal power plants, he contends, is the power plant output established at
a very specific set of environmental conditions, including temperature, elevation, relative
humidity, etc. However, those design conditions, he states, are actually met only a very small
percentage of the time. The rest of the time, the output of the power plant is higher or lower
depending on the particular environmental conditions at that time. Tr. at 77-78.
The variation of plant output, U.S. Geothermal contends, would be true also for the
Idaho "surrogate avoided resource" (SAR). Tr. at 79-81. Kitz concludes that it is therefore
reasonable to assume that the Commission expected, and was willing to see, published rates
offered to a nominal 10 MW power plant. A nominal 10 MW power plant would average 10
MW over the year, but would produce less than that in the summer and more than that in the
winter. Tr. at 83. Defining a 10 MW PURP A power plant as limited to the ability to produce no
more than 10 MW in any hour, Kitz contends, would effectively limit any thermal power plant to
a rating of 8.5 MW or less. Tr. at 83. Such a limitation, he contends, would compromise
economies of scale and economic viability. Tr. at 84-85.
PacifiCorp for published rate eligibility recommends (1) a capacity definition of
MW in any hour (Idaho Power s metered energy test); (2) an "initial capacity determination" to
verify that a QF at any time, when operated consistent with the manufacturer s specifications
prudent utility practices and actual operating conditions, has a maximum capacity of 10 MW or
less and is eligible for tariff prices; and (3) a contract provision limiting payment to not more
than 10 MW in any hour. Tr. at 496; 498. The 10 MW ceiling, PacifiCorp contends, should be
determined to be a measure of maximum capacity and not of average energy delivery. Tr. at
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497. By definition, PacifiCorp states, a "megawatt" is a measure of capacity, not average
energy. Tr. at 498. PacifiCorp s position is that the 10 MW capacity ceiling should apply to the
actual capacity of the QF, not just the hourly delivery limitation. Tr. at 500. An initial capacity
determination, it states, is necessary to preserve the integrity of the 10 MW capacity ceiling. Tr.
at 501. Referencing PURPA and FERC regulations at 18 C.R. Section 292.304(c)(2) which
states "there may be put into effect standard tariff prices for purchases from QFs with a design
capacity of more than 100 kW " PacifiCorp notes that FERC's "design capacity" standard
focuses on how the QF will be designed and operated. Tr. at 498; 500.
A vista supports a 10 MW threshold that determines eligibility based on generator
nameplate rating or dependable capacity. Tr. at 537. Commission Staff contends that nameplate
capacity is not a reasonable way to define the 10 MW threshold. Tr. at 590. Idaho Power
believes that a nameplate capacity rating is not very precise. The Company contends, however
that nameplate rating could be used if the Commission would specify a particular methodology
to be used to measure nameplate rating. Tr. at 344.
Commission Staff states that it has always interpreted the 10 MW threshold as a
capacity limit, not 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. Avista concurs
and believes that if eligibility for published avoided cost rates were to be based on average
energy, it could lead to unintended consequences (Tr. at 538). Staff supports the Company
metered energy test, not to exceed 10 000 kWh/hour definition. Tr. at 578; 584. Contrary to
S. Geothermal witness Kitz s testimony, Staff contends that in the regulatory arena plants are
always generally described by the rated capacities, not by their average annual capacities. Tr. at
587. For example, Staff states that the Idaho Power Danskin project (a single cycle natural gas
combustion turbine) is normally referred to as a 90 MW plant because it has the capability to
generate 90 MW under normal conditions. If 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. Tr. at 587.
Staff notes that if a threshold of 10 aMW measured over the course of the year were
used, it could not be verified except on an annual basis. If the QF were found to have exceeded a
10 aMW threshold at the end of a year, Staff contends that it would present administrative and
accounting difficulties to adjust for payments already made to the QF. Tr. at 588. A test based
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on hourly metering, Staff contends, would instead be able to provide almost immediate
verification. Tr. at 588.
It is Staffs belief that a wind project, unless it can meet specific performance criteria
to distinguish it as firm, is not entitled to Idaho s published rates. Tr. at 628.
Commission Findings
The Commission is asked to define a 10 MW threshold for posted rate eligibility.
This issue has come to the fore because of the operational characteristics of geothermal and wind
resources.
Idaho Power recommends a metered energy test - if metered energy is greater than
000/kWh per hour then a QF is greater than 10 MW and not eligible for posted rates. Staff
supports this definition, as does PacifiCorp. While such a test has the attractiveness of simplicity
and ease of verification, it also has limitations when applied to some eligible resources. Idaho
Power prefers a bright line test contending that a technology-by-technology analysis would be
too complex to administer.
Additional standards have also been proposed. A vista recommends an eligibility
standard based on generator nameplate rating or dependable capacity. U.S. Geothermal
recommends that the 10 MW be determined as the project's capability to generate at 10 MW
under normal or average design conditions, a standard based on annual average energy (10
aMW). PacifiCorp in addition to the metered energy test would require an "initial capacity
determination" to determine tariff rate eligibility.
The Commission is also asked to make a distinction regarding eligibility between
firm and non-firm resources. In Order No. 15746 we equated firm with pursuant to a "legally
enforceable obligation ; non-firm we equated to "as available.In doing so we referenced
Section 292.304(d) of the FERC rules. Exh. 59, pp. 13-14. Idaho Power and Staff now suggest
that the term "firm" connotes a level of energy predictability as to amount and time of delivery-
if a QF possesses that capability it is entitled to published rates; if it does not, it is somehow
relegated to non-firm or market based tariff rates. To adopt the Company s definitional proposal
would disqualify intermittent, low capacity resources (wind and solar) that might be unable to
predict amount and timing of generation from posted rate eligibility.
It was suggested in U.S. Geothermal's post-hearing brief that a QF was being
required to exhibit the roughly equivalent operational availability of the SAR or a single selected
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utility resource, in Idaho Power s case the selected resource being a wholesale market purchase.
The complainants contend that a utility s resource portfolio is diversified and includes resources
with different risk characteristics and varying degrees of operational availability. It is improper
they contend, to chose a utility resource and require QFs to model its performance within a band
of operation in order to receive full avoided cost. This Commission has adopted an SAR method
to establish avoided costs, not a method based on a resource portfolio of either existing or
proposed resources. Unless and until that method is changed, it shall remain the standard for
determining avoided cost rates. QFs have the incentive to provide the Company with as much
energy as they are capable of generating. While dispatchability may be of value to the Company
with respect to its own resources, it is not a feature of QF contracts. They should be recognized
for the type of resources they are and valued and integrated accordingly.
The Commission notes that Idaho Power QF contracts have always contained initial
estimates of monthly energy production. The Company admits it has never attempted to revise
the initial estimate in the contracts to comport with actual production but it nevertheless does use
historical generation for planning purposes. The Company has also never required QFs to
deliver their contract estimates. The Commission finds that the firm/non-firm issue raised is
really one of predictability, not capacity factor. The Company has accepted monthly
predictability as reasonably firm. Delivering contract estimates will always provide the utility
with capacity. This is as true for a wind resource as it is for a geothermal resource. If a QF can
provide monthly contract estimates, it is entitled to a published rate contract.
It is the Commission s belief that a legally enforceable obligation translates into
reciprocal contractual obligations for both parties, a quid pro quo. It is not just a lock-in of
avoided cost rates but is also an obligation to deliver. We are asked by the wind QFs to accept
that there is no reciprocal QF requirement other than committing to provide the utility with any
energy actually produced, no obligation to deliver estimated amounts. The question posed by
Idaho Power is whether we should continue with a method that was reasonably well suited for
the usual types of QFs of the past or determine that a different approach is now in the public
interest for a new generation of QFs. The changes in the electric industry and the constraints
challenges and opportunities now faced by Idaho Power indicate to this Commission that the QF
resource portfolio of the Company must be managed or administered more efficiently.
ORDER NO. 29632
The Commission finds that the parties have persuasively established the
unreasonableness of using a simple 10 MW nameplate capacity rating to determine posted rate
eligibility. For QF projects with parasitic load requirements such as U.S. Geothermal, such a
standard would be inequitable. It is also unreasonable for low capacity factor resources such as
wind. The Commission finds that the Company proposed metered energy test, a 10 000 kWh per
hour limit, is operationally too restrictive. The Commission believes that QF generation should
not be measured on an hourly, daily or weekly basis, but rather on a monthly basis. It is on a
monthly basis that QFs are paid. We find that the 10 MW threshold limit, however, must have
some import, some significance if eligibility is to mean anything. The Commission finds it
reasonable to define firmness as predictability on a monthly basis. By way of eligibility criteria
we find it reasonable for the utility to make an initial capacity determination and require that the
QF demonstrate that under normal or average design conditions the project will generate at no
more than 10 aMW in any given month. To provide further definition and sideboards, we also
find it reasonable to cap the maximum monthly generation that qualifies for published rates at
the total number of hours in the month multiplied by 10 MW.
3. 90%/110% Performance Band
During 2003 , Idaho Power purchased about 75 aMW of QF generation, yet the
nameplate capacity of the QF facilities under contract is 182 MW. Tr. at 314. Idaho Power is
requesting that the QF quantify the amount of net energy, in kilowatt hours, that the developer
intends to deliver each month. Tr. at 315. A QF will be allowed to revise its monthly net energy
amounts 6 months after the initial operation date, 12 months after the operation date, and every 2
years thereafter. Tr. at 315-316. At any time, the net energy commitment amount can be
temporarily reduced for force majeure or force outage events. Tr. at 316.
Idaho Power proposes a performance band to firm up QF power and make it more
predictable and reliable. Monthly QF deliveries of energy in excess of 110% of scheduled "net
energy" (up to 10 000 kWh/hour) will receive only 85% of the market price, or the contract rate
whichever is less. The market price is the monthly weighted average of the daily on-peak and
off-peak Dow Jones Mid-Columbia Index (Dow Jones Mid-C Index) prices for non-firm energy.
Tr. at 225.The excess energy rate is the same rate the Commission has approved for tariff
Schedule 86 non-firm energy purchases. Tr. at 317. If the QF provides more than 110% Idaho
ORDER NO. 29632
Power might have to sell the energy in the surplus market or back down a more economic
production plant. Tr. at 316.
If the QF delivers less than 90% of the scheduled "net energy" amount (for reasons
other than forced outage or force majeure events) the proposed FESA provides for liquidated
damages to compensate the utility and its customers for having to acquire energy to make up the
shortfall. Tr. at 317. A shortfall penalty for deliveries below 90% of scheduled "net energy" for
energy not delivered equates to 85% of the market price, less the contract rate. Tr. at 25 , 167
168, 259. If 85% of the monthly weighted average of the actual Mid-C prices is less than the
monthly contract price, the QF pays nothing. Tr. at 319. If greater than the monthly contract
price, the QF pays the difference. Idaho Power has offered to limit QF shortfall exposure by
capping liquidated damages at 150% of the contract price. Letters dated May 21, 2004 (Exhibits
201; 202); Tr. at 319.
Idaho Power contends that by providing economic incentives for QF developers to
more accurately estimate the amounts of firm energy they will deliver each month, the Company
is );loping to encourage developers to deliver firm energy rather than non-firm energy. Tr. at 311
317. Obtaining better estimates of the monthly amounts of firm energy to be provided, Idaho
Power contends, will increase the Company s ability to predict when QF generation will be
available and will improve the Company s ability to integrate QF resources into its resource
planning and acquisition processes as firm resources. Tr. at 311 , 337.
PURP A, Idaho Power contends, provides that avoided costs are based on the cost the
utility can avoid by purchasing from the QF rather than building a resource itself or purchasing
additional resources on the wholesale market. Reference 16 U.C. ~ 824a3(d); Tr. at 334. By
including the firming provisions in the QF contracts, the Company states that it is attempting to
more closely align the firmness of energy purchases under the QF contracts with firm energy
purchases it makes everyday in the wholesale market. Tr. at 334-336.
The Company contends that it is seeking to improve the firmness or predictability of
QF energy deliveries because conditions have materially changed. Tr. at 312. The changed
conditions include:
1. Wholesale markets have standardized the terms and conditions of
wholesale firm energy transactions. As a result, wholesale firm energy
purchases from creditworthy counterparties are now generally accepted
ORDER NO. 29632
as a prudent and cost-effective way of meeting a portion of a utility
resource needs. Tr. at 313.
2. Idaho Power has changed from an energy-constrained company to
capacity-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. Tr. at 313.
3. Transmission constraints require that Idaho Power more precisely
anticipate its needs for firm energy imports. Tr. at 313.
4. The growing prominence of intermittent generating technologies, such as
wind and solar, require a new approach in the Company PURPA
contracting procedures. Tr. at 313.
5. The Company s increased use of firm market purchases as hedges to
manage risk escalates the importance of predictable resource availability.
Tr. at 313.
Dr. Reading, witness for the wind QFs, contends that under PURP A, QFs are entitled
to be paid full avoided cost rates for all of their production and that requiring them to pay a
shortfall energy payment for power not produced is a concept not provided for in PURP A. Tr. at
260. Liquidated damages, Reading contends, is designed for parties to a contract to define
damages in advance of the breach, so that if a breach occurs there is no dispute over either the
level of damages or the methodology used to measure those damages. Tr. at 264. Idaho Power
contends that its proposal to use the average Mid-C pricing is not a penalty but is a reasonable
way of computing liquidated damages. Tr. at 322. The Company contends that Reading is
incorrect when he states that Idaho Power can readily calculate whether and how much it was
damaged by the QF developer s failure to supply an agreed upon amount of energy. First, the
Company points out that the energy shortfall is based on a monthly total. During any month, the
Company engages in numerous wholesale purchases/sales. Tr. at 322. Engaging in economic
dispatch, the Company runs different generating resources at different times, etc. Tr. at 322-323.
To demonstrate the reasonableness of liquidated damages, Idaho Power questions whether it
would be fair to allow the Company to choose which transactions in a month it would attribute to
the QFs failure to perform. Tr. at 323. At the same time, it contends that it is unfair to assume
that the QFs failure to deliver has no cost impact on the Company s power supply expense. Tr.
at 323.
ORDER NO. 29632
Staff agrees conceptually with the use of a performance band. Tr. at 591. Staff
recommends that the band be widened to 80/120. Tr. at 578. Staff notes that it is possible that if
generation falls short enough (90/110), that the project will owe money to the utility if it fails to
produce. Exh. 102; Tr. at 591. Staff notes that in the last 19 months Idaho Power s PURPA QFs
have delivered an average of 71 % of their contracted energy. Staff notes that none of the
projects have ever been held to their contract estimate amounts nor have any ever revised their
original contract amounts based on the amounts the project has proven able to deliver. With
incentives to deliver at least 80% of their monthly generation estimates, and periodic
opportunities to revise the estimates, Staff believes that 80% is achievable by most QF projects.
Tr. at 597.
Regarding Staff s proposal to expand the performance band to 80/120, Idaho Power
contends that increasing the upper and lower bounds reduces the firmness and weakens the
Company s ability to plan for a specific amount of energy from the QF each month. Tr. at 363.
Bandwidth only provides a financial incentive for the QF to set the estimated monthly generation
levels at reasonable, attainable levels for that specific facility and then perform accordingly, the
Company contends. Tr. at 365.
Staff contends that it is necessary to place a cap on the potential exposure QF
developers would face in the event their project is unable to meet the lower band and agrees with
the 150% cap proposed by Idaho Power. Tr. at 599. U.S. Geothermal contends that the
proposed cap on liquidated damages may still result in a one or two month shortfall wiping out
an entire year of profits or possibly even throwing a QF into bankruptcy.
The selection of a 90/110 band, U.S. Geothermal contends, appears arbitrary and
without a technical basis for justification. Tr. at 98. U.S. Geothermal contends that "the lesser
of' provision is unfair and is inconsistent with the Commission pricing criteria for non-firm
energy (85% of Mid-C market prices). Tr. at 226-227. The cost (and value) of firming the
delivery of power from the SAR, U.S. Geothermal contends, is not included in the published
rates. Tr. at 108, 169. Idaho Power, it states, has selected a "seasonal" approach to power
pricing, yet the penalties are monthly. If firmness is desired, U.S. Geothermal contends that it
would be far more reasonable to use "seasonal" firming, rather than monthly firming. Tr. at 100.
The only reason allowed, contractually, for failure to deliver, U.S. Geothermal
contends, would be "force majeure." The band, it contends, makes no allowance for the normal
ORDER NO. 29632
breakdown of equipment. Tr. at 98. So the routine failure of one of the downhole production
pumps, warmer than normal weather, or a shut down for scheduled maintenance one week early
would all result in the imposition of penalties. Tr. at 100. U.S. Geothermal further contends that
there is no opportunity to "make up" for power that is not delivered on either a monthly, or more
reasonably, seasonal basis, as is common in other firming contracts. Tr. at 100; 108.
S. Geothermal witness Runyan contends Idaho Power would have the Commission
believe that the 90/110 performance band is necessary to limit CSPP producers' discretion over
the operation of their facilities. But the fact is, Runyan contends, that Idaho QF projects receive
payment only for energy delivered - the ultimate incentive for reliable and continuous
production. Tr. at 206; 265. Runyan and Dr. Reading see no justification for performance
penalties. Tr. at 208, 264.
U. S. Geothermal witness Runyan proposes that the Agreement contain the standard
terms and conditions used for PURP A QF projects in Idaho over the last decade. Under such
contracts a QF is paid only for energy actually delivered, without any compensation for capacity.
Tr. at 168. QFs, Runyan contends , should not be held to a performance standard that has not
been required of the SAR. Tr. at 173. In the case of more than 60 PURP A QFs now providing
energy to Idaho Power, even though each individual facility may not be considered "firm " the
group as a whole, Runyan contends, in fact delivered the benefit of a firm resource to Idaho
Power and its customers. Tr. at 176. Regarding reliability/predictable performance, Runyan
contends that CSPP facilities have operated as well and arguably better than utility resources.
Tr. at 205. In reviewing only CSPP thermal projects, Runyan concludes that the deviation over a
seven-year (1997-2003) period was from 93% to 1060/0 of the seven-year average. Tr. at 204.
Idaho Power, he states, is trying to force attributes associated with system and tailored sales into
a contract that is intended to represent an avoided utility rate-based project. Tr. at 176.
S. Geothermal's QF contract proposal provides that any deliveries in excess of
12.7 MW in any hour is a material breach under the agreement. Tr. at 566. The contract also
provides for maximum energy amounts - no obligation to purchase in excess of that number. Tr.
at 542; 567. The contract further provides a net energy amount - what U.S. Geothermal intends
to deliver on a monthly basis. Tr. at 567. Finally, the contract also provides for a maximum
monthly capacity amount. Tr. at 568.
ORDER NO. 29632
Simply put, the wind QFs, Reading states, are arguing for the status quo. Tr. at 289.
Wind, he contends, is a legitimate QF resource that deserves to be treated the same as all other
legitimate resources. Tr. at 276.
Regarding Idaho Power s contention that a 90/110 band is necessary "to better
integrate QF resources into the Company s resource planning and acquisition process as firm
resources " Reading contends that Idaho Power s IRP simply lumps all QFs together in planning
for future years and considers the aggregate as a single resource, not individually modeled for
resource planning. Tr. at 281.
Regarding surplus or excess energy, Reading contends that obviously Idaho Power is
over-reaching here with a "heads they win and a tails the QF loses" pricing scheme. Assuming
the QF has not increased the size above the 10 MW threshold for entitlement to published rates
Reading contends that the Company should be required to pay the contract price for all energy
produced and delivered by a QF. Tr. at 271-272.
PacifiCorp witness Hale agrees that conditioning firm energy pricing on monthly
delivery commitments is a reasonable requirement. Tr. at 496. A utility, he states, should not be
required to pay for any energy delivered in excess of 10 MW in any hour. Tr. at 505. Hale notes
that power has different value depending upon the timing and extent to which the purchaser has
notice or control over delivery. Tr. at 506. Hale agrees with Idaho Power that QFs should be
required to commit to monthly (as opposed to daily or hourly) delivery schedules in order to
obtain firm energy prices. Tr. at 510-511.
Avista supports Idaho Power s proposed metered energy test. Tr. at 541-542. Any
energy delivered above the lesser of (1) the 10 MW threshold or (2) any stated contract hourly
amount, A vista witness Kalich contends, should be purchased at a percentage of market based
rates reflecting the purchasing utility s short-term avoided cost. Tr. at 542. Kalich recommends
that the market rate be equal to 85% of the Mid-C daily index and be capped at the published
avoided cost rate. Tr. at 542. Kalich contends that QFs must provide both capacity and energy
to receive the published avoided cost rate. Tr. at 544. The 90/110 bandwidth, he states, only
requires that resources meet a monthly energy quantity. Capacity, on the other hand, he notes, is
an instantaneous or near-instantaneous product. Wind and other non-firm resources, Kalich
contends, should not be eligible to receive the full, published avoided cost rate because of the
ORDER NO. 29632
absence of firm capacity from these resources. Tr. at 545. To address this problem, Kalich
suggests a capacity discount is a good solution.
Commission Findings
As reflected in our 10 MW cap discussion, the Commission finds that a legally
enforceable obligation translates into contractual obligations of both parties. For a QF it
translates into an obligation or commitment to deliver its monthly estimated production. Idaho
Power proposes that this delivery of committed energy fall within a 90/110 band. Staff proposes
that the band be expanded to 80/120. We find 90/110 to be reasonable. The Commission
recognizes that excess energy is not accepted by the Company without consequence. If
unplanned for and not easily integrated the energy may as suggested by the Company have to be
sold in the surplus market or other more economic resources of the Company backed down.
The Commission finds that energy delivered in excess of 110% should be priced at
85% of the market or the contract price, whichever is less. As reflected in our discussion of 10
MW we find it reasonable to cap the maximum monthly generation that qualifies for published
rates at the total number of hours in the month multiplied by 10 MW. This is also a cap for
excess energy payments. By way of example, a QF that commits to deliver a monthly total of
000 kWh in January and delivers greater than 90% of the commitment amount that month will
receive the posted rate for all energy up to 110% of the 7 000 kWh commitment amount and
85% of the Mid-C market price for energy exceeding 110% up to the 10 MW cap. The QF will
receive no payment for any energy provided above the 10 MW cap.
Idaho Power proposes that if the QF delivers less than 90% of the scheduled "net
energy" amount (for reasons other than forced outage or forced majeure events) that the shortfall
energy be priced at 85% of the market price, less the contract rate, the difference capped at 150%
of contract rate. The Commission believes that such a shortfall energy pricing method might
have the potential of exacting too heavy a price. We instead find it reasonable when the QF fails
to deliver 90% of the monthly commitment amount to price all delivered energy at 85% of the
market price, or the contract rate, whichever is less.
Forced Outage
Idaho Power s contract proposal provides QFs with a "grace period" when the QF
notifies the Company that it is suspending deliveries because a forced outage has occurred.
Forced outages include generating equipment breakdowns, geothermal well breakdowns, Idaho
ORDER NO. 29632
Power line maintenance outages, etc. The contract delivery obligation is adjusted to recognize
the impact of the forced outage. The generation suspension due to the forced outage must last at
least 72 hours. Idaho Power contends that the 72-hour time period is the minimum length of
grace period " not the maximum. Tr. at 362. The 72-hour provision, the Company contends
was included to discourage abuse of the forced outage suspension provision.Without a
minimum outage period, Idaho Power contends that a QF would be incented to declare a forced
outage every time some minor "hiccup" occurred. The intent is not to preclude adjustments for
legitimate forced outages but to discourage unreasonable numbers of declarations of forced
outage that could result in a burdensome amount of accounting and contract administration
activities. Tr. at 362. The Company concedes that a shorter period would also be workable. Tr.
at 363.
S. Geothermal questions why "all" deliveries must be suspended if a unit is
capable of operating at some reduced level. U.S. Geothermal posits that if Raft River has two 5
MW generators and one of them goes down for a day, the contract requires a shutdown of all
MW for 72 hours to avoid contract penalties. If the equipment can be repaired in 24 hours, what
public good, it queries, is served by the requirement to suspend deliveries a minimum of 72
hours? Tr. at 112-113; 211.
Commission Findings
The Commission finds that a minimum outage requirement is reasonable only as to
individual generation units incurring a forced outage event. Unaffected generation units need
not be interrupted.The Company proposes a 72-hour minimum outage requirement but
concedes that a shorter time might also be workable. We find 48 hours to be reasonable.
Revising Generation Estimates
Idaho Power proposes to allow QFs to revise their energy estimates three times
during the first year of operation and every two years thereafter. Tr. at 315-316. Staff contends
that QF project owners should be given more frequent opportunities to revise their monthly
generation estimates. Staff recommends a six-month interval for the duration of the contract.
Tr. at 597.
After the first year the Company believes the two-year period is preferable to the
shorter six-month period. Idaho Power contends that a two-year interval allows the Company to
more easily integrate the QF resource into its biennial IRP planning process. Tr. at 365-367. It is
. .'
ORDER NO. 29632
also important to note, the Company contends , that the estimated generation requirement is only
for total monthly kilowatt hours; it is not measured hourly, daily or weekly.Tr. at 367.
Inaccurate prediction may occur, the Company concedes, but still when the delivery does not
match the schedule, the product deteriorates. Tr. at 416. For a project with greater risk of
generation deviations, Idaho Power suggests that it may be prudent not to estimate generation at
the maximum output but instead to estimate generation at a lower level to allow a "cushion" for
potential times of reduced generation. Tr. at 369.
While favoring a two-year interval, the Company notes that even the more frequent
Staff proposed six-month adjustment would be an improvement over existing practice. If the
Commission is inclined to require a more frequent adjustment interval, the Company proposes a
one-year interval rather than six months.
S. Geothermal notes that a PURP A plant is required under Idaho Power s contract
to forecast its monthly generation up to two years in advance, and if it fails to deliver its
estimated power, then it is penalized. U.S. Geothermal witness Kitz states that Idaho Power
requirement that its generation forecast be set up as much as two years in advance makes no
allowance for weather circumstances beyond the control of the operator. Tr. at 97-98. Anyone
familiar with the weather in the Northwest, U.S. Geothermal witness Runyan contends, knows
that forecasting weather and streamflows two years in advance is a recipe for disaster. Even a
six-month forecast, he contends, is too long. Who in their right mind, he queries, would place
any credence in a November forecast of May streamflows. Tr. at 210. If the Commission deems
such forecast necessary, U.S. Geothermal contends, a one to two month ahead forecast will result
in a much more accurate information, while minimizing the punitive nature of any penalties that
Idaho Power maybe allowed to impose. Tr. at 100-101; 210.
If the Commission adopts the performance band concept, allowing updates every six
months, the wind QFs' witness Reading contends , is reasonable and should be adopted. Tr. at
288. Reading contends that the risk of not being paid is incentive enough, however, to ensure
the highest capacity factor possible from QFs. Tr. at 288.
Commission Findings
The Commission finds that it is reasonable and operationally expedient to require
QFs to provide Idaho Power with monthly kWh production estimates. The estimate amount is
the QF's generation delivery commitment. It is the monthly production estimate that will be
ORDER NO. 29632
used in the 90/110 performance band. The Commission finds it reasonable to provide more
frequent opportunities to revise generation estimates than proposed by the Company. We find
that the interest of the Company in planning for QF resources is better served if the generation
forecast is a reliable estimate. QFs shall initially provide Idaho Power with one year of monthly
generation estimates and beginning at the end of month nine and every three months thereafter
provide the Company with an additional three months of forward estimates. QF opportunities
for estimate revisions begin at the end of month three and every three months thereafter for the
forward period beginning the fourth month out through the end of the estimate period. For
planning purposes, following the first year the Company on a rolling basis will always have six
months of QF production estimates.
4. u.S. Geothermal Request for Grandfathering
Commission Findings
The Commission s Order addresses the three contract provisions objected to by the
QFs. Regarding U.S. Geothermal's request for grandfathering we find that the parties have
never reached agreement or tendered a signed contract. As indicated in our approving Orders
the non-standard contract terms contained in Tiber Montana (Order No. 29232) and Renewable
Energy (Order No. 29487) were non-precedential.This Commission will consider the
reasonableness of any signed contract negotiated by and acceptable to the parties and their
respective arguments as to the equity and fairness in approving same.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Idaho Power Company,
an electric utility, pursuant to the authority and power granted it under Title 61 of the Idaho Code
and the Public Utility Regulatory Policies Act of 1978 (PURP A).
The Commission has authority under PURP A and the implementing regulations of
the Federal Energy Regulatory Commission (FERC) to set avoided costs, to order electric
utilities to enter into fixed term obligations for the purchase of energy from qualified facilities
and to implement FERC rules.
ORDER
In consideration of the foregoing, IT IS HEREBY ORDERED and Idaho Power
Company is directed to conform its QF contracting practice and Firm Energy Sales Agreement
ORDER NO. 29632
contract provision requirements to accord and comply with the Commission s findings as set
forth above.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code ~ 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
~~
",ll
day of November 2004.
See attached Separate Concurrence
and ~issent of Commissioner Smith
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~lJ
D. Jewell
Commission Secretary
O:IPCEO408 10 sw2
ORDER NO. 29632
SEPARATE CONCURRENCE AND DISSENT
COMMISSIONER MARSHA H. SMITH
ORDER NO. 29632
CASE NOS. IPC-O4-8 AND IPC-O4-
I concur in the finding that Idaho Power Company is not a volunteer with respect to
signing a PURP A contract and therefore, a regulatory out provision is not necessary.
I find that U.S. Geothermal is eligible for the posted rates as a project designed and
capable of generating at 10 aMW under normal conditions. Idaho Power is protected by U.
Geothermal-proposed contractual provisions that provide a maximum monthly capacity amount
and no obligation to purchase excess deliveries. This is nothing more than the status quo that has
been available to all other legitimate resources.
I strongly oppose the 90%/110% performance band proposal of Idaho Power and also
do not favor the 80%/120% proposal of the Staff. It is my belief that project developers that sign
PURP A contracts have a legally enforceable obligation. The incentive for them is to provide all
the power they can. They need to be paid to stay in operation and if they do not produce, they do
not get paid. The banding proposal would operate as a penalty, not an incentive.
MARSHA H. SMITH, COMMISSIONER