20130108Petition to Reconsider.pdf

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ATTORNEYS AT LAW
Tel: [phone] Fax: [phone]
P.O. Box 7218 Boise, ID 83707 - 515 N. 27th St. Boise, ID 83702
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UTIUT. IE$ COMMIS S
January 8, 2013
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
RE: GNR-E-11-03 -Petition for Reconsideration
Dear Ms. Jewell:
Enclosed please find the Petition for Reconsideration of J.R. Simplot Company, and
Clearwater Paper Corporation. Per the Commission's Rules of Procedure, we have
enclosed and original and nine (7) copies, as well as a copy for our office.
Sincerely,
Peter J. Richardson
Richardson & O'Leary PLLC
end.
Peter J. Richardson (ISB # 3195)
Gregory M. Adams (ISB # 7454)
Richardson & O'Leary, PLLC
515 N. 27th Street
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
[e-mail]
gregrichardsonando1eary.com
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Attorneys for J.R. Simplot Company, and
Clearwater Paper Corporation
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-1 1-03
IN THE MATTER OF THE COMMISSION'S ) PETITION FOR RECONSIDERATION
REVIEW OF PURPA QF CONTRACT ) OF J.R. SIMPLOT COMPANY AND
PROVISIONS INCLUDING THE ) CLEARWATER PAPER CORPORATION SURROGATE AVOIDED RESOURCE (SAR) )
AND INTEGRATED RESOURCE PLANNING)
METHODOLOGIES FOR CALCULATING )
PUBLISHED AVOIDED COST RATES. )
COMES NOW, J. R. Simplot Company and Clearwater Paper Corporation (individually
"Simplot" or "Clearwater," and collectively "Petitioners"), and pursuant to Rule of Procedure
("RP") 331 of the Idaho Public Utilities Commission ("Commission" or "IPUC"), hereby
respectfully requests reconsideration of the Commission's Order No. 32697. That order
addressed several issues related to the Commission's implementation of the mandatory purchase
obligations of the Public Utility Regulatory Policy Act of 1978 ("PURPA"). For the reasons set
forth below, Petitioners respectfully request that the Commission reconsider and revise its
determinations in Order No. 32697 as follows:
CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
PAGE 1
. Disavow use of the "singe-run" methodology for calculation of avoided cost rates for
qualifying facilities ("QF") in the Integrated Resource Plan ("IRP") methodology, and
instead require use of the IRP methodology proposed by Petitioners' witness, Dr. Don
Reading; and
. Declare that QFs retain ownership of all environmental attributes, including renewable
energy credits ("RECs"), when they sell QF energy and capacity to a utility at avoided
cost rates calculated with the IRP methodology.
I.
PROCEDURAL AND FACTUAL BACKGROUND
The Commission entered its Final Order in this matter on December 18, 2012 (Order No.
32697). Among other issues addressed, the Commission determined that published avoided cost
rates would be calculated utilizing a modified version of the Commission's long-standing
surrogate avoided resource ("SAR") methodology. Order No. 32697 at 13-17. The Commission
determined that these published rates will be unavailable for wind and solar QFs over 100
kilowatts ("kw") in capacity, as well as any other QF selling in excess of 10 average monthly
megawatts ("MW"). Id. at 13. The Commission required use of the IRP methodology to
calculate rates for QFs ineligible for the published avoided cost rates. Id.
Among the issues the Commission addressed in calculation of avoided cost rates in the
IRP methodology, the Commission determined to adopt Idaho Power Company's ("Idaho
Power") "single-run" methodology. Id. at 21. This was a drastic departure from prior practice,
which substantially reduces the payment to QFs entitled to IRP-based rates.
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With regard to ownership of environmental attributes or RECs, the Commission first
determined that it had jurisdiction to resolve the dispute regarding treatment of non-energy
environmental attributes in QF power purchase agreements ("PPA"). Id. at 44-45. Next, the
Commission correctly stated that "there is no Idaho law that implements a renewable portfolio
standard (RPS) program or addresses the ownership of RECs[,]" and correctly stated that
"Idaho's avoided cost rates do not compensate QFs for RECs." Id. at 45. Thus, the Commission
determined, "Because the SAR Methodology is based upon a gas-fired surrogate and such a
resource produces no RECs, we find that it is reasonable and appropriate to assign the RECs for
SAR-based QFs to the QFs." Id. at 46. Yet, by a confusing twist in logic, the Commission then
determined, "Under the IRP Methodology, we find that splitting RECs either 50%-50% each
year over the life of the PPA, or equally in terms of years over the length of the contract, is
reasonable." Id. The Commission did not state that utilities must pay for their 50% share of the
RECs generated by an IRP-based QF, and appears to have determined that the utilities will
receive the RECs free of charge. Id.
Pursuant to IPUC RP 331, Petitioners hereby timely file this Joint Petition for
Reconsideration. Petitioners operate QFs that are currently producing, or could be modified to
produce, in excess of 10 aMW, and Petitioners may also seek to develop other QF resources in
the future in excess of the eligibility cap for SAR-based rates. Petitioners are thus impacted by
the Commission's determinations regarding the IRP methodology rates. Petitioners request that
the Commission reconsider its determinations for the reasons set forth below.
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II.
LEGAL STANDARD
IPUC RP 331.01 provides, "Petitions for reconsideration must set forth specifically the
ground or grounds why the petitioner contends that the order or any issue decided in the order is
unreasonable, unlawful, erroneous, or not in conformity with the law, and a statement of the
nature and quantity of evidence or argument the petition will offer if reconsideration is granted."
See also I.C. § 61-626.
III.
GROUNDS FOR RECONSIDERATION
This Petition seeks reconsideration regarding use of the "single-run" methodology for
calculating avoided cost rates in the IRP methodology,' and the Commission's determination that
the utility owns 50% of the environmental attributes or RECs when it purchases QF energy and
capacity with rates calculated under the IRP methodology.2 The nature and quantity of evidence
or argument that the Petitioners would present on reconsideration is contained in this pleading
and its attachments. Petitioners stand ready to present further briefing, oral argument, or any
further technical testimony the Commission may request on the issues raised in this Petition.
Petitioners do not request reconsideration of the Commission's other determinations regarding calculation
of IRP methodology rates, including that QFs entering into contract renewals will be paid for capacity for the full
term of the renewed agreement, that QF energy payments will not be discounted for transmission and line loss when
a utility is energy surplus, and that the Commission will review capacity sufficiency determinations from the IRP.
Order No. 32697 at 21-23.
2 Petitioners do not request reconsideration of the Commission's determinations that the Commission has
jurisdiction to resolve the dispute between QFs and utilities regarding how QF PPAs should address ownership of
environmental attributes, or that QFs paid with SAR rates will retain their environmental attributes. See Order No.
32697 at 43-46.
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A. The Commission Should Reconsider Order No. 32697 By Disavowing Use of the
"Single-Run" Method for Calculating IRP Methodology Rates Because It Produces
Rates Below the Full Avoided Costs.
Federal law requires utilities to contract with each QF at the full avoided cost rates. The
U.S. Supreme Court has upheld the Federal Energy Regulatory Commission's ("FERC")
regulations requiring utilities to purchase capacity and output of QFs at full avoided cost rates.
Amer. Paper Inst., Inc. v. Amer. Elec. Power Serv. Corp., 461 U.S. 402, 413, 417-18 (1983); 16
U.S.C. § 824a-3(b), (d); see also Small Power Production and Cogeneration Facilities;
Regulations Implementing Section 210 of the Pub. Util. Reg. Pol. Act of 1978 ("Order No. 69"),
45 Fed. Reg. 12,214, 12,222-12,223 (Feb. 25, 1980) (promulgating avoided cost regulations and
directly rejecting proposals to provide QFs with rates at less than the full avoided cost);
Whitehall Wind, LLC v. Montana Pub. Service Commn., 355 Mont. 15, 21, 223 P.3d 907, 911
(20 10) (reversing state commission determination of avoided costs because record on the whole
demonstrated rates relying on stale data were below the actual avoided costs).
Order No. 32697 approved sweeping changes in how avoided cost rates are set using the
IRP methodology. The Commission summarized this highly complex and multi-faceted issue as
follows:
Idaho Power proposed revisions to the IRP Methodology that focus on
identifying the incremental costs that its system would incur, i.e., a single-run
simulation, rather than its current methodology that is primarily predicated on
making surplus sales at the future market prices developed within the AURORA
model, i.e., a two-run simulation. In order to do this, Idaho Power proposes to use
the AURORA model to determine the highest displaceable incremental cost being
incurred during each hour of the QF's proposed contract term. The Company
claims that its proposed modified methodology better aligns with the definition of
avoided cost from federal regulations, and results in a much better estimation of
the costs the utility is capable of avoiding.
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Order No. 32697 at 21 (emphasis in original). One cannot discern from the Commission's
discussion that any other party even addressed the issue. In fact, Dr. Reading on behalf of
Clearwater, Simplot, and Exergy Development Group of Idaho, LLC and Don Schoenbeck on
behalf of the Canal Companies each extensively addressed this proposal and each reached
separate conclusions that it is fatally flawed and contrary to PURPA. See Reading DI at 27-29;
Schoenbeck DI at 17-21.
In its second paragraph addressing this issue, the Commission made the following
findings:
The Commission finds Idaho Power's proposed modifications to the IRP
Methodology reasonable. We agree that the Company's revisions properly focus
the determination of avoided costs on incremental costs, not solely on the value of
potential market sales. The result, we find, is a more accurate avoided cost.
Moreover, we fmd that the modified methodology comports with the definition of
avoided cost contained in FERC regulations. Therefore, we direct Idaho Power,
Avista and Rocky Mountain Power to utilize displaceable incremental costs in
calculating avoided costs under the IRP Methodology.
Order No. 32697 at 21. Remarkably, in the immediately preceding section of the Order, the
Commission found that, "the IRP models used by each individual utility produce reasonable
avoided cost rates consistent with PURPA and FERC regulations." Id. at 20. Indeed, even Idaho
Power's witness, Karl Bokenkamp, testified that the pre-existing IRP methodology "is a far more
accurate approximation of avoided cost than the more generic SAR methodology." Bokenkamp
DI at 6. Of course, the Commission continues to use the SAR methodology for all resources
under 10 aMW and wind/solar under 100 kw, stating, "We acknowledge Idaho Power's efforts to
devise an alternative wholly different than the SAR method currently used to obtain published
avoided cost rates. However, we are not prepared to abandon the SAR method entirely." Order
Twin Falls Canal Company, Northside Canal Company and the Renewable Energy Coalition.
CASE NO. GNR-E-1 1-03
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No. 32697 at 14. The inconsistency is perplexing. While extolling the virtues of the pre-existing
IRP methodology, Idaho Power proposed to devise a modification that substantially reduces the
avoided cost rates. See Schoenbeck DI at 20 (containing a comparison of the rates calculated in the
pre-existing IRP Methodology and the "single-run" methodology).
Idaho Power's proposal adopted by the Commission is summarized by Mr. Bokenkamp
as follows:
[T]he main difference is that in Idaho Power's current implementation of the IRP
methodology, the QF generation supports market sales which generate revenues
that reduce Idaho Power's calculated power supply costs, essentially valuing the
QF generation at AURORA' s estimate of future market prices with customers
talking all of the price risk. Under the proposed methodology, the QF generation
does not support surplus sales, it is simply valued at the highest displaceable
incremental cost Idaho Power is incurring during the hour.
Bokenkamp DI at 21. Mr. Bokenkamp's rationale is rooted in a flawed reading of PURPA.
Although he accurately quoted the definition of avoided costs, Mr. Bokenkamp posited that the
avoided cost rate produced by the pre-existing IRP methodology is improperly predicated, in
part, on making surplus sales at future market prices developed within the AURORA model. He
made the following incredible legal conclusion:
This deviates from the definition of avoided cost, which is focused on the
incremental cost to an electric utility of displaced generation or purchases.
Projected revenue from surplus sales is never mentioned in the federal regulation
definition of avoided cost.
Bokenkamp DI at 7.
By restricting the definition of "cost" to exclude surplus sales made possible by QF
purchases, Mr. Bokenkamp turns PURPA and traditional ratemaking on its head. Without those
surplus sales that are only made possible by the QF purchase, Idaho Power would have lost an
opportunity sale - which is a concept well established in electric utility ratemaking. The concept
CASE NO. GNR-E-1 1-03
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and quantification of lost opportunity sales is a concept that is commonly recognized in the
PURPA context as well. In fact, much of Idaho Power's PURPA wind integration charge is based
on lost opportunity sales due to the requirement imposed by that intermittent resource for higher
reserves. The opportunity to make surplus sales at a profit is part and parcel with the reality of
how Idaho Power runs its system, and is a well-known factor used by the Company in evaluating
the benefit of future non-QF resources. Notably, Idaho Power has not proposed to use the
"single run" methodology in its IRP planning process, where it will obviously prefer to consider
the benefits of off-system sales its proposed utility-owned resources may provide.
Apparently the Commission put much stock in Mr. Bokenkamp's inventive definition of
costs and failed to recognize the significance of surplus sales when it stated, "We agree that the
Company's revisions properly focus the determination of avoided costs on incremental costs, not
solely on the value of potential market sales." Order No. 32697 at p. 21 (emphasis provided).
The order over-stated the record by asserting that the pre-existing IRP methodology is focused
"solely" on potential market sales. Not even Mr. Bokenkamp's strained testimony went that far.
What Mr. Bokenkamp missed in his definition of cost is the key "but for" test concept in
FERC's avoided cost rule, which states:
Avoided costs mean the incremental cost to an electric utility of electrical energy
or capacity or both which, butfor the purchasefrom the gualifvinfçcilitv or
qualifying facilities, such utility would generate itself or purchase.
18 C.F.R. § 292.101(6) (emphasis added). In explaining this concept, FERC directly endorsed
the two-run methodology Mr. Bokenkamp believed to be inconsistent with FERC's avoided cost
rule. FERC stated:
One way of determining the avoided cost is to calculate the total (capacity
and energy) costs that would be incurred by a utility to meet a specified demand
CASE NO. GNR-E-1 1-03
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in comparison to the cost that the utility would incur if it purchased energy or
capacity or both from a qualifying facility to meet part of its demand, and
supplied its remaining needs from its own facilities. The difference between these
two figures would represent the utility's net avoided cost. In this case, the avoided
costs are the excess of the total capacity and energy cost of the system developed
in accordance with the utility's optimal capacity expansion plan, excluding the
qualifying facility, over the total capacity and energy cost of the system (before
payment to the qualifying facility) developed in accordance with the utility's
optimal capacity expansion plan including the qualifying facility.
Order No. 69, 45 Fed. Reg. at 12,216 (footnote omitted).
Mr. Schoenbeck succinctly addressed the problem with Idaho Power's proposal:
[Aln appropriate method for establishing the rates for energy and capacity
payments must reflect the cost that is avoided by purchasing the power from the
QFs. The best manner to implement this fundamental avoided cost "but for"
pricing principle is through employing two production cost simulations. With one
simulation having the QF excluded from the resource mix and a second
simulation with the QF in the resource mix, the difference in cost represents the
costs that would have been incurred "but for" the QF. The costs avoided due to
the presence of the QF cannot be quantified under Idaho Power's single "QF-in"
computer simulation.
Schoenbeck DI at 18-19 (emphasis added). Mr. Schoenbeck did not equivocate; he simply and
logically observed that under Idaho Power's single-run proposal it is impossible to calculate a
utility's avoided costs due to the addition of a QF to its resource stack. Mr. Schoenbeck's
conclusion is, in fact, the only reasonable conclusion. The result is fatally flawed without a
comparison of the utility's overall costs to meet a specified demand before and after inclusion of
the QF.
Dr. Reading provided extensive testimony on the ratemaking principles underlying
marginal cost pricing in the context of setting avoided cost rates. These principles also weigh
against Idaho Power's single-run methodology. Quoting from the leading authority on marginal
cost pricing, Dr. Reading observed:
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Due to the fact that capacity is acquired in discrete blocks and long lead times are
required, utilities will oscillate around the least total cost expansion curve. Rather
than follow the short-run costs in their oscillations around equilibrium, it I
recommended that, pj marginal costinpuryoses, the lonc&run marginal costsQ(
generating capacitybe used except in chronic cases of imbalance.
Reading DI at 11 (emphasis in original).
The problem with Idaho Power's proposal is that it only calculates avoided cost rates on a
very short run basis. As pointed out by Dr. Reading, this results in wildly inaccurate avoided
cost estimates:
In practical terms what this means is, over time, a utility will in the normal course
of building plant to meet load almost always have surplus generating capacity.
Because generation plant will be added in chunks that will exceed its shorter-term
load needs it will thus almost always have a capacity surplus.
Reading DI at 11-12. Using the short-run marginal costing model to estimate long-term avoided
cost rates deprives the QF of the benefit of having made the utility surplus at a time when excess
generation could be sold at a profit. Dr. Reading noted that such a deprivation means that the QF
will never be compensated "on an equal basis." Of course, this is the very same point that Mr.
Schoenbeck made in stating that, "The costs avoided due to the presence of the QF cannot be
quantified under Idaho Power's single 'QF-in' computer simulation." Unfortunately, Order No.
32697 does nothing to address the conclusions from these two highly respected experts in this
field that it is impossible for Idaho Power's single-run model proposal to even begin to
approximate an accurate estimate of a utility's avoided cost rates. The resulting adoption of
Idaho Power's "single-run" methodology will deprive IRP-based QFs of compensation at the full
avoided costs. The Commission should disavow use of the single-run methodology.
CASE NO. GNR-E-1 1-03
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B. The Commission Should Reconsider Order No. 32697 and Declare that QFs Retain
Ownership of All Environmental Attributes and RECs When QFs Sell Energy and
Capacity At Avoided Cost Rates Calculated with the IRP Methodology.
The determination in Order No. 32697 that the utilities will own 50% of the
environmental attributes in an IRP-based contract is unreasonable, unlawful, erroneous, or
otherwise not in conformity with the law for several different reasons. The reasoning violates
PURPA by assuming that Idaho QFs are compensated for renewable attributes, by discriminating
against QFs as opposed to non-QFs, and by imposing a new condition on large QFs' access to
full avoided cost rates. Additionally, the order amounts to a physical taking of 50% of IRP-
based QFs' RECs in violation of the Idaho and U.S. Constitutions. The order also violates the
Dormant Commerce Clause of the U.S. Constitution by requiring in-state processing of a
commodity the State of Idaho has not created - thus burdening the interstate flow of goods to
benefit the Commission's chosen local proprietors. Furthermore, the reasoning arbitrarily
disregards the Commission's past determination that a utility (Idaho Power) may not condition
its federally mandated purchase of QF power on a right offlrst refusal to also buy the QF 's
RECs - which determination could only be construed as the equivalent of an order that Idaho
Power does not own the RECs. Finally, the reasoning and outcome of the order cut against the
Commission's duty to encourage QF development by undoing the financial benefits conferred on
Idaho QFs by neighboring states' renewable portfolio standard ("RPS") laws.
1. Order No. 32697 is inconsistent with PURPA because it assumes that IRP-
based rates compensate QFs for non-energy, renewable attributes, or
otherwise provide favorable treatment to QFs that must be mitigated.
Idaho utilities must pay QFs the full avoided cost for their energy and capacity. See 16
U.S.C. § 824a-3(d); Amer. Paper Inst., Inc., 461 U. S. at 413, 417-18. At the same time,
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however, avoided costs do not compensate the QFs for anything other than their energy and
capacity. See Amer. Ref-Fuel Co., 105 FERC 161,004 (2003). FERC has stated, "[t]he avoided
cost rates, in short, are not intended to compensate the QF for more than capacity and energy."
Id. at ¶ 22. FERC declared "contracts for the sale of QF energy and capacity entered into
pursuant to PURPA do not convey RECs to the purchasing utility absent an express provision in
a contract" or a rule of state law to the contrary. Id. at ¶ 24. "If avoided costs are not intended to
compensate a QF for more than capacity and energy, it follows that other attributes associated
with the facilities are separate from, and may be sold separately from, the capacity and energy."
Amer. Ref-Fuel Co., 107 FERC ¶ 61,016, ¶16 (2004), den 'g reconsid. (emphasis added).
Order No. 32697 itself correctly acknowledged that "Idaho's avoided cost rates 4.q not
compensate QE1J RECs." Order No. 32697 at 45 (emphasis added). The order also correctly
concluded that it is reasonable and appropriate to assign the RECs for SAR-based QFs to the
QFs. Id at 46. Because the avoided cost rates are not intended to compensate the QF for more
than energy and capacity, the Commission's determination with regard to SAR-based rates was
consistent with FERC' s reasoning that "other attributes associated with the facilities are separate
from, and may be sold separately from, the capacity and energy." Amer. Ref-Fuel Co., 107
FERC ¶ 61,016, at ¶ 16 (emphasis added).
Yet Order 32697 nevertheless reasoned that the IRP-based rates compensate QFs for
some of their RECs, or somehow compensate QFs for some of the costs associated with being a
renewable facility, and thus deemed it proper to assign 50% of the RECs to the utility. Id. at 46.
The order's string of logic is that IRP-based rates "are based on the actual generation
characteristics of the renewable resource," and "Renewable resources, whether utility or QF
CASE NO. GNR-E-1 1-03
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owned, produce RECs." Id. at 46. Thus, the order stated, "we find it reasonable to equally
apportion RECs between the utility and the QF." Id. The Commission further reasoned, "From
the utility's perspective, selling RECs produces revenue which directly offsets the utility's (and
ratepayers) costs of purchasing power from QFs." Id. This reasoning is inconsistent with
PURPA because —just like the SAR-based rates - the IRP-based rates only compensate for
energy and capacity. IRP-based QFs are entitled to the full avoided cost rates for their energy
and capacity. There is no basis in PURPA to assume IRP-based QFs are compensated for
renewable characteristics or that the Commission must mitigate the utilities' cost of purchasing
energy and capacity at avoided cost rates.4
FERC itself has expressly stated so in a decision issued after the hearing in this
proceeding. See Morgantown Energy Assoc., 140 FERC 161,223 (Sep. 20, 2012), deny'g
recon.5 There, FERC addressed an order of the Public Service Commission of West Virginia
assigning RECs in certain QF contracts to utilities. FERC noted that "the West Virginia Order,
in fact, makes a number of express statements concerning the favorable nature of PURPA
avoided cost rate contracts and how those favorable PURPA avoided cost rates support its
finding that electric utilities should own RECs produced by QFs in the first instance." Id at ¶
19. FERC found such statements inconsistent with PURPA.
The reasoning of Order No. 32697 is substantively indistinguishable from the reasoning
of the West Virginia Commission, and is likewise inconsistent with PURPA. For example,
Indeed, as argued above, IRP-based QFs will be compensated for substantially less than the full avoided
costs under the "single-run" methodology. This even further undermines the logic that there need be some rate
mitigation for purchases from IRP-based QFs.
This dispute has now progressed to the United States District Court for the Southern District of West
Virginia (Case 2: 12-cv-0 1809), where the QFs have commenced an enforcement action under Section 210(h) of
PURPA.
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FERC noted: "The West Virginia Order went on to note that the other states 'found that it was
unfair for the utility customer to pay additional costs to purchase the credits. . . when they had
already paid for the electricity at higher market rates to promote PURPA policies and the
development of QFs[.]" Id. at ¶ 19 n.39. Similarly, Order No. 32697 reasoned, "Splitting RECs
under the IRP Methodology for wind/solar QFs larger than 100 kW and other QFs larger than 10
MW also mitigates those arguments that assigning RECs to either the QF or the utility in their
entirety represents a revenue windfall to the recipient." Order No. 32697 at 47 (emphasis
added). A QF's receipt of payment for its RECs is not a windfall; it is compensation for the sale
of an attribute other than the energy and capacity it sells to the utility.
In another passage, FERC explained:
It is likewise significant, we find, that the West Virginia Commission implied that
RECs produced by non-QFs could be considered to be owned by the non-QF
generator in the first instance rather than the first purchaser of the output of the
non-QF generator. The only reasonable reading of the West Virginia Order is that
the West Virginia Commission's finding that RECs produced by QFs, as opposed
to RECs produced by non-QFs, are owned by the purchasing utilities in the first
instance is based on the West Virginia Commission's belief that the PURPA
avoided cost rates are overly generous and therefore must include RECs.
Morgantown Energy Assoc., 140 FERC ¶ 61,223 at ¶ 21. FERC ultimately concluded that "the
West Virginia Commission cannot, consistent with PURPA, assign ownership of the RECs to the
Utilities on the grounds that the avoided cost rates in their PURPA PPAs compensate the QFs for
RECs in addition to energy and capacity." Id. at ¶ 24. But that is just what Order No. 32697 did
in this case when it reasoned IRP-based rates "are based on the actual generation characteristics
of the renewable resource," and "Renewable resources, whether utility or QF owned, produce
RECs." Order No. 32697 at 46. It is inconsistent with PURPA to then conclude utilities should
own some of the RECs because IRP-based rates compensate QFs for some of their RECs, or
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somehow compensate QFs for some of the costs associated with being a renewable facility. The
IRP Methodology calculates the value of the energy and capacity to the utility - not the value of
any renewable attributes of the generation.
The Commission's order appears to have confused FERC's precedent. FERC has indeed
ruled that a state utility commission may require a utility to pay a separate, higher avoided cost
rate stream for QFs that will help the utility avoid actual costs of a resource procurement
requirement in addition to the providing energy and capacity. Cal. Pub. Util. Commn., 133
FERC ¶ 61,059 (2010), grant 'g clarify and dimiss 'g reh 'g. However, because Idaho law
imposes no renewable procurement requirement, this reasoning is inapplicable in Idaho. The
utilities are only compensating IRP-based QFs for energy and capacity - not any costs associated
with a renewable resource procurement requirement. Thus there is no basis in Idaho law or the
Commission's implementation of PURPA to transfer RECs to the utilities.
The Commission had it right the first time, when it stated "Idaho's avoided cost rates do
not compensate QFs for RECs." Order No. 32697 at 45. This is the case for IRP-based and
SAR-based QFs. And it follows that even IRP-based QFs retain all of those RECs.
2. Order No. 32697 violates PURPA by discriminating against QFs as opposed
to other non-QF generators.
FERC's regulations generally require that QFs be treated in a non-discriminatory manner.
See 18 C.F.R. § 292.304(a)(1)(ii), § 292.306(a). With regard to REC-ownership, FERC has
stated, "[W]hile a state may decide that a sale ofpower at wholesale automatically transfers the
ownership of the state-created RECs, that requirement must find its authority in state law, not
PURPA." Morgantown Energy Assoc., 140 FERC ¶ 61,223 at ¶ 24 (emphasis added). The
problem with Order No. 32697 is that Idaho law does not declare that a sale of power at
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wholesale automatically transfers the ownership of Idaho's state-created RECs.6 Nor does it
even-handedly apply to QF and non-QF generators in the state. Instead, it sets up a regime
where large QFs receiving IRP-based rates must transfer 50% of their RECs, while large non-QF
generators may retain and sell separately all of their RECs or sell their RECs bundled with the
electrical output for additional compensation.
This is demonstrated by a recent non-QF contract approved by the Commission - the
Neal Hot Springs Geothermal contract. See Order No. 31087. Petitioners have attached this
approved contract and order as Attachment 1. In approving the agreement, the Commission
noted "the Agreement is not a PURPA contract." Id. at 2. The Commission expressly noted,
"Although the energy costs for the Neal Hot Springs facility are higher than current PURPA
rates, the Agreement provides benefits to Idaho Power as identified by the Application. For
example, Idaho Power will receive ownership of all renewable energy credits associated with the
facility, and this clearly will provide value to Idaho Power." Order No. 31087 at 4 (emphasis
added). There is no law requiring this non-QF to gift any portion of its RECs, and it therefore
negotiated a higher rate than the mere value of its electrical output (which is by definition the
avoided cost rates) in exchange for also selling its RECs.
Under the reasoning of Order No. 32697, IRP-based QFs selling to the same utility
cannot do this. Instead, IRP-based QFs must cede half of their RECs for no additional payment.
Discrimination occurs because unlike large QFs, large non-QF generators do not automatically
transfer half of their RECs to the purchasing utility. Rather, because they retain all of their
6 Indeed, Idaho law does not even create any such RECs; they exist because neighboring states enacted laws
allowing RECs to be produced by QF and non-QF generators in Idaho.
See also FERC Docket No. ERI3-413 (containing the generator's application to sell as an exempt
wholesale generator at market based rates). A non-utility generator that is not a QF must obtain status as an exempt
wholesale generator from FERC in order to avoid regulation as a public utility.
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RECs, non-QFs can negotiate a better rate to sell electricity bundled with all RECs, or may retain
unbundled RECs and sell them separately. In effect, the order punishes large QFs for utilizing
the mandatory purchase provisions of PURPA. This violates PURPA by discriminating against
QFs.
3. Order No. 32697 violates PURPA by conditioning an IRP-based QF's access
to full avoided cost rates on the QF's agreement to give away half of its RECs
- thus imposing a pre-condition for the benefits of QF status found nowhere
in FERC's regulations.
All QFs have the option to sell energy and capacity to a utility and to receive
compensation at the full avoided cost rates for that energy and capacity. See Amer. Paper Inst.,
Inc., 461 U.S. at 413, 417-18. However, Order No. 32697 imposes a new regime, whereby a
large QF in Idaho may only sell to a utility at the avoided cost rates if that QF agrees to sign a
contract granting the utility ownership of 50% of the QF's RECs. This creates an illegal
precondition on the QF's entitlement to full avoided cost rates.
In an analogous situation, the California Public Utility Commission attempted to use
certain efficiency standards as a precondition to QFs' access to full avoided cost rates. The
Ninth Circuit held that PURPA preempted this precondition to payment at the full avoided costs.
See Ind Energy Producers Assn, Inc. v. Cal. Pub. Util. Commn., 36 F.3d 848 (9th Cir. 1994).
The Court explained:
The CPUC program usurps the [FERC]'s authority by authorizing the Utilities to
determine whether a QF is in compliance with federal efficiency standards. It also
violates PURPA by substituting for any "non-complying" QF an "alternative"
avoided cost rate equal to 80% of the Utilities' avoided cost for short term
economy energy. QFs are entitled to receive the full avoided cost rates provided
in the QF's standard offer contract, 18 C.F.R. Sec. 292.304, and not a rate that is
80% (or less than 80%) of the full avoided cost rate. The CPUC program thus
authorizes the Utilities to deny to QFs one of the benefits to which they are
statutorily entitled under PURPA, resulting in the effective decertification of that
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QF. Because the authority to make QF status determinations resides exclusively
with the Commission, we conclude that the CPUC program is preempted by
federal law.
Id. at 854-55 (emphasis added) (footnote omitted).
The same outcome will unfold in Idaho if utilities can condition access to avoided cost
rates on an IRP-based QF's ability, or agreement, to cede 50% of its RECs. It is now common
for parties to pre-sell forward strips of several years of RECs. However, if a QF had pre-sold its
RECs in a long-term forward strip prior to entering into the PPA, that QF would be unable to
comply with the requirement in Order No. 32697 that it convey 50% of the RECs to the utility. It
is also possible that certain QFs will be structured financially such that the entity responsible for
generating electrical output and contracting with the utility for sale of that output is not the entity
that owns all of the renewable attributes of the facility. This is a likely scenario in the case of
renewable fuel supplier at a dairy, landfill or biomass plant that wishes to retain the renewable
benefits of selling the fuel, which could include both RECs and carbon offsets. In that case, the
QF - despite meeting all of FERC's qualification criteria - would be unable to sign an Idaho
PURPA PPA without restructuring its entire organization. And the utility would obviously
refuse to purchase the QF' s output at the full IRP-based avoided cost rates if the QF cannot cede
50% of its RECs. The QF might be able to negotiate a rate that was less than the full estimate of
the avoided cost rate, for its inability to also convey its RECs. But in either scenario the effect is
inconsistent with PURPA because the state requirement curtails the QF's right to receive full
avoided cost rates for energy and capacity due to a condition found nowhere in FERC's
regulations.
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4. Order No. 32697 effects a taking in violation of the Idaho and U.S.
Constitutions by gifting 50% of an IRP-based QF's RECs to the utility.
Order No. 32697 itself acknowledges that Idaho avoided cost rates do not compensate for
RECs, yet the order nevertheless gifts 50% of the IRP-based QF's RECs to the utility. The Fifth
Amendment of the U.S. Constitution and Article 1 Section 14 of the Idaho Constitution each
provide that private property shall not be taken for public use without just compensation. U.S.
Const. amend. V, cl. 4; Idaho Const. art. 1 § 14. The purpose of the takings clause is to prohibit
the "Government from forcing some people alone to bear public burdens which, in all fairness
and justice, should be borne by the public as a whole." Armstrong v. Us., 364 U.S. 40, 49
(1960). Courts first examine whether the claimant possesses a property interest that is protected
by the Fifth Amendment. Ruckeishaus v. Monsanto Co., 467 U.S. 986, 1003-04 (1984). If such
an interest is established, courts then examine whether the government's action amounts to a
compensable taking of that interest. Id. at 1005-06. When such a taking occurs, an aggrieved
individual may file a claim for "inverse condemnation," which is a shorthand description of the
manner in which a property owner recovers just compensation for a taking of his property when
condemnation proceedings have not been instituted. US. v. Clarke, 445 U.S. 253, 257 (1980).
a. RECs are compensable property rights.
For purposes of Takings Clause analysis, "property" refers to "the group of rights
inhering in the citizen's relation to the physical thing, as the right to possess, use and dispose of
it." U.S. v. Gen. Motors Corp., 323 U.S. 373, 377-78 (1945); see also Lingle v. Chevron US.A.
Inc., 544 U.S. 528, 539 (2005); Loretto v. Teleprompter Manhattan CATV Corp., 458 U.S. 419,
435 (1982). Property interests "are about as diverse as the human mind can conceive." Flor.
Rock Indust. v. US., 18 F.3d 1560, 1572 n. 32 (Fed.Cir.1994). The Takings Clause "is addressed
CASE NO. GNR-E-1 1-03
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to every sort of interest the citizen may possess." Gen. Motors Corp., 323 U.S. at 378; see also
Lucas v. S. C. Coastal Council, 505 U.S. 1003, 1019 (1992) (real property); Monsanto Co., 467
U.S. at 1003-04 (intangible trade secret property); U.S. Trust Co. v. New Jersey, 431 U.S. 1, 19
n.16 (1977) (contract rights); Members of the Peanut Quota Holders Assn v. US., 421 F. 3d
1323, 1332 (Fed. Cir. 2005) (government issued peanut quotas); Roth v. Pritikin, 710 F.2d 934,
939 (2d Cir.1983) (copyright); Redevelopment Authority of Philadelphia v. Lieberman, 336 A.2d
249, 257-59 (Pa. 1975) (liquor license).
Order No. 32697 does not even appear to contest that RECs are a compensable property
interests that are separate and distinct from the energy and capacity sold in a PURPA PPA. As
noted repeatedly above, the avoided cost rates do not compensate QFs for RECs or other
environmental attributes. Indeed, both Petitioners currently have PPAs wherein they contracted
to sell their QF electrical output at the avoided cost rates but retain the right to separately convey
the unbundled renewable attributes of the generation. See Attachment 2 (Simplot PPA and IPUC
order approving it); Attachment 3 (Clearwater PPA and IPUC order approving it). There can be
no doubt that a QF's right to separately transfer the RECs is a compensable property right.
b. Order 32697 Requires IRP-based QFs to Gift Environmental
Attributes to the Utilities, and Therefore Constitutes a Physical
Taking.
Order No. 32697 appears to have reasoned that no taking occurs because the IRP-based
QFs will still own 50% of their RECs, or perhaps that nobody owned Idaho RECs prior to the
Commission's order. See Order No. 32697 at 47. This reasoning is indefensible. Idaho has still
not created any state-created Idaho RECs, or enacted any legislation that automatically transfers
RECs to a utility in all wholesale energy transactions. Instead, through Order No. 32697, the
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Commission has unlawfully impaired IRP-based QFs' ability to possess and sell 50% of their
RECs. Petitioners possessed the RECs associated with their QF output prior to Order No. 32697,
but if Petitioners choose to renew their PPAs to sell at the IRP-based avoided cost rates they will
no longer own 50% of their RECs. By its order, the Commission has now impaired Petitioners'
right to transfer property for compensation.
Where the government requires an owner to suffer a permanent physical invasion of their
property - however minor - it must provide just compensation. See Loretto, 458 U.S. at 438-39
(state law requiring landlords to permit cable companies to install cable facilities in apartment
buildings effected a taking). A second categorical rule applies to regulations that completely
deprive an owner of all economically beneficial use of her property. Lucas, 505 U.S., at 10 19-
1023; Coeur d'Alene Garbage Service v. Coeur d'Alene, 114 Idaho 588, 591, 759 P.2d 879, 881
(1988) (collecting Idaho cases and applying Idaho Constitution to find taking of garbage
collection business by City action curtailing its business).8 Since what the owner had was
transferable value, "the question is, What has the owner lost? Not, What has the taker gained?"
Kimball Laundry Co. v. U.S., 338 U.S.1, 12-13 (1949); see also Yancey v. U.S., 915 F.2d 1534,
1541-42 (Fed. Cir. 1990) (finding a compensable taking where "the Yanceys had no choice but
to sell their birds for substantially less than their value").
Granting the utilities title to 50% of IRP-based QFs' RECs without providing any
compensation to QFs constitutes a categorical taking. The Commission's order will leave the
8 Even when the claimant still retains economic value of its property, just compensation may be required by
weighing relevant factors set forth in Penn Central Transp. Co. v. New York City, 438 U.S. 104, 124 (1978).
However, Order No. 32697 effects a direct appropriation of private property required for a categorical taking, thus
precluding the need to engage in balancing the Penn Central factors for regulatory takings commonly used in zoning
law. In any event, Order No. 32697 would also constitute a taking under application of the factors set forth in Penn
Central because it provides no legitimate basis to impair Petitioners' property rights. See Ruckelshaus, 467 U.S. at
1005-1016; Cienega Gardens v. U.S., 331 F.3d 1319, 1337-53 (Fed. Cir. 2003).
CASE NO. GNR-E-1 1-03
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QFs with no choice but to cut a deal selling their RECs for "substantially less than their value" -
in fact, 50% of the QFs' RECs must be sold for no value. Yancey, 915 F.2d at 1542. Because
RECs are most valuable in forward strips, the order may also impair the value of the remaining
50% of the RECs QFs retain. The ostensible purpose for gifting RECs to the utilities is to
protect utilities and their ratepayers from needing to pay the full avoided cost rates for energy
and capacity. See Order No. 32697 at 46 ("From the utility's perspective, selling RECs produces
revenue which directly offsets the utility's (and ratepayers) costs of purchasing power from
QFs."). To authorize such a seizure under this reasoning would be a classic case of requiring an
individual (QF) to forfeit its property (valuable environmental attributes) for public benefit (the
ability to offset the cost of federally mandated payments to QFs at the full avoided costs) without
any compensation. That is a taking.
The Commission's reliance on the Connecticut case is unavailing. See Wheelabrator
Lisbon, Inc. v. Connecticut Dept. of Pub. Util. Control, 531 F.3d 183 (2nd Cir. 2008). There, the
waste-to-energy QF at issue entered into a PURPA PPA in 1991. Id. at 186. "In 2002, the
specific credits at issue. . . became marketable by the creation of a market for such credits
pursuant to the laws of several states, including Connecticut." Id Based on construction of the
1991 contract, the Connecticut Supreme Court concluded that the 1991 contract assigned REC
ownership to the utility, and therefore the state commission's decision did not constitute a taking
in violation of the state constitution. Wheelabrator Lisbon, Inc. v. Dept. of Pub. Util. Control,
931 A.2d 159, 176-77 (Conn. 2007). The federal district court likewise rejected a challenge
under the takings clause on the ground that the RECs "were created after the parties entered into
the [contract]." Wheelabrator Lisbon, Inc. v. Connecticut Dept. of Pub. Util. Control, 526
CASE NO. GNR-E-1 1-03
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F.Supp.2d 295, 306 (D. Conn. 2006).9 In stark contrast, Order No. 32697 expressly
acknowledges that RECs exist today, and that Idaho avoided cost rates do not compensate QFs
for RECs. Additionally, Petitioners (and many QFs in the state) have existing contracts which
expressly state that Petitioners own the RECs. It follows that requiring QFs to gift 50% of the
RECs to utilities as a precondition to exercise their right to sell QF energy and capacity at
avoided cost rates is a taking of property without compensation.
5. Order No. 32697 violates the Dormant Commerce Clause of the U.S.
Constitution by requiring in-state processing of 50% of Idaho IRP-based
QFs' RECs - thus improperly impeding the flow of interstate commerce
created by other states' policies.
The Commerce Clause of the United States Constitution provides that "Congress shall
have Power.. . To regulate Commerce. . . among the States... ." U.S. Const., Art. I, § 8, ci. 3.
The Dormant Commerce Clause, however, also imposes limitations on states in the absence of
congressional action. "It is well settled that actions are within the domain of the Commerce
Clause if they burden interstate commerce, or impede its free flow." C&A Carbone, Inc. v. Town
of Clarkstown, N. Y, 511 U.S. 383, 389 (1994) (emphasis added). "The central rationale for the
rule against discrimination is to prohibit state or municipal laws whose object is local economic
protectionism." Id. at 390. State laws requiring that goods be processed in-state prior to entering
interstate commerce are per se invalid because such laws block the flow of interstate commerce
at the state's borders. See, e.g., id. at 390 (striking down town ordinance requiring non-
recyclable solid waste to be processed at designated facility within municipality before
shipping); S. Central Timber Devel., Inc. v. Wunnicke, 467 U.S. 82, 100 (19 84) (striking down
The QF did not appeal to the Second Circuit with the taking argument, and therefore the Second Circuit
never addressed the issue. Wheelabrator Lisbon, Inc., 531 F.3d 183. See also City of New Martinsville v. Pub. Serv.
Commn. of W Va., 229 W.Va. 353, 729 S.E.2d 188, 197 n.13 (W.Va. 2012) (concluding no taking occurred in
Commission determination of ownership of RECs in contract pre-dating creation of RECs).
CASE NO. GNR-E-1 1-03
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Alaska regulation that required all Alaska timber to be processed within the state before export);
New Hampshire v. New England Power, 455 U.S. 331, 339 (1982) (holding that law restricting
exports of hydropower violated commerce clause by hoarding resources for State's economic
benefit).
In C.A. Carbone, Inc., the Court specifically noted the ordinance requiring local
processing of solid waste favored only a "single local proprietor," rather than a class of in-state
processors, and held "this difference just ma[de] the protectionist effect of the ordinance more
acute." C&A Carbone, Inc., 511 U.S. at 392. "Discrimination against interstate commerce in
favor of local business or investment is per se invalid, save in a narrow class of cases in which
the municipality can demonstrate under rigorous scrutiny, that it has no other means to advance a
legitimate local interest." Id at 392. (distinguishing Maine v. Taylor, 477 U.S. 131 (1986),
where the Court upheld a restriction on importation of baitfish because Maine had no other way
to prevent spread of parasites and local economic interests were not the state's justification for
the ban).
Here, the Commission's order directs the utilities to take title to an interstate commodity
created by other states' RPS laws - RECs. In discussing RECs, FERC stated, "States, in
creating RECs, have the power to determine who owns the REC in the initial instance,
and how they may be sold or traded; it is not an issue controlled by PURPA." Amer. Ref-Fuel
Co., 105 FERC 161,004 at ¶ 23. Idaho does not have an RPS law that creates "Idaho RECs,"
and the Idaho legislature has stated no purpose whatsoever - let alone a legitimate purpose - to
require QFs to give RECs to the utility. The Commission has deemed a commodity created by
other states to be bundled to electrons for a small class of generators in Idaho - IRP-based QFs.
CASE NO. GNR-E-1 1-03
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To do so - without requiring any compensation - is an act of local protectionism of Idaho's
investor-owned electric utilities that would burden the interstate flow of goods and violate the
Dormant Commerce Clause. C&A Carbone, Inc., 511 U.S. at 390. The order unlawfully
requires the RECs to be processed in-state and then resold out-of-state by the Commission's
chosen proprietors. See Id.; S. Central Timber Devel., Inc., 467 U.S. at 100; New Hampshire,
455 U.S. at 339. Order No. 32697 effectively undermines the policies in neighboring states
designed to provide an economic benefit to those who might expend time and effort to develop,
own or upgrade a renewable energy project - here the IRP-based QF. This impermissibly
burdens interstate commerce.
6. Order No. 32697 is unreasonable, erroneous, and arbitrary and capricious
because it fails to provide a reasoned decision to depart from the
Commission's prior determination refusing to grant Idaho Power a right of
first refusal to buy a QF's RECs.
Order No. 32697 fails to dispense with past Commission orders on this topic, and is
therefore unreasonable, erroneous, and arbitrary and capricious. It is a basic tenet of
administrative law that an agency reversing its prior policy faces a heightened burden to reverse
course. See Motor Vehicle Mfrs. Assn of Us., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S.
29, 42 (1983) ("an agency changing its course by rescinding a rule is obligated to supply a
reasoned analysis for the change beyond that which may be required when an agency does not
act in the first instance."). Order No. 32697 completely overlooks that the Commission has
previously declared that Idaho utilities may not condition the federally mandated purchase of QF
power on a right offirst refusal to also buy the QF's RECs and instead left parties to negotiate
the sale of RECs to the utility.
CASE NO. GNR-E-1 1-03
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Specifically, Idaho Power previously petitioned the Commission for an order declaring
that QFs generating green tags must grant Idaho Power "a 'right of first refusal' to purchase
those tags." Order No. 29480 at 4-5. Petitioners have provided this order as Attachment 4.
PacifiCorp and Avista both intervened and requested that the Commission determine the utilities
own the environmental attributes associated with QF generation. Id. at 5-8. The Commission
found that Idaho Power's petition did "not present ajusticiable controversy in Idaho and [wa]s
not ripe for a declaratory judgment[.]" Id. at 16. The Commission observed the Amer. Ref-Fuel,
Co. orders and noted that the State of Idaho does not have a green tag program or an RPS. It
stated:
While this Commission will not permit [Idaho Power] in its contracting
practice to condition QF contracts on inclusion of such a right-of-first refusal
term, neither do we preclude the parties from voluntarily negotiatin2the sale and
purchase of such a green tag should it be perceived to have value. The price of
same we find, however, is not a PURPA cost and is not recoverable as such by the
Company.
Id. at 16-17 (emphasis added). The Commission's determination that a utility (Idaho Power)
may not condition its federally mandated purchase of QF power on a right offirst refusal to also
buy the QF's RECs is the equivalent of an order that Idaho Power does not own the RECs. So is
the suggestion that Idaho Power could negotiate to purchase those RECs if it wished.
Not surprisingly, Idaho Power thereafter filed for approval of a PURPA contract with J.R.
Simplot Co. containing the published rates for a non-fueled project, wherein Idaho Power
expressly waived any claim to ownership of environmental attributes. See Order No. 29577 at 2-
3. The Commission stated, "The State of Idaho still has not created a green tag program, has not
established a trading market for green tags, nor does it require a renewable portfolio standard."
Id. at 5-6. It again stated that the QF and the utility were free to separately negotiate for the sale
CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
PAGE 26
of environmental attributes, but that the costs associated with the sale could not be recovered by
the utility as a PURPA cost. The Commission ruled, "[a]s qualified above, the Commission
finds it reasonable to approve the submitted Agreement and further finds it reasonable to allow
payments made under the Agreement as prudently incurred expenses for ratemaking purposes."
Id. at 6. Thus, the Commission found it reasonable for the Utilities to waive ownership of
environmental attributes because the utility did not own the RECs.
Despite the obvious intent behind these prior orders, in Grand View Solar P V II v. Idaho
Power Co., the Commission misconstrued its prior order to state that "we have held that the
parties to a QF contract or PPA arefree to contract for the ownership of RECs." Order No.
32580 at 10 (emphasis added). Order No. 32697 likewise relies on this faulty reasoning that its
prior orders merely intended for QFs and utilities to negotiate the ownership of RECs. See Order
No. 32697 at 47. This is perplexing. The prior order did not state parties could negotiate
ownership of RECs. It stated Idaho Power could condition is purchase of QF energy and
capacity on a right of first refusal to also separately purchase the QF's RECs. The Commission
has re-written its prior orders. Doing so is unreasonable, arbitrary and capricious. It is also poor
policy because parties rely upon the Commission's orders. Again, the Commission's
determination that a utility (Idaho Power) may not condition its federally mandated purchase of
QF power on a right ofjirst refusal to also buy the QF's RECs is the equivalent of an order that
Idaho Power does not own the RECs.
Petitioners' own contracts entered into contemporaneous to these prior Commission
orders demonstrate the understanding at the time contemporaneous to the Commission's prior
orders. As with the contract discussed above, the current Simplot contract entered into in 2006
CASE NO. GNR-E-1 1-03
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PAGE 27
contains a clause declaring Simplot the owner of the environmental attributes. See Attachment 2
at Art. 8. In approving the Potlatch contract (now Clearwater), the Commission stated, "The
Commission finds that the $42.92IMWh levelized purchase price for the Potlatch base generation
amount (62 aMW) is a reasonable approximation of Avista's avoided cost and was correctly
calculated under the Commission approved JRP-based avoided cost methodology." Order No.
29418 at 9. The contract expressly disclaims Avista's right to the renewable attributes, and in
fact Clearwater has been separately selling its renewable attributes to Avista under a separate
agreement for additional compensation. See Attachment 3 at § 18. Order No. 32697 operates
under the false assumption that nobody owned the RECs during this timeframe. It is simply not
plausible.
Finally, Order No. 32697's reliance on more recent contracts where Idaho Power was
able to coerce certain QFs into granting Idaho Power the right to 50% of their RECs is
unpersuasive. See Order No. 32697 at 46. As Idaho Power itself freely admitted in this case,
Idaho Power used a title-clouding clause in its draft QF contracts in order to coerce QFs into
gifting RECs to Idaho Power. See Reading DI at Exhibit 506 (containing Idaho Power's
discovery response on its title-clouding clause). Furthermore, despite the implicit assumption of
Order No. 32697, not all of these QFs were IRP-based QFs. See Order No. 32451 (approving the
Riverside Investments QF PPA for a project under 10 MW and ceding 50% of the RECs to Idaho
Power). That these developers chose to give away 50% of their RECs to avoid litigating against
Idaho Power does not undo the Commission's prior determinations on the topic. These contract
approval dockets were not litigated and cannot establish a reasoned basis to depart from the prior
CASE NO. GNR-E-1 1-03
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PAGE 28
determination in Order No. 29480. No reasoned basis exists for why utilities - which previously
could not even insist on a right to buy the RECs - now simply own 50% of the RECs outright.
7. Order No. 32697 discourages QF development by undoing the financial
benefits conferred on Idaho QFs by neighboring states' RPS laws
At bottom, the reasoning and effect of Order No. 32697 blunts the financial benefit
conferred on Idaho QFs by neighboring states' RPS laws - thus running afoul of the
Commission's duty to encourage QF development. See 16 U.S.C. § 824a-3(a). The
Commission went to great lengths in this proceeding to modify calculation of avoided cost rates
to further the principle of ratepayer indifference to QFs. Even if the Commission adopts
Petitioners' recommended revision to the IRP methodology set forth above, the avoided cost
rates to emerge from this proceeding will be far lower for many QFs than they were prior to this
proceeding. This demonstrates, yet again, that QFs receive compensation only for the projected
value to the individual utility of the QFs' energy and capacity. The ratepayers and the utility
should be indifferent. As such, PURPA merely provides QFs with access to sell at a rate
calculated to provide ratepayer indifference.
RECs are different. RECs are a product of certain state's laws designed to provide an
additional economic benefit to promote development of renewable energy projects in the
region.'° Idaho law does not even create any such RECs. The RECs exist because other states in
the region have enacted laws allowing RECs to be produced by QF and non-QF generators in
Idaho. The Commission's order effectively eliminates 50% of the economic benefit of the RECs
for IRP-based QFs. The effect of the order is to go beyond the principle of ratepayer
10 For example, Washington's statement of policy for its RPS states, "Increasing energy conservation and the
use of appropriately sited renewable energy facilities builds on the strong foundation of low-cost renewable
hydroelectric generation in Washington state and will promote energy independence in the state and the Pacific
Northwest region." Rev. Code. Wash. 19.285.020 (emphasis added).
CASE NO. GNR-E-1 1-03
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indifference and to actively discourage QF development by blunting the financial benefit
neighboring states have chosen to confer on Idaho QFs and non-QFs. Aside from the legal
arguments set forth above, the Commission should reconsider whether it wishes to discourage
QF development by implementing a 50% reduction in value of a commodity designed to
encourage renewable resources in the region.
IV. CONCLUSION
For the reasons set forth above, Petitioners respectfully request that the Commission
reconsider and revise its determinations in Order No. 32697 as follows:
. Disavow use of the "singe-run" methodology for calculation of avoided cost rates for
QFs in the IRP methodology, and instead require use of the IRP methodology proposed
by Petitioners' witness, Dr. Don Reading; and
. Declare that QFs retain ownership of all environmental attributes, including RECs, when
they sell QF energy and capacity to a utility at avoided cost rates calculated with the IRP
Methodology.
Petitioners stand ready to present further briefing, oral argument, or any further technical
testimony the Commission may request on the issues raised in this Petition.
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DATED THIS 8th day of January 2013.
RICHARDSON AND O'LEARY, PLLC
By:
Peter J. Ri hardson (ISB No: 3195)
Gregory M. Adams (ISB No: 7454)
Attorneys for
J.R. Simplot Company, and
Clearwater Paper Corporation
CASE NO. GNR-E-1 1-03
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CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
OF J.R. SIMPLOT COMPANY AND CLEARWATER PAPER
CORPORATION
ATTACHMENT 1
Office of the Secretary
Service Date
May 20, 2010
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-09-34
APPROVAL OF AN AGREEMENT TO )
PURCHASE CAPACITY AND ENERGY )
FROM USG OREGON, LLC AND ) ORDER NO. 31087
AUTHORIZE RECOVERY IN THE )
COMPANY'S POWER COST ADJUSTMENT )
On December 28, 2009, Idaho Power Company filed an Application requesting
approval of a Purchase Power Agreement and an accounting order authorizing the Company to
recover purchases of energy and associated costs from the USG Oregon, LLC, Neal Hot Springs
Unit No. 1 geothermal generation facility. The Company seeks recovery of its costs and
purchases in its annual Power Cost Adjustment (PCA).
The Application states that Idaho Power indicated in both its 2004 and 2006
Integrated Resource Plans (IRPs) that it intended to actively seek acquisition of geothermal
generating resources. In 2006, the Company issued a request for proposal (RFP) to acquire
geothermal resources and then entered into an agreement with U.S. Geothermal to purchase
power from its Raft River No. 1 geothermal power plant. Idaho Power issued a new request for
proposal in 2008 to acquire additional geothermal resources. The Company received three
responses, two of which were withdrawn by the bidders, and the Company concluded that the
third bid was too speculative and thus unacceptable. Application, p. 3. The Company's
Application states that this experience with the unsuccessful RFP process demonstrates that "the
competitive RFP process is not the optimal means to acquire geothermal resources."
Application, pp. 3-4. Accordingly, the Company actively pursued discussions with developers of
five different potential geothermal sites, including the Neal Hot Springs site. The Company
believes the Neal Hot Springs development is advantageous for several reasons, including (1)
substantial prior geotechnical exploration at the site, (2) its location in Idaho Power's service
area and proximity to Treasure Valley load centers, (3) available transmission capacity, and (4)
favorable energy pricing in comparison to other proposals. Application, p. 4.
On December 11, 2009, Idaho Power and USG Oregon, LLC entered into a Power
Purchase Agreement providing for the Company's purchase of energy from the Neal Hot Springs
ORDER NO. 31087 1
Unit No. 1 geothermal generation facility. USG Oregon, LLC is a subsidiary of U.S.
Geothermal. The Neal Hot Springs project is located approximately 12 miles west northwest of
Vale, Oregon. The project is expected to produce approximately 22 MW of power with an
estimated online date late in 2012. The Purchase Agreement provides an initial term of 25 years
with an option for Idaho Power to extend the term of the Agreement. The Agreement provides
that Idaho Power will receive the rights to all environmental attributes and renewable energy
credits now available or created during the term of the Agreement. The Agreement grants Idaho
Power the first right-of-offer to participate in any future U.S. Geothermal resource development
at the site or in close proximity to the site. Application, p. 5.
The energy price stated in the Agreement will be seasonally adjusted consistent with
seasonality factors currently used in Idaho Power's PURPA agreements. The Company asserts
that seasonal prices give the correct price signal by promoting production when the value of the
energy to the Company is highest. Beginning in 2012, the flat energy price is $96/MWh. The
price escalates annually, resulting in a 25-year levelized contract price of approximately
$1 17.56/MWh. This compares to a levelized price for a 20-year PURPA contract of
$95.56IMWh. The Company asserts that, while the price of energy under this Agreement is
higher than energy purchased under PURPA contracts, there are benefits to this Agreement that
bring value to Idaho Power's customers that PURPA contracts do not. The Company identifies
these benefits as (1) the Company's rights to any of the project's renewable energy credits, (2)
the limited ability to curtail energy, (3) the right of first offer on ownership of other site
development, (4) exploration, development and construction milestone requirements and
associated damages, and (5) the right to extend the terms of the contract. The Application states
that with the addition of a relatively minor system upgrade, sufficient firm transmission capacity
is available for the full output of the project to be delivered to Idaho Power's load centers.
Because the Agreement is not a PURPA contract, the Company proposes that the cost
of power purchased under the Agreement be recovered in its annual PCA in a manner similar to
other non-qualified facility power purchase expenses. The Company requests that its Application
be processed by Modified Procedure, that the Commission find that the Agreement is prudent for
ratemaking purposes and that the Commission approve its request for recovery of the power
purchase expense associated with the Agreement in the Company's power cost adjustment rate.
On March 17, 2010, the Commission issued a Notice of Application and Notice of Modified
ORDER NO. 31087 2
Procedure that provided notice of an opportunity to file written comments and reply comments
on or before May 13, 2010. The only written comments received were filed by the Commission
Staff.
Staff reviewed Idaho Power's process to obtain proposals for geothermal resources
including the Company's effort to obtain the resources through the RFP process. The Company
issued an RFP in 2006, and ultimately selected a proposal from U.S. Geothermal, Inc. to develop
two 13 MW phases at the Raft River site near Malta, Idaho and two phases at Neal Hot Springs.
Idaho Power issued a new RFP in January 2008 to acquire additional geothermal resources. The
RFP specified bids for up to 100 MW with a target online date of June 2011, but also stated that
the Company was willing to allow flexibility and possible delay in the project online date. The
Company received three responses to the RFP, but ultimately two of the proposals were
withdrawn by the bidders and the Company rejected the third. With this experience, the
Company decided to directly discuss with developers the possibility of geothermal development,
including possible development of the Neal Hot Springs site. Negotiations for generation at the
Neal Hot Springs site began in April 2008.
Staff expressed two concerns with the negotiation process between Idaho Power and
U.S. Geothermal. First, the prices in the Agreement submitted for Commission approval are
higher than the prices offered by U.S. Geothermal in its RFP bid. Second, the scheduled
operation date for the Neal Hot Springs project is much later than both the original 2010 online
date originally proposed by U.S. Geothermal and the June 2011 date requested by Idaho Power
in its 2006 RFP. The parties now estimate an online date of late 2012, but Staff noted that under
the terms of the Agreement the project scheduled operation date could be as late as December
2017. Staff stated it is difficult to confirm that the pricing in the Agreement is favorable
compared to other proposals because those proposals were withdrawn or rejected before serious
negotiations began with U.S. Geothermal regarding the Neal Hot Springs site. Staff Comments,
p.7.
The energy prices contained in the Agreement begin in 2012 at $96 per MWII, and
escalate during the 25 years of the term. Staff compared the contract rates with three other
energy purchase rates to evaluate the reasonableness of the contract terms. Staff compared the
energy prices to a 25-year PURPA contract for a facility smaller than 10 aMW, to a PURPA
facility larger than 10 aMW, and to the cost of power that will be provided by Idaho Power's
ORDER NO. 31087 3
Langley Gulch facility. The rates in the Neal Hot Springs Agreement are higher than all three of
the other facilities. Staff Comments, pp. 7-9.
Despite identifying concerns with the Agreement, Staff recommended the
Commission approve all of the Agreement's terms and conditions as submitted and find that all
payments Idaho Power makes to USG Oregon, LLC for purchases of energy from the Neal Hot
Springs Unit No. 1 generation facility will be allowed as prudently incurred expenses for
ratemaking purposes. Additionally, Staff recommended the cost of power purchased under the
Agreement be recovered in Idaho Power's annual PCA until the next general rate case, at which
time the Company would be allowed to include costs as specified in the Agreement in base rates.
COMMISSION FINDINGS
Based on the record in this case, the Commission has determined to approve the
power purchase agreement as filed with the Application. Although the energy costs for the Neal
Hot Springs facility are higher than current PURPA rates, the Agreement provides benefits to
Idaho Power as identified by the Application. For example, Idaho Power will receive ownership
of all renewable energy credits associated with the facility, and this clearly will provide value to
Idaho Power. Additional favorable contract terms include the Company's ability to curtail
energy deliveries from the project, and the right of Idaho Power to purchase additional
generation capacity if it is added in the future. The Agreement enables Idaho Power the first
right to purchase the facility assets if the owner proposes to sell them during the term of the
Agreement. The Agreement contains liquidated damages for construction delays and energy
shortfall damages, contract terms that make it more favorable to the Company. Finally, Idaho
Power has an option to extend the terms of the Agreement, although any extension requires re-
negotiation of the terms and conditions. These contract terms provide value to Idaho Power in
the project, and taken altogether, make the terms of the Agreement fair and reasonable. The
Agreement also is significant in that it brings a unique generating facility into Idaho Power's mix
of resources.
The Commission notes that this case presents a situation where the RFP process, the
preferred method for obtaining competitive proposals for energy purchases, ultimately was not
successful. Contract terms resulted from direct negotiations rather than through an RFP. In most
circumstances where the RFP process is not successful, Idaho Power is not precluded from
directly negotiating contract terms with a single provider. However, the Company always bears
ORDER NO. 31087 4
the burden, when seeking Commission approval of a purchase agreement, of demonstrating its
terms are fair, just and reasonable.
The Commission finds the terms of the Purchase Power Agreement between Idaho
Power and USG Oregon, LLC, Neal Hot Springs Unit No. 1 geothermal generation facility to be
fair, just and reasonable. Purchases of energy from the Neal Hot Springs Unit No. 1 generation
facility will be allowed as prudently incurred expenses for ratemaking purposes, and may be
recovered in Idaho Power's annual PCA until the Company's next general rate case. Idaho
Power is directed to provide copies of progress reports that are required under the Agreement to
Staff. If the contract terms are amended for any reason, the Company is required to submit the
new terms to the Commission for review and approval.
ORDER
IT IS HEREBY ORDERED that the Application of Idaho Power Company for
approval of the purchase of energy from USG Oregon, LLC, Neal Hot Springs Unit No. 1
geothermal generation facility is approved. Purchases of energy from the Neal Hot Springs Unit
No. I generation facility will be allowed as prudently incurred expenses for ratemaking
purposes, and may be recovered in Idaho Power's annual PCA until the Company's next general
rate case.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this case may petition for
reconsideration within twenty-one (21) days of the service date of this Order with regard to any
matter decided in this Order or in interlocutory Orders previously issued in this case. Within
seven (7) days after any person has petitioned for reconsideration, any other person may cross-
petition for reconsideration. See Idaho Code § 61-626.
ORDER NO. 31087 5
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
day of May 2010.
(d1' /1
MMD. KEMPTON, PRESIDENT
A444C If, &~~
MARSHA H. SMITH, COMMISSIONER
MACK A. iwDFORD, C"ISS Y6NER
ATTEST:
Jeo D. Jewell (J Cànmission Secretary
bIs/0:IPC-E09-34_ws2
ORDER NO. 31087 6
BARTON L KLINE
Lead Counsel
bkIineidahopower.com
December 28, 2009
E Foy
IHO
- An IDACORP Company
Th09 DEC 28
wNU
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P.O. Box 83720 -
Boise, Idaho 83720-0074
Re: Case No. IPC-E-09-34
IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY
FOR AN ACCOUNTING ORDER AUTHORIZING THE INCLUSION OF
POWER SUPPLY EXPENSES ASSOCIATED WITH THE PURCHASE OF
CA PA CITYAND ENERGY FROM USG OREGON LLC IN THE COMPANY'S
POWER COST ADJUSTMENT
Dear Ms. Jewell:
Enclosed please find for filing an original and seven (7) copies of Idaho Power
Company's Application in the above matter.
Very truly yours,
DFLU1 I L. !'%III I
BLK:csb
Enclosures
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise, ID 83702
BARTON L. KLINE (ISB No. 1526) RECE(n p,
DONOVAN E. WALKER (ISB No. 5921)DEC '° Idaho Power Company u P1112-30
P.O. Box 70 IDAho Pu
1221 West Idaho Street UTILITIES
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
bkIine(idahopower.com
dwalker(idahopower.com
Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR AN ) CASE NO. IPC-E-09-34
ACCOUNTING ORDER AUTHORIZING )
THE INCLUSION OF POWER SUPPLY ) APPLICATION
EXPENSES ASSOCIATED WITH THE )
PURCHASE OF CAPACITY AND ENERGY )
FROM USG OREGON LLC IN THE )
COMPANY'S POWER COST )
ADJUSTMENT. )
Idaho Power Company (Idaho Power" or the "Company"), in accordance with
Idaho Code § 61-503 and RP 52, hereby respectfully applies to the Idaho Public Utilities
Commission (IPUC" or the "Commission") for an accounting order authorizing Idaho
Power to include the expenses associated with the purchase of energy from the USG
Oregon LLC, Neal Hot Springs Unit #1 geothermal generation facility ("Project") in the
Company's Power Cost Adjustment. In support of this Application Idaho Power
represents as follows:
APPLICATION -1
I. BACKGROUND
1. Over the past several years, Idaho Power has made a concerted effort to
acquire cost-effective energy from geothermal generating resources for its resource
portfolio. In its 2004 and 2006 Integrated Resource Plans ("lRPs"), the Company
discussed why it is strongly supportive of the acquisition of energy from geothermal
generating resources. First, geothermal generation utilizes a renewable resource,
geothermally heated fluid, which decouples the project's variable operating costs from
the volatility associated with the cost of fossil fuels. Geothermal generation, except for
occasional planned and forced outages, is unique in comparison to other renewable
resources (i.e., wind, solar, run-of-river hydro, etc.), which are more intermittent in their
availability. Geothermal generation is essentially available 24/7 throughout the year and
therefore can be considered to be a baseload resource. Second, numerous studies. and
tests indicate that it is likely that there are significant sources of geothermally heated hot
water underlying Idaho Power's service area. Development of these geothermal
resources will add economic value in local communities in the Company's service
territory and will make efficient use of limited transmission capacity. Third, under
various Renewable Portfolio Standards, geothermal resources qualify for renewable
energy credits that can provide independent financial and environmental benefits to
Idaho Power and its customers. Fourth, the inclusion of geothermal resources in the
Company's resource portfolio provides diversity and reduced exposure to fuel cost
fluctuations. Finally, due principally to very aggressive renewable portfolio standards,
particularly in California, a number of utilities are actively seeking to acquire geothermal
resources throughout the entire western United States. In short, geothermal generation
APPLICATION -2
resources have the potential to provide a desirable, long-term, and economically stable
generating resource for Idaho Power and there is some urgency to move forward to
develop these desirable local resources.
2.Idaho Power disclosed its intention to actively seek to acquire geothermal
generating resources in both its 2004 and 2006 lRPs. In 2006, Idaho Power issued a
Request for Proposals ("RFP") to acquire geothermal resources. The 13 MW Raft River
Geothermal Power Plant Unit #1, developed by a subsidiary of U.S. Geothermal, was
selected as one of the successful proposals. The Raft River #1 plant began delivering
energy to Idaho Power in April 2008 under a power purchase agreement developed as
a result of the 2006 RFP process. U.S. Geothermal included additional geothermal
projects in its successful 2006 bid, including additional generation at Raft River and a
new project at Neal Hot Springs. However after further review of escalating
construction costs, U.S. Geothermal concluded that its fixed-price bid was not viable
and withdrew its offer to sell power from the Neal Hot Springs site as submitted.
3.Consistent with its continuing desire to include geothermal generation in
its resource portfolio, Idaho Power issued a new RFP in 2008 to acquire additional
geothermal resources. This 2008 RFP received three responses, two of which were
shortly withdrawn by the bidders prior to Idaho Power fully evaluating the bids. Idaho
Power concluded that the third bid was too speculative and therefore unacceptable.
4.In reviewing the disappointing results of the 2006 and 2008 geothermal
RFPs both internally and with geothermal industry experts, it has become apparent to
Idaho Power that due to the substantial uncertainties inherent in the exploration and
APPLICATION -3
development processes required for geothermal projects, the competitive RFP process
is not the optimal means to acquire geothermal resources.
5.Based on its belief that a non-RFP driven resource acquisition process for
geothermal resources is more likely to be successful, Idaho Power has actively pursued
development discussions with the developers of approximately five different potential
geothermal sites. These sites had been identified in previous RFPs or brought to the
Company's attention as a result of previous proposals received directly from
developers. The Project identified in this Application became the front-runner in the
non-RFP procurement process for several reasons, including: (1) substantial prior
geotechnical exploration of the potential resource site, (2) its location in Idaho Powers
service area and proximity to Treasure Valley load centers, (3) available transmission
capacity, and (4) favorable energy pricing in comparison to other proposals. Idaho
Power is continuing discussions with the other potential geothermal projects and,
consistent with the action plans in its accepted lRPs, may, in the future, present to the
Commission power purchase agreements for additional geothermal resources Idaho
Power determines to be prudent choices to fulfill Idaho Power identified energy needs.
II. GENERAL DESCRIPTION OF TERMS AND CONDITIONS
IN THE POWER PURCHASE AGREEMENT FOR THE
NEAL HOT SPRINGS UNIT #1 PROJECT
6.On December 11, 2009, Idaho Power and USG Oregon LLC entered into
a Power Purchase Agreement ("Agreement") for the purchase of energy from the Neal
Hot Springs Unit #1 geothermal electrical generation facility. USG Oregon LLC is a
subsidiary of U.S. Geothermal, a Boise-based geothermal developer. The Project will
be located approximately 12 miles WNW of Vale, Oregon, just west of the Bully Creek
APPLICATION -4
Reservoir. The expected MW output from the Project will be approximately 22 MW, with
an estimated on-line date of late 2012 (the Agreement requires an on-line date no later
than 2016) and with an initial term of 25 years with an option for Idaho Power to extend
the term of the Agreement. A copy of the Agreement is enclosed as Attachment No. 1.
7.Under the Agreement, Idaho Power will receive, as a part of the purchase
price, the rights to all Environmental Attributes and Renewable Energy Credits ("RECs")
as currently known and any additional Environmental Attributes and Renewable Energy
Credits created during the term of the Agreement.
8.The Agreement requires the Project to maintain a 90 percent capacity
factor, with applicable annual energy output guarantees. Various development
milestones have been established within the Agreement. Failure to meet these
development milestones or annual output guarantees will result in damages being
calculated and will require the Project to post liquid security. The Project is required to
provide energy delivery forecasting to Idaho Power. The Agreement also allows Idaho
Power to curtail energy deliveries to Idaho Power in an amount up to 1,620 MWh per
contract year at no cost to Idaho Power. This curtailment right will allow the Company
some flexibility, albeit limited, to dispatch the Project to benefit customers.
9.Delay damages and other liquidated damages are applicable based upon
the Projects compliance with various exploration, development, and construction
milestones, as well as its ongoing performance.
10.The Agreement grants Idaho Power the first right-of-offer to participate in
any future U.S. Geothermal resource development at this geothermal site or in close
proximately to the site and in any future ownership restructuring of the planned Project.
APPLICATION -5
I 11. The energy price within the Agreement will be seasonally adjusted
consistent with seasonality factors currently being used in Idaho Powers PURPA
agreements. Using seasonality factors to adjust prices provides for reduced energy
prices in months of historically low market energy values, with increased energy prices
in months when Idaho Power experiences its peak energy needs. Seasonal prices give
the correct price signal by incenting production when the value of the energy to the
Company is the highest. Beginning in 2012, the flat energy price (energy price to which
seasonality is then applied) is $96.00IMWh. An annual price escalation that varies from
6 percent in the initial years to 1.33 percent in the later years of the Agreement was
used to create the fixed monthly price schedule shown in Appendix A of the Agreement.
Applying levelized energy pricing models to this fixed set of prices results in an
approximate 25-year levelized contract price of $117.56.
12. For comparison purposes, PURPA contracts are currently only available
for a 20-year term. The levelized price for a 20-year PURPA contract, with first energy
deliveries in 2012 is $95.56IMWh (IPUC Order No. 30744). The calculated levelized
contract price for energy provided under this Agreement for a 20-year term would be
approximately $11 5.28IMWh. IPUC Order No. 30744 establishes PURPA non-levelized
contract price for energy received in 2012 to be $80.05/MWh, which escalates to
$1 38.93/MWh in calendar year 2034 (2034 is the last year currently priced in IPUC
Order No. 30744). The energy price for 2012 in the Agreement is $96.00/MWh and the
price escalates to $140.82/MWh in 2034. While the price of energy under the
Agreement is higher than energy purchased under PURPA contracts, there are aspects
of the Agreement that bring value to Idaho Powers customers that PURPA contracts do
APPLICATION -6
not. For example, typical PURPA agreements currently do not provide Idaho Power
rights to any of the project's RECs. To obtain the RECs for a PURPA project, Idaho
Power must incur additional costs to purchase those credits from the developer in a
separate transaction. PURPA agreements offer no energy curtailment rights, no
operational financial security requirements, no rights of first offer on ownership or other
site development, no exploration, development or construction milestone requirements
and associated damages, and no rights for extension of the contract term.
13.USG Oregon LLC has submitted a request and completed a Large
Generation Interconnection Agreement for this Project. The Project will pay all
interconnection costs associated with this Project and the schedule for completion of
installation and construction of all required interconnection equipment is consistent with
the Projects expected energy delivery dates. With the addition of one relatively minor
system upgrade, sufficient firm transmission capacity is available for the full output of
the Project to be delivered to Idaho Power's load centers. The Project will advance the
cost of the upgrade and receive credit for its advanced funds based on its capacity and
the OATT rate.
14.Section 1.8, Articles 27 and 28 of the Agreement provides that the
Agreement will not become effective until the Commission has approved all of the
Agreement's terms and conditions and declared that all payments Idaho Power makes
under this Agreement will be allowed as prudently incurred expenses for ratemaking
purposes.
APPLICATION -7
III. ACCOUNTING TREATMENT
15.Idaho Power intends to include the expenses associated with the
purchases from the Project in FERC Account 555. The Agreement is not a PURPA
agreement and therefore the Company proposes that the cost of power purchased
under the Agreement be recovered in the PCA in a manner similar to other non-QF
power purchase expenses, with 95 percent of variations captured through the
Company's PCA mechanism until the next general rate case, at which time the
Company will be allowed to include the costs of the Agreement in base rates.
IV. MODIFIED PROCEDURE
16.Idaho Power believes that a hearing is not necessary to consider the
issues presented herein and respectfully requests that this Application be processed
under Modified Procedure, i.e., by written submissions rather than by hearing. RP 201,
et seq. If, however, the Commission determines that a technical hearing is required, the
Company stands ready to present its testimony and support the Application in such
hearing.
V. COMMUNCIATIONS AND SERVICE OF PLEADINGS
17.Communications and service of pleadings, exhibits, orders, and other
documents relating to this proceeding should be sent to the following:
Barton L. Kline, Lead Counsel
Donovan E. Walker, Senior Counsel
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
bkline(ãidahopower.com
dwaIker(idahoDower.com
Randy C. Allphin
Contract Administrator
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
ralIphin(didahoOower.COm
APPLICATION -8
VI. REQUEST FOR REUEF
18. Idaho Power Company respectfully requests that the Commission issue
an Order (1) Authorizing that this matter be processed by Modified Procedure; and (2)
finding that the Agreement is prudent for ratemaking purposes; and (3) approving Idaho
Power's requested accounting treatment for inclusion of the power purchase expense
associated with the Agreement in the Company's Power Cost Adjustment rate.
Respectfully submitted this 28th day of December 2009.
BARTONL. KLINE
Attorney for Idaho Power Company
APPLICATION -9
CERTIFICATE OF MAILING
I HEREBY CERTIFY that on the 28 1h day of December 2009 I served a true and
correct copy of the within and foregoing APPLICATION upon the following named
parties by the method indicated below, and addressed to the following:
USG Oregon LLC Hand Delivered
Dan Kunz _X. U.S. Mail
USG Oregon LLC Overnight Mail
1505 TyrelI Lane FAX
Boise, Idaho 83706 Email
(2Q
Barton L. Kline
APPLICATION -10
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-09-34
IDAHO POWER COMPANY
ATTACHMENT NO. 1
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
TABLE OF CONTENTS
ARTICLE 1 DEFiNiTIONS............................................................................................
ARTICLE 2 RULES OF CONSTRUCTION ................................................................
ARTICLE 3 RESOURCE EXPLORATION ..................................................................
ARTICLE 4 CONDITIONS TO ACCEPTANCE OF ENERGY FIRST
ENERGYDATE.........................................................................................
ARTICLE 5 TERM AND OPERATION DATE ............................................................
ARTICLE6 PRICE.........................................................................................................
ARTICLE 7 ENVIRONMENTAL ATTRIBUTES .........................................................
ARTICLE 8 DELIVERY AND SHORTFALL OBLIGATIONS...................................
ARTICLE 9 METERING AND TELEMETRY.............................................................
ARTICLE 10 SYSTEM PROTECTION...........................................................................
ARTICLE 11 FACILITY AND INTERCONNECTION..................................................
ARTICLE 12 GENERAL OPERATIONS........................................................................
ARTICLE 13 BILLING, RECORDS, AUDITS ...............................................................
ARTICLE 14 INDEMNIFICATION AND iNSURANCE...............................................
ARTICLE 15 CREDIT AND COLLATERAL REQUIREMENTS.................................
ARTICLE 16 FORCE MAJEURE.....................................................................................
ARTICLE 17 FORCED OUTAGE...................................................................................
ARTICLE 18 BUYER'S ACCESS RIGHTS....................................................................
ARTICLE 19 NO THIRD PARTY LIABILITY, NO DEDICATION OF FACILITY
ORSYSTEM...............................................................................................
ARTICLE 20 SEVERAL OBLIGATIONS .......................................................................
ARTICLE 21 . WAIVER .....................................................................................................
ARTICLE 22 CHOICE OF LAW .....................................................................................
ARTICLE 23 LIMITATIONS...........................................................................................
ARTICLE 24 DISPUTES..................................................................................................
ARTICLE 25 EVENTS OF DEFAULT, DELAY DAMAGES AND
MATERIALBREACHES..........................................................................
ARTICLE 26 TERMINATION.........................................................................................
ARTICLE 27 GOVERNMENTAL AUTHORIZATION.................................................
ARTICLE 28 REGULATORY APPROVAL...................................................................
ARTICLE 29 SUCCESSORS AND ASSIGNS................................................................
ARTICLE 30 MODIFICATION.......................................................................................
ARTICLE31 TAXES........................................................................................................
ARTICLE 32 NOTICES....................................................................................................
ARTICLE 33 ADDITIONAL TERMS AND CONDITIONS..........................................
ARTICLE34 SEVERABILITY........................................................................................
ARTICLE 35 CONFIDENTIAL BUSINESS INFORMATION......................................
ARTICLE 36 REPRESENTATIONS AND WARRANTIES ............................................
ARTICLE 37 ENTIRE AGREEMENT.............................................................................
ARTICLE 38 COUNTERPARTS.....................................................................................
ARTICLE 39 CAPTIONS.................................................................................................
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
This Power Purchase Agreement ("Agreement") is entered into this 1/ day
of c e J,pv , 2009, by and between USG OREGON LLC, a Delaware limited
liability company with a principal place of business at 1505 Tyrell Lane, Boise, ID 83706
("Seller"), and IDAHO POWER COMPANY, an Idaho corporation with a principal
place of business at 1221 W. Idaho Street, Boise, ID 83702 ("Buyer"). Seller and Buyer
may be referred to individually as "Party," or jointly as "Parties."
Recitals
A.Seller desires to develop, construct, own and operate a geothermal electric
generating facility known as the Neal Hot Springs Unit #1 with an estimated average
annual net output of no less than 14,000 kW and no greater than 25,000 kW. At the time
of signing this Agreement the expected estimated average annual net output is 22,000
kW. This estimated average annual net output will be precisely established as specified
in Article 3.
B.Seller desires to deliver, and sell the full electrical energy output from this
facility to the Buyer along with all environmental benefits associated with the electrical
energy output for all calendar months of each year for the full term of this Agreement.
C.Seller and Buyer wish to enter into this Agreement in order to set forth the
terms and conditions under which Seller will sell and Buyer will purchase energy from
the Seller's Facility.
NOW, THEREFORE, in consideration of the mutual covenants contained in this
Agreement, the sufficiency and adequacy of which are hereby acknowledged by each
Party, the Parties agree to the following:
PAGE 1
ARTICLE 1
DEFINITIONS
1.1 "Affiliate" means any other person or entity that controls, is under the
control of, or is under common control with, the named person or entity. For purposes of
this definition, the term "control" (including the terms "controls," "under the control of,"
and "under common control with") means the possession, directly or indirectly, of the
power to direct or cause the direction of the management or the policies of a person or
entity, whether through ownership interest, by contract or otherwise.
1.2 "Annual Allowed Energy Reduction" means 1,620 MWh for each
Contract Year.
1.3 "Annual Capacity Factor" means 90%.
1.4 "Annual Guaranteed Output" means the Annual Output Forecast as
defined in Section 8.5 multiplied by the Annual Capacity Factor.
1.5 "Bankrupt" means with respect to any entity, such entity (1) files a
petition or otherwise commences, authorizes or acquiesces in the commencement of a
proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar
law, or has any such petition filed or commenced against it, (2) makes an assignment or
any general arrangement for the benefit of creditors, (3) otherwise becomes bankrupt or
insolvent (however evidenced), (4) has a liquidator, administrator, receiver, trustee,
conservator or similar official appointed with respect to it or any substantial portion of its
property or assets, or (5) is generally unable to pay its debts as they fall due. The term
"Bankruptcy" shall have a corollary meaning when used herein.
1.6 "Business Day" means any calendar day that is not a Saturday, a Sunday,
or a NERC-recognized holiday.
1.7 "Commission" means the Idaho Public Utilities Commission or its
successor.
1.8 "Commission Approval" means an order issued by the Commission
approving this Agreement and finding the Contract Price to be reasonable and that all
payments to be made to Seller under this Agreement shall be allowed as prudently incurred
expenses of Buyer for ratemaking purposes, without condition(s) or modification(s) other
than condition(s) or modification(s) accepted in writing by the Party or Parties adversely
affected by such condition(s) or modification(s).
1.9 "Contract Price" means the price for all Net Energy that has been agreed
to by the Parties in this Agreement and referenced in Appendix A.
1.10 "Contract Year" means the period commencing March 1st of the first
calendar year after the establishment of the Operation Date ending one (1) year later, and
each one year period thereafter beginning on March 1.
PAGE 2

1.11 "Credit Rating" means (1) with respect to any entity other than a financial
institution, the (a) current ratings issued or maintained by S&P's or Moody's with respect
to such entity's long-term senior, unsecured, unsubordinated debt obligations (not
supported by third-party credit enhancements) or (b) corporate credit rating or long-term
issuer rating issued or maintained with respect to such entity by S&P's or Moody's, or
(2) if such entity is a financial institution, the ratings issued or maintained by S&P's or
Moody's with respect to such entity's long-term, unsecured, unsubordinated deposits.

1.12 "Delay Energy Quantity" means 3,000 kW less any portion of the capacity
rating (kW) of the Facility that has met the Operation Date requirements specified in
Section 5.4 multiplied by the hours beginning with the 744th hour past midnight of the
Scheduled Operation Date to midnight of the day preceding the Operation Date, not to
exceed, 2,160 total hours.

1.13 "Delay Liquidated Damages" means the Delay Energy Quantity multiplied
by the Delay Price.

1.14 "Delay Price" means 85% of the applicable month's Market Energy Cost
less the applicable month's Contract Price as specified in Appendix A. If this calculation
results in a value less than zero (0) then the result will be zero (0).

1.15 "Designated Dispatch Facility" means Buyer's generation dispatch group
or any subsequent group designated by Buyer.

1.16 "Effective Date" means the date first written above.

1.17 "Emergency" means an emergency condition as defined under the
Interconnection Agreement or the applicable OATT.

1.18 "Environmental Attributes" means the aggregate amount of environmental
air quality credits, off-sets, or other benefits related to the Net Energy and Test Energy
produced by the Facility that reduces, displaces or off-sets emissions resulting from fuel
combustion at another location pursuant to any federal, state or local legislation or
regulation, and the aggregate amount of credits, offsets or other benefits related to Buyer's
current marketing program, any successor green pricing program, or other environmental or
renewable energy credit trading program derived from the use, purchase or distribution of
Net Energy from the Facility or any similar program pursuant to any federal, state or local
legislation or regulation. The Environmental Attributes include, but are not limited to,
green tags, green certificates, renewable energy credits (REC's) and tradable renewable
certificates directly associated with the Net Energy produced at this Facility. One REC is
associated with the generation and delivery of one thousand (1,000) kWh of Net Energy.
Notwithstanding any other provision of this Agreement, Environmental Attributes do not
include: (1) the PTC's, (2) any investment tax credits, and any other tax credits,
deductions, exemptions, or other tax benefits associated with the Facility, and (3) any state,
federal, local or private cash payments, exemptions, refunds or grants relating in any way
to the Facility, construction of the Facility or output of the Facility, including the
production of Test Energy, Station Use, or Net Energy.
PAGE 3

1.19 "Facility" means the electric generation facility commonly known as
Seller's Neal Hot Springs Unit #1 geothermal power plant, as described in more detail in
Appendix B, which includes all of the equipment required to enable this power plant to
produce and deliver the electric energy as specified within this Agreement to the Buyer.
This equipment shall include, but not be limited to, the electrical interconnection
equipment, generator, turbine, heat exchanger, and cooling tower(s). The geothermal fluid
extraction wells, geothermal fluid injection wells, geothermal fluid transportation systems
from the various wells to the generation unit are included in the Facility to the extent that
they are used in the production of energy from the Facility.

1.20 "Facility Assets" shall have the meaning given to that term in Section
29.7.1.

1.21 "Facility Lender" means, collectively, any lender(s) providing any Project
Financing and any guarantors of such lenders and successor(s) or assigns thereto that Seller
identifies in Article 32.

1.22 "Financing Documents" means the loan and credit agreements, notes,
bonds, indentures, security agreements, lease financing agreements, mortgages, deeds of
trust, and other documents relating to any Project Financing for the Facility, and any and
all amendments, modifications, or supplements to the foregoing that may be entered into
from time to time at the discretion of Seller in connection with any Project Financing of the
Facility, or of the Facility in combination with other assets of the Seller.

1.23 "First Energy Date" means the day commencing at 00:01 hours, Mountain
Time, following the day that the conditions in Section 4.1 have been satisfied.

1.24 "Forced Outage" means a Facility condition that requires a sudden or
mandatory unplanned curtailment of the Net Energy deliveries from the Facility that (1) is
due to equipment failure or unplanned shutdown which was not caused by an event offorce
majeure or by neglect, disrepair or lack of adequate preventative maintenance of the
Seller's Facility or (2) is required to allow unplanned repair or maintenance to prevent
equipment failure.

1.25 "Good Utility Practice(s)" means any of the practices, methods and acts
engaged in or approved by a significant portion of the electric utility industry during the
relevant time period, or any of the practices, methods and acts which, in the exercise of
reasonable judgment in light of the facts known at the time the decision was made, could
have been expected to accomplish the desired result of the lowest reasonable cost
consistent with good business practices, reliability, safety and expedition. Good Utility
Practice(s) is not intended to be limited to the optimum practice, method or act to the
exclusion of all others, but rather to be acceptable practices, methods, or acts generally
accepted in the region and consistently adhered to.

1.26 "Guaranty" means an instrument or agreement pursuant to which a
guarantor guarantees the performance of the obligations of an obligor, which instrument or
agreement is substantially in the form set forth as Appendix C.
PAGE 4

1.27 "Guaranty Default" means with respect to a Guaranty or the guarantor
thereunder, the occurrence of any of the following events: (1) any representation or
warranty made or deemed to be made or repeated by such guarantor in connection with
such Guaranty shall be false or misleading in any material respect when made or when
deemed made or repeated; (2) such guarantor fails to pay, when due, any amount required
pursuant to such Guaranty; (3) the failure of such guarantor to comply with or timely
perform any other material covenant or obligation set forth in such Guaranty if such failure
is not capable of remedy or shall not be remedied in accordance with the terms and
conditions of such Guaranty; (4) such Guaranty shall expire or terminate, or shall fail or
cease to be in full force and effect and enforceable in accordance with its terms against
such guarantor, prior to the satisfaction of all obligations of the obligor under this
Agreement, in any such case without replacement; (5) such guarantor shall repudiate,
disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of, its Guaranty,
or (6) such guarantor becomes Bankrupt; provided, however, that no Guaranty Default
shall occur or be continuing in any event with respect to a Guaranty after the time such
Guaranty is required to be canceled or returned to a Party in accordance with the terms of
this Agreement.

1.28 "Initial Term" has the meaning given to that term in Section 5.1.1.

1.29 "Interconnection Agreement" means the agreement between the
Interconnection Provider and the Seller that enables the Seller's energy to be delivered and
integrated into the Interconnection Provider's electrical system.

1.30 "Interconnection Facilities" means all equipment required to be installed
to interconnect and deliver energy from the Facility to the Interconnection Provider's
system including, but not limited to, connection, switching, metering, relaying,
communications and safety equipment.

1.31 "Interconnection Provide?' means that portion of Idaho Power Company,
or its successor, that is responsible for the interconnections and operations of the Idaho
Power Company distribution and transmission system as specified in the Idaho Power
Company OATT.

1.32 "Interest Rate" means (I) for purposes of identifying the Interest Rate to
be paid on cash collateral, an annual interest rate equal to the overnight federal funds rates,
or (2) for purposes of identifying the Interest Rate to be paid in an event of default, an
annual interest rate equal to one hundred percent (100%) of the LIBOR three (3) month rate
plus two hundred (200) basis points. The designated Interest Rate shall be the rate
published on the date of the invoice, or other notice, in The Wall Street Journal (or, if
The Wall Street Journal is not published on that day, the next succeeding date of
publication); provided, however, that the annual interest rate used as the Interest Rate shall
not exceed the maximum rate permitted by law.

1.33 "Investor" means any investor(s) (including any transferees of such
investors) that acquire a direct or indirect interest in Seller that Seller identifies in Article
32.
PAGE 5

1.34 "Market Energy Cost" means 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. If the Dow Jones Mid-C Index price is discontinued by the reporting
agency, both Parties will mutually agree upon a replacement index similar to the Dow
Jones Mid-C Index. The selected replacement index will be consistent with other similar
agreements and a commonly used index by the electrical industry.

1.35 "Market Energy Price" means ninety percent (90%) of the Market Energy
Cost.

1.36 "Material Adverse Change" means, with respect to Seller's Guarantor, the
Guarantor's non-credit enhanced unsecured debt has (a) a Credit Rating below BBB- by
S&P or below Baa3 by Moody's, or (b) a Credit Rating of BBB— by S&P accompanied by a
negative watch or Baa3 by Moody's accompanied by a negative watch, or (c) both ratings
are withdrawn or terminated on a voluntary basis by the rating agencies. If S&P changes
its rating system during the Term, "BBB—" shall be replaced by S&P's lowest investment
grade rating under the new rating system; likewise, if Moody's changes its rating system
during the Term, "Baa3" shall be replaced by Moody's lowest investment grade rating
under the new rating system.

1.37 "Material Breach" means a default or Event of Default (Article 25) subject
to Section 25.3.

1.38 "Maximum Capacity" shall not exceed 30,000 kW without prior mutual
consent by both Parties and will be precisely established as specified in Section 3.2.2.

1.39 "Metering and Telemetry Equipment" means all equipment specified in
the Interconnection Agreement, this Agreement, and any additional equipment specified in
Appendix B required to measure, record and telemeter power flows between the Facility
and the Interconnection Provider's electrical system.

1.40 "Metering Point" means the point where the Seller's energy is measured
by the Interconnection Provider's Metering Equipment.

1.41 "Moody's" means Moody's Investor Services, Inc. or its successor.

1.42 "NERC" means the North American Electric Reliability Council or its
successor.

1.43 "Net Energy", expressed in (kWh), means all of the electric energy
produced by the Facility, less Station Use, and delivered to and measured at the Metering
Point that is (1) after an Operation Date has been established (2) is delivered by the Seller
to the Metering Point and accepted by the Buyer at the Metering Point and (3) not
exceeding the Maximum Capacity. Net Energy does not include Test Energy.

1.44 "Net Energy Shortfall" means as calculated in Section 8.5.5 and subject to
Net Energy Shortfall Damages.
PAGE 6

1.45 "Net Energy Shortfall Price" means the price used to calculate the Net
Energy Shortfall Damages as specified in Appendix D.

1.46 "Net Energy Shortfall Damages" means any remaining Net Energy
Shortfall after the provisions of Section 8.5.5.2 have been applied, multiplied by the Net
Energy Shortfall Price applicable to the actual period when the Net Energy Shortfall
occurred.

1.47 "OA1T' means the Open Access Transmission Tariff applicable to the
Interconnection Provider's system or the Buyer's transmission system.

1.48 "Operation Date" means the day commencing at 00:01 hours, Mountain
Time, following the day that all conditions of Section 5.4 have been satisfied.

1.49 "Performance Assurance" means collateral in the form of either a
Guaranty, cash, letter(s) of credit, or other security acceptable to Buyer, as described in
Article 15.

1.50 "Point of Delivery" means the point where the Transmission Tap
intersects the Interconnection Provider's Vale-Unity transmission line.

1.51 "Project Financing" means debt with respect to which the Facility
Lender(s) are granted security interests in the Facility, as well in such other of Seller's
assets, and in such revenues generated therefrom, as are specified in the Financing
Documents.

1.52 "Project Milestone" means a defined date by which time the Seller shall
have accomplished a particular activity, as defined in Appendix H.

1.53 "PTC's" means Production Tax Credits applicable to electricity produced
from certain renewable resources pursuant to 26 U.S.C. § 45, or replacement or substitute
tax benefits based on energy production from the Facility.

1.54 "PTC Value" means if the Seller elects to receive PTCs for this Facility,
an amount equal to: (a) the PTC's to which Seller would have been entitled with respect to
renewable energy it is unable to deliver because of a Buyer Event of Default; plus (b) a
"gross up" amount to take into account the federal, state and local income tax to Seller on
such payments in lieu of PTC's, so that the net amount retained by Seller, after payment of
federal, state and local income taxes, is equal to the amount set forth in clause (a) of this
definition. For purposes of determining the foregoing, Seller shall deliver a certificate from
an officer of Seller stating the corporate income tax rates (federal, state or local, as
applicable) that are in effect for the Seller during the tax year in which the receipt of such
PTC Value is taxed, and such income tax rates shall be used in the calculation of the PTC
Value. If the Seller does not elect to receive PTC's for this Facility, the PTC Value shall
be zero (0).
PAGE 7

1.55 "Scheduled First Energy Date" means the date that is thirty (30) months
from the date on which the Seller issues the notice to proceed for the power plant
construction as described in the fourth Project Milestone of Appendix H.

1.56 "Scheduled Maintenance" means as defined in Section 12.2.

1.57 "Scheduled Operation Date" means six (6) months after the Scheduled
First Energy Date.

1.58 "Scheduled Outage" means the pre-scheduled kWh curtailment associated
with the Scheduled Maintenance.

1.59 "Seller's Guarantor" means the entity providing the Guaranty or a
successor or assignee thereof that is not experiencing a Material Adverse Change.

1.60 "Site" means the parcel of real property on which the Facility will be
constructed and located, including any easements, right-of-ways, surface use agreements,
and other interests or rights in real estate reasonably necessary for the construction,
operation and maintenance of the Facility.

1.61 "Station Use" means electric energy produced by the Facility that is used
to operate equipment that is auxiliary or otherwise related to the production of electricity
by the Facility, including geothermal fluid pumps.

1.62 "S&P" means Standard & Poor's, a division of McGraw-Hill Companies
Inc. or its successor.

1.63 "Term" means the period of time during which this Agreement shall
remain in full force and effect, including the Initial Term and any extension of the Term as
provided in Article 5.

1.64 "Test Energy" (expressed in kWh), means all of the electric energy
produced by the Facility, less Station Use, and delivered to and measured at the Metering
Point, that is (1) pfior to an Operation Date being established and (2) delivered by the
Seller to the Metering Point and accepted by the Buyer at the Metering Point and (3) not
exceeding the Maximum Capacity.

1.65 "Total Annual Facility Net Energy" means the sum of twelve (12) months
of actual Net Energy beginning with March l of each calendar year.

1.66 "Transmission Tap" means the approximate eleven (11) mile transmission
line connecting the Facility to the Point of Delivery.

1.67 "WECC" means the Western Electricity Coordinating Council or its
successor.
PAGE 8
1.68 "WREGIS" means the Western Renewable Electricity Generation
Information System which is an independent, renewable energy tracking system for the
region covered by the Western Electricity Coordinating Council (WECC).
ARTICLE 2
RULES OF CONSTRUCTION

2.1 General. The defined terms listed in Article I (as indicated by initial
capitalization) shall have the meanings set forth in Article 1 whenever the terms appear in
this Agreement and attached Appendices, whether in the singular or the plural or in the
present or past tense. Other terms used in this Agreement but not listed in Article 1 shall
have meanings as otherwise defined within this Agreement or as commonly used in the
English language and, where applicable, in Good Utility Practice(s). Words not
otherwise defined in this Agreement that have well-known and generally accepted
technical or trade meanings are used in accordance with such recognized meanings. In
addition, the following rules of interpretation shall apply:
2. 1.1 The masculine shall include the feminine and neuter.
2.1 .2 References to "Articles," "Sections," or "Appendices" shall be to
articles, sections or appendices of this Agreement.
2.1.3 The Appendices attached to this Agreement are incorporated in
and are intended to be a part of this Agreement.
2.1.4 This Agreement was negotiated and prepared by both Parties with
the advice and participation of counsel. The Parties have agreed to the wording of this
Agreement, and none of the provisions of this Agreement shall be construed against one
Party on the grounds that such Party is the author of this Agreement or any part of this
Agreement.
2.1.5 The Parties shall act reasonably and in accordance with the
principles of good faith and fair dealing in the performance of this Agreement. Unless
expressly provided otherwise in this Agreement, (i) where the Agreement requires
consent, approval, or a similar action by a Party, such consent, approval or other action
shall not be unreasonably withheld, conditioned or delayed, and (ii) where the Agreement
gives a Party a right to determine, require, specify or take similar action with respect to a
matter, such determination, requirement, specification or similar action shall be
reasonable.

2.2 Interoretation of Interconnection Agreement and Interconnection Provider
documentation. The Parties recognize that the Seller has entered into a separate
Interconnection Agreement enabling the delivery of the Facility's electrical energy to the
Buyer. This agreement shall include but not be limited to an Interconnection Agreement
with the Interconnection Provider and documentation from the Interconnection Provider
approving the delivery of the Facility's energy to the Point of Delivery.
PAGE 9
2.2.1 The Parties acknowledge and agree that the Interconnection
Agreement(s) and the Interconnection Provider documentation shall be separate and
free-standing documents and agreements and that the terms of this Agreement are not
binding upon the Interconnection Provider.
2.2.2 Notwithstanding any other provision in this Agreement, nothing in
the Interconnection Agreement(s) or the Interconnection Provider documentation shall
alter or modify the Buyer's or Seller's rights, duties and obligations under this
Agreement. This Agreement shall not be construed to create any rights between the
Seller and the Interconnection Provider.
ARTICLE 3
PROJECT MILESTONES
3.1 The Seller shall meet all requirements of the first three (3) Project
Milestones specified in Exhibit H (exploration schedule, exploration drilling, and
resource report).
3. 1.1 Within sixty (60) days of the date the resource report required
under the third Project Milestone is provided to the Buyer, the Parties shall review the
provided report and establish the estimated average annual net output (kW rating) of the
Facility. Based upon this agreed upon kW rating, the Facility shall be developed as
follows:
a.)If the report indicates that the geothermal resource is able
to accommodate a Facility kW rating from 14,000 kW to
25,000 kW the Seller shall proceed with completion of the
Facility as specified within this Agreement.
b.)If the report indicates that the geothermal resource is able
to accommodate a Facility kW rating of less than 14,000
kW, the Seller within sixty (60) days of the date of the
issuance of the resource report shall notify the Buyer of the
Seller's 1) intent to proceed with development and
construction of the Facility as specified within this
Agreement, or 2) propose to the Buyer modifications of the
existing Agreement, or 3) provide notification of
termination of this Agreement. If the Seller provides no
notification within the sixty (60) day period, the Seller shall
be obligated to proceed with development and construction
of this Facility as specified within this Agreement. If the
report indicates the kW rating of the Facility shall be less
than 10,000 kW, the Buyer reserves the right to terminate
this Agreement within this sixty (60) day period. If after
commercially reasonable efforts the Parties are unable to
agree upon modifications proposed as specified in item 2)
PAGE 10
above, either Party may terminate this Agreement with 30
days notification. Upon mutual consent, the Parties may
agree to extend this sixty (60) day period prior to the end of
the initial sixty (60) day period. Termination of this
Agreement as allowed with this section 3.1.1 b) shall result
in no damages be assessed against either the Buyer or the
Seller.
c.) If the report indicates that the geothermal resource is able
to accommodate a Facility kW rating greater than 25,000
kW the Seller shall proceed with development of up to a
25,000 kW rated Facility. The Parties may mutually agree
to Net Energy deliveries to the Buyer exceeding 25,000
kWh per hour as an amendment to this Agreement or in a
separate agreement.

3.2 The Seller shall meet all requirements of the fourth Project Milestone
(issuance of notice to proceed with power plant construction) specified in Exhibit H.
3.2.1 Within sixty (60) days of meeting the fourth Project Milestone,
Seller may revise, if necessary, item B-i of Appendix B. Any such revision shall provide
sufficient detail to accurately describe the entire geothermal facility that will be included
in this Agreement. This description must include, but not be limited to, generation
equipment, cooling towers, control equipment, turbine, heat exchanger, geothermal fluid
production and injection wells, geothermal fluid transportation system, etc.
3.2.2 Within sixty (60) days of meeting the fourth Project Milestone,
Seller shall submit a revised Maximum Capacity value not to exceed the Maximum
Capacity established in Section 1.38.
ARTICLE 4
CONDITIONS TO ACCEPTANCE OF ENERGY
FIRST ENERGY DATE

4.1 Conditions. As a condition of the Buyer's acceptance of deliveries of
energy from the Seller, the following conditions shall be satisfied.
4. 1.1 The Commission shall have approved this Agreement as
contemplated in Articles 27 and 28, or Buyer shall have waived such approval.
4.1.2 Seller shall include updated information as to the Facility's
expected First Energy Date in the Progress Reports and Seller shall have notified Buyer
of the expected First Energy Date no later than five (5) Business Days before the
expected First Energy Date.
PAGE 11
4.1.3 Seller shall have delivered to the Buyer a certificate signed by an
officer of Seller (1) certifying that to the best of the officer's knowledge all licenses,
permits or approvals necessary for Seller's commencement of deliveries have been
obtained from applicable federal, state or local authorities, and (2) listing all such
licenses, permits and approvals.
4.1.3.1 Seller shall certify that either (a) the Seller's market-
based tariff applicable for sale of the Test Energy and Net Energy has attained FERC
Market-Rate authority or (b) the Facility is exempt from FERC Market-Rate authority
and such application or acceptance is not required for Seller to commence Test Energy
and Net Energy deliveries under this Agreement.
4.1.4 Opinion of Counsel. Seller shall have submitted to the Buyer an
opinion letter signed by a law firm that includes attorneys admitted to practice and in
good standing in the states of Idaho or Oregon providing an opinion that Seller's licenses,
permits and approvals as set forth in Section 4.1.3 above are legally and validly issued,
are held in the name of the Seller and, based on a reasonable review (which may include
reliance on certificates provided by officers or other responsible personnel of Seller), the
firm is of the opinion that Seller is in substantial compliance with said permits as of the
date of the opinion letter. The opinion letter will be in a form acceptable to Buyer and
will acknowledge that the firm rendering the opinion understands that Buyer is relying on
said opinion in connection with and for the purposes of this transaction. Buyer's
acceptance of the form will not be unreasonably withheld, conditioned or delayed. The
opinion letter will be governed by and shall be interpreted in accordance with the legal
opinion accord of the American Bar Association Section of Business Law (1991). If
Buyer does not object in writing to the proposed form of opinion letter within ten (10)
Business Days after receiving in it, it shall be deemed accepted.
4.1.5 Seller shall have delivered to Buyer certification that the Facility is
substantially complete, tested and capable of beginning energy deliveries to the Buyer in
a safe manner.
4.1.6 Engineer's Certifications. Submit an executed Engineer's
Certification of Design & Construction Adequacy and an Engineer's Certification of
Operations and Maintenance (O&M) Policy. These certificates will be in the form
specified in Appendix E but may be modified to the extent necessary to recognize the
different engineering disciplines providing the certificates.
4.1.7 Insurance. Submit written proof to the Buyer of all insurance
required in Article 14.
4.1.8 Interconnection Provider Approval. Provide the Buyer with proof
that the Interconnection Agreement is complete and all Interconnection Provider
approvals, including approval for Seller to deliver Test Energy and Net Energy to the
Metering Point of no less than the Maximum Capacity are complete.
PAGE 12
4.1.9 Written Acceraance. Seller shall request and obtain written
confirmation from the Buyer that all conditions to acceptance of Test Energy have been
fulfilled. Such written confirmation shall be provided within a commercially reasonable
time following the Seller's request and will not be unreasonably withheld by the Buyer.
The conditions set forth in this Section 4.1 are to be used solely for purposes of
determining when the Facility has achieved its First Energy Date. They are not intended
to affect in any way when the Facility is deemed to have been "placed in service" for tax
treatment purposes.
4.2 Buyer's APDToVa1 of First Energy Date Disagreements. Seller's
designation of the First Energy Date shall be subject to Buyer's approval, which Buyer
shall not unreasonably withhold, condition or delay. No later than five (5) Business Days
after Seller's notification to the Buyer of the Seller's proposed First Energy Date, as
specified in Section 4.1.9, Buyer shall send Seller a written notice, either (A) approving
the First Energy Date specified in the notice, or (B) setting forth in reasonable detail
Buyer's reasons for concluding that the First Energy Date has not been achieved or will
be achieved on a date other than the date designated in Seller's notice. If Buyer does not
respond on or before the fifth (5th) Business Day after Seller's notice, the First Energy
Date shall be deemed to have occurred on the date designated in Seller's notice. If Buyer
reasonably disagrees that the First Energy Date has been achieved, the Parties shall
cooperate promptly and in good faith to address Buyer's concerns and agree upon the
First Energy Date. If the Parties are unable to agree to a First Energy Date within
ten (10) Business Days of Buyer's notice of disagreement, either Party may pursue
dispute resolution under Article 24 to determine the First Energy Date.
ARTICLE 5
TERM AND OPERATION DATE
5.1 Term.
5.1.1 Initial Term. This Agreement shall become effective as of the
Effective Date and shall remain in full force and effect through the last day of the last
month of the twenty-fifth (25th) Contract Year, subject to any termination provisions set
forth in this Agreement (the "Initial Term").
5.1.2 Buyer's Option to Extend Term. Buyer shall have the option to
extend the Term. Buyer may exercise this option by giving irrevocable notice of exercise
to Seller on or before the end of the twenty-third (23'') Contract Year. If Buyer does not
timely exercise this option, the option shall automatically expire. The option set forth in
this Section shall automatically terminate upon any termination of this Agreement. If
Buyer timely exercises this option, the Parties will negotiate, in good faith, the terms and
conditions under which the Term of this Agreement would be extended; provided,
however, the option set forth in this Section shall terminate without liability to either
Party if the Parties fail to enter into a definitive written agreement concerning the
extension to the Term within six (6) months following the date of Buyer's notice. The
PAGE 13
terms and conditions of any such extension shall be subject to the Parties' respective
management, Board of Directors, and any required Commission approval.
5.2 Progress Reports. On the first Business Day of each calendar quarter
following the first Project Milestone (exploration report) until the Seller has achieved the
fourth Project Milestone (power plant notice to proceed) and on the first Business Day of
each calendar month thereafter until the Operation Date is achieved, Seller shall submit to
the Buyer progress reports on the development and construction of the planned Facility in
a form reasonably satisfactory to the Buyer. These Progress Reports shall include, but
not be limited to, a project development schedule including all significant activities and
milestones and the status of these items, notation and explanation of any significant
delays and the Seller's planned action, and other information pertinent to Seller's
progress on development and construction of the Facility.
5.3 Monitoring of Facility. Buyer shall have the right at its sole risk and
expense to monitor the construction, start-up and testing of the Facility and the Seller
shall comply with all reasonable requests of the Buyer with respect to these monitoring
events. Seller shall cooperate in such physical inspections of the Facility as may be
reasonably requested by the Buyer during and after completion of construction. All
persons visiting the Facility on behalf of the Buyer shall comply with all of the Seller's
applicable safety and health rules and requirements. Buyer's technical review and
inspection of the Facility shall not be construed as endorsing the design of the Facility
nor as any warranty of the safety, durability, or reliability of the Facility.
5.4 Operation Date. Seller will in good faith seek to achieve the Operation
Date by the Scheduled Operation Date. The Operation Date shall occur after all of the
following conditions have been satisfied.
5.4.1 Seller shall notify the Buyer of the Seller's proposed Operation
Date, in written form no later than five (5) Business Days prior to the proposed Operation
Date.
5.4.2 Seller shall have completed and shall have maintained all
conditions to acceptance of energy as specified in Article 4.
5.4.3 The generator, turbines, extraction wells, injection wells and other
associated equipment enabling the Facility to deliver at least 3,000 kW of Net Energy in a
stable, reliable, consistent and safe manner have been installed, tested and determined to
be functioning properly.
5.4.4 All Facility systems necessary for the stable, safe, reliable and
consistent operation of the installed Facility are substantially complete, any testing of the
installed Facility required pursuant to the Interconnection Agreement(s) and
Interconnection Provider documents and equipment supplier requirements have been
successfully completed, and the Facility is available for operation in all material respects
in accordance with applicable laws.
PAGE 14
5.4.5 Seller shall have delivered to Buyer a "Certificate of Facility
Completion" signed by an officer of Seller certifying that the requirements of
Sections 5.4.3 and 5.4.4 have been satisfied with respect to the Facility.
5.4.6 Seller shall have requested and obtained written confirmation from
the Buyer that all conditions to receiving an Operation Date have been fulfilled. Such
written confirmation shall be provided within a commercially reasonable time following
the Seller's request and will not be unreasonably withheld by the Buyer.
These Operation Date requirements are to be used solely for purposes of determining
when the Facility has achieved its Operation Date. They are not intended to affect in any
way when the Facility is deemed to have been "placed in service" for purposes of FTC
eligibility.
5.5 Buyer's Approval of Operation Date: Disagreements. Seller's designation
of the Operation Date shall be subject to Buyer's approval, which Buyer shall not
unreasonably withhold, condition or delay. No later than five (5) Business Days after
Seller's notification to the Buyer of the Seller's proposed Operation Date, as specified in
Section 5.4.6, Buyer shall send Seller a written notice, either (A) approving the Operation
Date specified in the notice, or (B) setting forth in reasonable detail Buyer's reasons for
concluding that the Operation Date has not been achieved or will be achieved on a date
other than the date designated in Seller's notice. If Buyer does not respond on or before
the fifth (5th) Business Day after Seller's notice, the Operation Date shall be deemed to
have occurred on the date designated in Seller's notice. If Buyer reasonably disagrees
that the Operation Date has been achieved, the Parties shall cooperate promptly and in
good faith to address Buyer's concerns and agree upon the Operation Date. If the Parties
are unable to agree to an Operation Date within ten (10) Business Days of Buyer's notice
of disagreement, either Party may pursue dispute resolution under Article 24 to determine
the Operation Date. Upon completion of the dispute resolution process establishing an
Operation Date and/or upon mutual agreement between the Parties of an Operation Date,
the Buyer shall revise any previous Net Energy payments to reflect the applicable Net
Energy Price from the date of the agreed upon Operation Date.
5.6 Continuing Obligations. Seller shall provide Buyer with the following
during the Term of this Agreement:
5.6.1 At Buyer's request, Seller shall provide evidence that it is in
compliance with the insurance requirements set forth in Section 14.2.
5.6.2 Seller shall maintain compliance and remain in good standing in all
requirements of Articles 4 and 5 of this Agreement.
PAGE 15
ARTICLE 6
PRICE
6.1 Test Energy Price. Notwithstanding any other energy pricing provisions
in the Agreement, Buyer shall pay the Seller the lesser of the current month Market
Energy Price or Contract Price for each kWh of Test Energy.
6.2 Net Energy Price. For all Net Energy delivered by the Seller to the Buyer
from the Operation Date through the end of the Initial Term, Buyer shall pay the Seller
the Contract Price.
6.3 Contract Price, Terms and Conditions to Remain in Effect for Term. The
prices, terms and conditions specified in this Agreement shall remain in effect until
expiration of the Term. Notwithstanding any provision in this Agreement, neither Party
shall seek, nor shall support any third party in seeking, to prospectively or retroactively
revise the prices, terms or conditions of service of this Agreement through application or
complaint to FERC pursuant to the provisions of Section 205, 206 or 306 of the Federal
Power Act, or any other provisions of the Federal Power Act, absent the prior written
agreement of the Parties. Further, absent the prior agreement in writing by both Parties,
the standard of review for changes to the prices, terms and conditions of service of this
Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the
"public interest" standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas
Service Corp., 350 US 332 (1956) and Federal Power Commission v. Sierra Pacific
Power Co., 350 US 348 (1956).
ARTICLE 7
ENVIRONMENTAL ATTRIBUTES
7.1 Environmental Attributes. Buyer will be granted ownership of all of the
Environmental Attributes associated with the Facility. Title of all Environmental
Attributes shall pass to Buyer at the same time that transfer of title of the associated Test
Energy or Net Energy to Buyer occurs. If after the Effective Date any additional
Environmental Attributes or similar environmental value is created by legislation,
regulation, or any other action, including but not limited to, carbon credits and carbon
offsets, Buyer shall be granted ownership of all of these additional Environmental
Attributes or environmental values that are associated with the Test Energy or the Net
Energy delivered by the Seller to Buyer. All reasonable costs of securing the ownership
of these additional Environmental Attributes and environmental values, including
documented Seller costs, shall be paid by the Buyer.
Seller shall use prudent and commercially reasonable efforts to ensure that any
operations of the Facility do not jeopardize the current or future Environmental Attribute
status of this geothermal generation Facility.
7.2 The Parties shall cooperate to ensure that all Environmental Attribute
certifications, rights and reporting requirements are completed by the responsible Parties.
PAGE 16
7.2.1 At least sixty (60) days prior to the First Energy Date, the Parties
shall mutually cooperate to enable the Environmental Attributes from this Facility to be
placed into the Buyer's WREGIS account or any other Environment Attribute accounting
and tracking system selected by the Buyer. The Buyer shall reimburse the Seller for any
WREGIS or other Environmental Attribute system fees incurred to enable this to occur
and/or any reoccurring WREGIS or other Environmental Attribute system fees for the
Term of this Agreement. If the Environmental Attribute accounting and tracking system
initially selected by the Buyer is materially altered or discontinued during the Term of
this Agreement, the Parties shall cooperate to identify an appropriate alternative
Environmental Attribute accounting and tracking process and enable the Environmental
Attributes be processed through this alternative method.
7.2.2 The Seller shall not report under Section 1605(b) of the Energy
Policy Act of 1992 or under any applicable program that any Environmental Attributes
are owned by the Seller.
7.2.3 As the Buyer is the sole owner of the Environmental Attributes
from this Facility, only the Buyer shall be entitled to sell, trade, assign or otherwise
transfer or claim the Facility's Environmental Attributes.
7.2.4 If the Buyer requests additional Environmental Attribute
certifications beyond what is provided by the WREGIS process the Seller shall obtain
any Environmental Attribute certifications required by the Buyer for those Environmental
Attributes delivered to the Buyer from the Seller. If the Seller incurs cost, as a result of a
Buyer's request, Seller shall invoice the Buyer for the reasonable costs of providing such
certification. If the Buyer elects to obtain its own certifications, then Seller shall fully
cooperate with the Buyer in obtaining such certification.
ARTICLE 8
DELIVERY AND SHORTFALL OBLIGATIONS
8.1 Delivery and Accentance of Test Energy. Except when either Parts
performance is excused as provided herein, the Buyer will purchase and Seller will sell
the Test Energy produced by the Facility.
8.2 Delivery and Acceptance of Net Energy. Except when either Party's
performance is excused as provided herein, the Buyer will purchase and Seller will sell
the Net Energy produced by the Facility.
8.3 No Deliveries In Excess of the Maximum Capacity. Under no
circumstances will the Seller deliver Net Energy and/or Test Energy to the Metering
Point, in an amount that (1) exceeds 36,000 kW at any moment in time or (2) that exceeds
the Maximum Capacity by any amount for more than five (5) consecutive minutes.
Delivery of Net Energy and/or Test Energy by the Seller to the Metering Point that
exceeds either item (1) or (2) of this section shall be a Material Breach of this Agreement.
Any Material Breach of this Agreement arising under this Section 8.3 may be cured by
PAGE 17
the Seller reducing the Net Energy or Test Energy deliveries to the Buyer to no longer
exceed the limits established in this section. In addition, the Seller shall identify the
circumstances that caused the Facility to deliver energy in excess of these limitations and
implement the necessary operational procedures to prevent similar deliveries in excess of
these limits. If the Seller repeatedly exceeds these limits and is not taking commercially
reasonable efforts to resolve this issue, the Buyer may terminate this Agreement.
8.4 Forecasting. At its expense, Seller shall provide to Buyer for the Term,
forecasting information provided via electronic format acceptable to the Buyer or any
other format that the Buyer and Seller mutually agree is acceptable. The Seller shall be
responsible for all costs associated with creating and transmitting the forecasting
information to the Buyer. Each forecast will take into account any Scheduled Outages,
any known Forced Outages, known curtailments or known capacity deratings affecting
the Facility. The Buyer and Seller shall mutually develop and approve the electronic
format and process of transmitting the data no later than thirty (30) days prior to the
Operation Date. The forecasting information shall be provided as follows:
(1)No later than 1:00 pm Pacific Time each Business Day, the Seller
shall provide an hourly forecast that starts at 5:00 am Pacific Time of the
next day and runs for a minimum of 168 hours (7 days).
(2)Any deviations exceeding or equal to plus or minus ten percent
(10%) of the previously provided forecast will be communicated to
the Buyer in a prompt and timely manner. In the case of a planned
event the Seller shall notify the Buyer by 5:00 pm Pacific Time of
the preceding day of any Net Energy forecasting deviation of the
previously provided forecast. In the case of an unplanned event,
the Seller shall notify the Buyer promptly after the occurrence of
the unplanned event. In both cases, the Seller will include with
this notification the expected duration and quantity of the energy
delivery reductions that will occur at the Metering Point.
8.4.1 Basis of Forecasts. The forecasts called for by this
Agreement shall be consistent with any specific requirements of this Agreement,
geothermal industry standards and Good Utility Practice(s).
8.4.2 Provision of Forecasting. The provision of the forecasting
information described in Section 8.4 in accordance with Good Utility Practice(s) is an
integral component of this Agreement. Accordingly, Seller shall act in a manner
consistent with Good Utility Practice(s) with the goal of providing timely, useful, quality
forecasts to the Buyer under Section 8.4. If Seller fails in any material respect to act in
conformity with the preceding sentence, Buyer may provide notice to Seller stating in
reasonable detail the basis for Buyer's belief that Seller is defaulting in its obligations
under this Article 8. Seller shall have ten (10) Business Days in which to cure the alleged
default, to commence the cure of the alleged default if it cannot reasonably be cured
within the ten (10) Business Day period (and thereafter diligently pursue such cure to
completion), or to submit the matter to dispute resolution under Article 24. With respect
PAGE 18
to any Facility Lender or Investor, the ten (10) Business Day periods set forth in the
preceding sentence shall be extended to thirty (30) days from date of Buyer's notice to
Seller under this Section 8.4. As long as Seller is pursuing dispute resolution under
Article 24 in good faith, Seller shall not be in default of this Section and shall have
sixty (60) days from any final resolution of the dispute in which to implement any
agreed-upon or required cure ("Forecast Cure Period").
8.5 Output Guarantee
8.5.1 By December 0 of each calendar year, the Seller shall submit in
writing to the Buyer the identity of a licensed professional
independent engineer or licensed professional independent
engineering firm and the independent engineer or engineering
firm's qualifications that the Seller intends to contract with to
complete the annual certification as required in this Section. The
Seller shall be responsible for all costs of retaining this engineer
and the cost of completing the certification as required within this
Section. No later than ten (10) Business Days after Seller's
notification to the Buyer of the Seller's proposed independent
engineer or independent engineering firm, Buyer shall send Seller
a written notice, either (A) approving the independent engineer or
independent engineering firm specified in the notice, or (B) setting
forth in reasonable detail Buyer's reasons for concluding that the
independent engineer or independent engineering firm selected by
the Seller is not acceptable. If Buyer does not respond on or before
the end of the tenth (10th) Business Day after Seller's notice, the
independent engineer or the independent engineering finn selected
by the Seller shall be deemed to be acceptable. If Buyer
reasonably disagrees that the Seller selected independent engineer
or independent engineering firm is acceptable, the Parties shall
cooperate promptly and in good faith to address Buyer's concerns
and agree upon an independent engineer or independent
engineering firm. If the Parties are unable to agree to an
independent engineer or independent engineering firm within
ten (10) Business Days of Buyer's notice of disagreement, either
Party may pursue dispute resolution under Article 24 to determine
an independent engineer.
8.5.2 No later than February 1st of each calendar year, the Seller will
provide the Buyer with a report and an energy forecast, stamped
and approved by the professional independent engineer or the
independent engineering firm specified above, containing at the
minimum, certification of the following:
a) Current status of the geothermal resource in comparison to the
previous status of the resource. This information will include a
detailed description of any geothermal resource degradation,
PAGE 19
the apparent vause of such degradation, assessment of future
status of the resource and its ability to sustain its current level
of output in consideration of the requirements of Section 8.7.
b)Estimated lost Net Energy (measured in kWh) production
associated with Scheduled Outages as specified in Section 1.58
that are planned to occur for the next twenty-four (24) months
beginning with March l of the current year.
c)Estimated energy (measured in kWh) that the Facility will be
able to deliver to the Metering Point for each of the next
twenty-four (24) months beginning with March of the current
year.
d)The assumptions used by the engineer.
8.5.3 No later than ten (10) Business Days after Seller provides a written
copy of the certification as specified above to the Buyer, the Buyer shall send Seller a
written notice, either (A) approving the certification, or (B) setting forth in reasonable
detail Buyer's reasons for concluding that the certification is not acceptable. If Buyer
does not respond on or before the end of the tenth (10th) Business Day after Seller's
notice, the certification provided by the Seller shall be deemed to be acceptable. If Buyer
reasonably disagrees that the Seller's certification is acceptable, the Parties shall
cooperate promptly and in good faith to address Buyer's concerns and agree upon a
certification. If the Parties are unable to agree on the certification as being acceptable
within ten (10) Business Days of Buyer's notice of disagreement, either Party may pursue
dispute resolution under Article 24 to determine an acceptable certification.
8.5.4 The "Annual Output Forecast" (measured in kWh) shall be the
lower of (i) the sum of the monthly estimated energy established in Section 8.5.2 c) for
the first twelve (12) months of the information provided or (ii) the Expected Annual
Average Capacity established in Appendix B, multiplied by 8,760 hours and then by the
Annual Capacity Factor. The last Annual Output Forecast of the Initial Term of this
Agreement shall be based upon the actual Calendar Months available for the project to
deliver Net Energy from March ls to the last day of the Initial Term of this Agreement,
which may or may not be a full twelve (12) months.
8.5.4.1 For the period beginning with March 1st of the first (1)
Contract Year through February 28th of the third (3 rd) Contract Year an
Annual Output Forecast shall be provided for information purposes only
and no Net Energy Shortfall will be calculated for this period.
8.5.4.2 Upon conclusion of an event that causes energy deliveries
to the Buyer to be reduced, the Seller shall calculate the quantity of energy
delivery reductions they believe occurred due to the event. These events
shall include Forced Outages, force majeure, actual Scheduled
Maintenance outages, curtailments required by the Buyer or curtailments
PAGE 20
required by the Interconnection Provider. Upon mutual agreement as to
the quantity of energy delivery reduction, the Annual Guaranteed Output
shall be adjusted accordingly.
8.5.5 Energy Delivery Guarantee. Reconciliation, and Net
Energy Shortfall Determination. Seller guarantees that the Total Annual Facility
Net Energy shall equal or exceed the Annual Guaranteed Output for each Contract
Year during the Initial Term of this Agreement beginning with March 1 of the
fourth (4th) Contract Year. The determination of whether Seller has met its
Annual Guaranteed Output requirement shall be made on an annual basis
beginning on March 1St of the fifth (5th) Contract Year by comparing the amount
of the previous twelve (12) month's Total Annual Facility Net Energy to the
Annual Guaranteed Output as provided for in this Section.
8.5.5.1 If the Total Annual Facility Net Energy is equal to
or greater than the Annual Guaranteed Output in the applicable
period, Seller shall be deemed to have met its Annual Guaranteed
Output obligation for that period, and Seller shall have no
obligation to pay Net Energy Shortfall Damages or to true-up
energy delivery obligations with respect to that period. Any Net
Energy delivered during this period exceeding the Annual
Guaranteed Output may be used to make up the previous period
Net Energy Shortfall if one exists.
8.5.5.2 If the Total Annual Facility Net Energy is less
than the Annual Guaranteed Output for a specified period, then a
Net Energy Shortfall exists and is equal to the Annual Guaranteed
Output minus the Total Annual Facility Net Energy. The Net
Energy Shortfall may be made up in the subsequent twelve (12)
month period beginning at March 1. Net Energy delivered during
the immediately following twelve (12) month period in excess of
the Annual Guaranteed Output for that period may be used to make
up the previous period's Net Energy Shortfall. At the end of the
subsequent twelve (12) month period, if the Net Energy Shortfall
has not been made up, then any remaining Net Energy Shortfall
Damages will be calculated based upon any remaining balance of
the Net Energy Shortfall and a billing will be presented to the
Seller which the Seller will be required to pay the Buyer within
fifteen (15) days of the date of the billing notice.
Any remaining Net Energy Shortfall at the end of the Initial Term
of this Agreement will be payable to the Buyer within fifteen (15)
days of the date of the billing notice being provided to the Seller.
PAGE 21
8.6 Buyer Acceptance of Energy. Excused Payment. Payment for Unexcused
Curtailments and Adjustment of the Annual Guaranteed Output
8.6.1 Acceptance of Energy—
a.) The Buyer shall be excused from accepting Net Energy
and Test Energy for any reason.
8.6.2 Excused Energy Payment -
a.)The Buyer shall be excused from paying for Net Energy
and Test Energy that the Buyer did not accept in any
Contract Year due to an event of Force Majeuré or that
is equal to or less than the Annual Allowed Energy
Reduction. Net Energy and Test Energy that is not
accepted by the Buyer due to an event of Force Majeure
is not included in the calculation of MWh's not
accepted by the Buyer in determining if the Buyer has
exceeded the Annual Allowed Energy Reduction.
b.)The Buyer shall not be excused from paying for Net
Energy and Test Energy that the Buyer did not accept
due to an economic dispatch.
8.6.3 Payment for Unexcused Curtailment -
a.) If the Buyer fails to accept Net Energy or Test
Energy that the Facility could have delivered, and
payment for the unaccepted energy is not excused
as specified in section 8.6.2 a), then the Buyer shall
pay the Seller the applicable Contract Price or Test
Energy Price plus any applicable PTC Value for the
estimated Net Energy and/or Test Energy that the
Seller was unable to deliver to the Buyer. The
estimated Net Energy and/or Test Energy (measured
in kWh) that was not delivered will be determined
based upon the most recently provided energy
forecast, prior to the curtailment, as specified in
Section 8.4 of this Agreement for the applicable
time period in which the Buyer did not accept the
Seller's energy. If the curtailment event exceeds
the time period of the energy forecast (168 hours)
the Buyer and Seller shall mutually agree upon the
estimated Net Energy and/or Test Energy based
upon the most recently provided energy forecast
PAGE 22
plus any additional information available.
b.) If the Buyer does not accept the Net Energy from
this Facility, then Seller may attempt to sell all or a
portion of the Net Energy to another party for just
the period of when Buyer is not accepting the Net
Energy from the Facility. Seventy-five percent
(75%) of any net energy sales payments the Seller
receives from another party will be deducted from
any payments the Buyer is required to make to the
Seller for the period in which the Buyer was not
accepting the Facility's Net Energy.
8.6.4 Adjustment of Guaranteed Output -
If the Buyer requires the Seller to reduce Net Energy deliveries to
the Buyer from the Facility pursuant to the terms of this Article 8.6,
the Annual Guaranteed Output for the impacted Contract Year(s)
will be reduced by the same amount as the estimated Net Energy that
was not delivered as a result of the Buyer's curtailment
requirements.
8.7 Requirements for the Addition of New Geothermal Energy Uses.
Seller may add additional uses of geothermal energy controlled by Seller or available for
Seller's use, subject to the terms of this Section 8.7.
8.7.1 Certification of Geothermal Energy Sufficiency. Prior to allowing
each new geothermal use(s) to be built and delivery of geothermal energy
to commence to the new geothermal use(s), an independent licensed
geothermal reservoir engineer shall certify that for the remaining Term of
this Agreement and in the professional judgment of this engineer, the
geothermal energy production capability of the geothermal resource
controlled by Seller or available for Seller's use is sufficient to supply at
least one hundred percent (100%) of the geothermal energy requirements
of (1) the Facility, (2) the existing other use(s) of geothermal energy, and
(3) the proposed new use(s) of the geothermal energy.
8.7.1.1 The independent engineer shall be selected by
Seller and shall be reasonably acceptable to Buyer. The Seller
shall be responsible for all costs of retaining this engineer and the
cost of completing the certification as required within this Section.
• 8.7.1.2 Seller shall provide Buyer with a copy of the
independent engineer's certification prior to adding any additional
PAGE 23
geothermal uses. Buyer shall have sixty (60) days to provide
Seller with the Buyer's acceptance or rejection of such
certification. If rejected, the Buyer will supply Seller the reason(s)
why the certification was rejected and the necessary modifications
required to make the certification acceptable.

8.7.1.3 Geothermal energy use(s) that utilize waste heat
from the Facility and do not materially affect the power operations
of the Facility may be installed by Seller.

8.8 Title and Risk of Loss. As between the Parties, Seller shall be deemed to
be in control of the energy output from the Facility up to and until delivery and
acceptance at the Metering Point by the Buyer. Title and risk of loss related to the energy
shall transfer from Seller to Buyer at the Metering Point.

8.9 Station Energy. Seller shall enter into separate arrangements for the
supply of electric services to the Facility to supply Station Energy when the Facility's
generation is unable to meet the Station Energy requirements. Seller is responsible for
causing these electric services to be available before the First Energy Date. Seller will
specifically design the Facility to ensure that no energy purchased for supply of electric
energy to the Facility is delivered to the Buyer as Net Energy or Test Energy.
ARTICLE 9
METERING AND TELEMETRY

9.1 Metering and Telemetry. Seller will arrange for the Interconnection
Provider to provide, install, and maintain Metering and Telemetry Equipment to be
located at the Metering Point to accurately calculate the actual energy deliveries from the
Seller to the Metering Point and provide continuous telemetry information from the
Facility to the Interconnection Provider and the Buyer. The Metering and Telemetry
Equipment shall be of the type required to accurately measure, record and report the
energy to provide the Buyer adequate Net Energy and Test Energy measurement data to
administer this Agreement and to integrate the Facility's energy into the Interconnection
Provider's electrical system. The Buyer shall not be responsible for any costs of the
actual Metering and Telemetry Equipment, installation, inspections, maintenance and
testing costs.

9.2 Seller will arrange for and make available at Seller's cost a communication
circuit acceptable to the Interconnection Provider and the Buyer, dedicated to
Interconnection Provider and the Buyer's use to be used for load profiling and another
communications circuit dedicated to Interconnection Provider and Buyer's
communication equipment for continuous telemetering of the Facility's energy deliveries
to Designated Dispatch Facility. Interconnection Provider and Buyer, provided
equipment will be owned and maintained by either the Interconnection Provider or the
PAGE 24
Buyer. The Buyer shall be not be responsible for any of the cost of purchase, installation,
operation, and maintenance, including administrative cost of this equipment.
9.3 All meters used to determine the billing hereunder shall be sealed and the
seals shall be broken only by the Interconnection Provider or the Buyer when the meters
are to be inspected, tested or adjusted.
9.4 Meter Inspection. Seller will arrange for the Interconnection Provider to
inspect the Metering and Telemetry installations regularly and test meters on the
applicable periodic test schedule relevant to the Metering and Telemetry Equipment
installed. If requested by the Seller, the Interconnection Provider shall make a special
inspection or test of a meter and the Seller shall pay the reasonable costs of such special
inspection. The Seller shall make arrangements with the Interconnection Provider to be
notified at least two (2) Business Days prior to the time when any inspection or test shall
take place, and the Seller may have representatives present at the test or inspection. If a
meter is found to be inaccurate or defective, it shall be adjusted, repaired or replaced, at
the Seller's expense, in order to provide accurate metering. If a meter fails to register, or
if the measurement made by a meter during a test varies by more than two percent (2 1/o)
from the measurement made by the standard meter used in the test, adjustment (either
upward or downward) to the payments Seller has received shall be made to correct those
payments affected by the inaccurate meter for the actual period during which inaccurate
measurements were made. If the actual period cannot be determined, corrections to the
payments shall be based on the shorter of (1) a period equal to one-half (1/2) the time
from the date of the last previous test of the meter to the date of the test which established
the inaccuracy of the meter; or (2) six (6) months. Seller shall state such adjustment as a
credit or additional charge, as appropriate, on its next invoice.
9.5 Additional Tel If the Buyer requests telemetry equipment,
information or services of any nature beyond that expressly required by the
Interconnection Provider, the Seller and Buyer shall mutually cooperate to make efficient
use of Seller's, Interconnection Provider's and Buyer's telemetry equipment to provide
the additional information requested by Buyer in the most cost-effective manner. The
Seller shall not be responsible for any cost associated with additional telemetry
equipment, information, services or requirements that are beyond those expressly
required by the Interconnection Provider.
ARTICLE 10
SYSTEM PROTECTION
10.1 Operation and Maintenance of Seller's Facilities. Seller shall construct,
operate and maintain the Facility and Seller's Interconnection Facilities in accordance
with the Interconnection Providers' requirements, Good Utility Practice(s), the National
Electrical Code, the National Electrical Safety Code, and any other applicable local, state
and federal codes.
PAGE 25
ARTICLE 11
FACILITY AND INTERCONNECTION
11.1 Design of Facility. Seller will design, construct, install, own, operate and
maintain the Facility and any Seller-owned Interconnection Facilities so as to allow safe
and reliable generation and delivery of energy to the Buyer for the full Term of the
Agreement.
11.2 Interconnection Facilities. Seller will construct, install, own and maintain
all Interconnection Facilities other than those owned, installed or maintained by the
Interconnection Provider. Buyer will not be responsible for any costs of interconnecting
the Seller's Facility with the Interconnection Provider.
ARTICLE 12
GENERAL OPERATIONS
12.1 Communications. Seller, Interconnection Provider and Buyer shall
maintain appropriate operating communications through the Designated Dispatch Facility
in accordance with Appendix F.
12.2 Scheduled Maintenance. On or before March 1 of each calendar year,
Seller shall submit a written proposed maintenance schedule of significant Facility
maintenance for the next twelve (12) months, beginning with March l of the current
year, and Buyer and Seller shall mutually agree as to the acceptability of the proposed
schedule. The Parties determination as to the acceptability of Seller's timetable for
scheduled maintenance will take into consideration the need to perform maintenance and
perform other work as required to maintain the Facility's reliable operations, Good
Utility Practice(s), Buyer's system requirements, Interconnection Provider's maintenance
schedule, Buyer's maintenance schedule and Seller's preferred schedule. Neither Party
shall unreasonably withhold acceptance of the proposed maintenance schedule. Upon
mutual agreement between the Parties, or otherwise if required by Good Utility Practices,
the previously approved Scheduled Maintenance may be revised during a Contract Year.
12.3 Maintenance Coordination. Buyer and Seller shall mutually cooperate, to
the extent practical, to coordinate the Facility's maintenance schedules with the
Interconnection Provider's maintenance schedules and the Buyer's maintenance
schedules such that they occur simultaneously.
12.4 Contact Prior to Curtailment. The Buyer will make a reasonable attempt to
contact Seller prior to exercising its rights to curtail, interrupt or reduce deliveries from
the Seller's Facility. Seller understands that in the case of emergency circumstances,
real time operations of the electrical system, and/or unplanned events, the Buyer may not
be able to provide notice to the Seller prior to interruption, curtailment, or reduction of
electrical energy deliveries to the Buyer.
PAGE 26
ARTICLE 13
BILLING, RECORDS, AUDITS
13.1 Billing Invoices. The monthly billing period shall be the calendar month.
No later than three (3) Business Days after the end of each calendar month, Seller shall
provide to Buyer, by e-mail or fax and confirmed by first-class mail, an invoice for the
amount due Seller by Buyer for the previous calendar month billing period. Seller's
invoice shall show all billing parameters, rates and factors, and any other data reasonably
pertinent to the calculation of monthly payments due to the Seller. Each such monthly
invoice shall calculate the amount that Buyer owes to the Seller for Test Energy, Net
Energy and any offsets for Net Energy Shortfall Damages. Upon receipt of this invoice,
Buyer shall review and confirm all calculations and contact the Seller with any identified
discrepancies.
13.2 Payments. Unless otherwise specified in this Agreement, undisputed
payments due under this Agreement shall be due and payable by electronic funds transfer
on or before the twenty-fifth (25th) day of the invoicing month or fifteen (15) days after
receipt of the billing statement from the Seller by the Buyer, whichever is later. If the due
date occurs on a day that is not a Business Day, payment will be due on the next Business
Day. If the undisputed amount due is not paid on or before the due date, a late payment
charge shall be applied to the unpaid balance and shall be added to the next billing
statement. Such late payment charge shall be calculated based on the Interest Rate.
Buyer shall have the right to withhold from the payment any unpaid and undisputed
Seller amounts due to Buyer.
13.3 Maintenance of Records. Seller shall maintain at the Facility or such other
location mutually acceptable to the Parties adequate total generation, net generation, and
maximum generation (kW) records in a form and content consistent with Good Utility
Practice(s).
13.4 Right to Audit: Refunds: Billing Disuutes.
13.4.1 Audit Rights. Each Party shall have the right, upon reasonable
notice to the other Party and during the other Party's regular business hours and without
unduly interfering with the conduct of that Party's business, to access all of that Party's
records pertaining to invoices under this Agreement and to audit reports, data,
calculations, invoices, Net Energy, and maximum generation records pertaining to the
Facility. The auditing Party shall bear its own costs of performing such audit; provided,
however, that the other Party shall cooperate with the audit and shall not charge the
auditing Party for any reasonable costs (including without limitation the cost of
photocopies) that the other Party may incur as a result of such audit. A Party shall have
twenty-four (24) months from the date on which an invoice or notice is received to audit
and to challenge that invoice or notice.
13.4.2 Refunds of Overpavments and Underpavments. If an audit
discovers a billing error or errors that resulted in an overpayment by the Buyer, Seller
PAGE 27
shall refund to the Buyer the amount of the overpayment plus interest calculated at the
Interest Rate thereon from the date such overpayment was made by the Buyer to (but not
including) the date the Buyer actually receives the refund from the Seller. If the audit
discovers a billing error or errors that resulted in an underpayment by the Buyer, the
Buyer shall pay to the Seller the amount of the underpayment plus interest calculated at
the Interest Rate thereon from the due date thereof to (but not including) the date the
Seller actually receives the payment thereof from the Buyer. The Interest Rate used in
this Section shall be the Interest Rate applicable to cash collateral.
13.4.3 Billing Disputes. Either Party may dispute invoiced amounts, but
shall pay to the other Party at least the undisputed portion of invoiced amounts on or
before the invoice due date. To resolve any billing dispute, the Parties shall use the
procedures set forth in Article 24. When the billing dispute is resolved, the Party owing
shall pay the amount owed within five (5) Business Days of the date of such resolution,
with interest charges calculated on the amount owed in accordance with the provisions of
Section 13.4.2. Buyer at any time may offset against any and all amounts that may be
due and owed to Seller under this Agreement, any and all undisputed amounts, including
damages and other payments, that are owed by Seller to Buyer pursuant to this
Agreement. Likewise, Seller at any time may offset against any and all amounts that may
be due and owed to Buyer under this Agreement, any and all undisputed amounts,
including damages and other payments, that are owed by Buyer to Seller pursuant to this
Agreement. Undisputed and non-offset portions of amounts invoiced under this
Agreement shall be paid on or before the due date or shall be subject to the interest
charges set forth in Section 13.4.2.
ARTICLE 14
INDEMNIFICATION AND INSURANCE
14.1 Indemnification. Each Party shall agree to hold harmless and to indemnify
the other Party, its officers, agents, affiliates, subsidiaries, parent company and
employees against all loss, damage, expense and liability to third persons for injury to or
death of person or injury to property, proximately caused by the indemnifying Party's
construction, ownership, operation or maintenance of, or by failure of, any of such
Party's works or facilities used in connection with this Agreement. The indemnifying
Party shall, on the other Party's request, defend any suit asserting a claim covered by this
indemnity. The indemnifying Party shall pay all costs, including reasonable attorney fees
that may be incurred by the other Party in enforcing this indemnity.
14.2 Insurance. During the Term of this Agreement, Seller shall secure and
continuously carry the following insurance coverage:
14.2.1 Worker's ConiDensation Insurance. Seller shall, during the Initial
Term of this Agreement and any extensions thereof, provide and maintain Worker's
Compensation Insurance for all its employees engaged in work under this Agreement in
accordance with statutory requirements. Seller shall obtain a Waiver of Subrogation
Endorsement in favor of Buyer in reference to Worker's Compensation Insurance.
PAGE 28
If any direct claim for Worker's Compensation benefits is asserted against
Seller by any of Seller's employees or, in the event of the death of a Seller's
employee, by such employee's personal representatives, then, upon timely written
notice from Buyer, Seller shall undertake to defend Buyer against such claim(s)
and shall indemnify and hold Buyer harmless from and against any such claim(s)
to the extent of all benefits awarded.
14.2.2 Comprehensive General Liability Insurance (including coverage
for bodily injury and death, property damage, independent contractors, products and
completed operations) with limits equal to $1,000,000, each occurrence, combined single
limit. The deductible for such insurance shall be consistent with current Insurance
Industry Utility practices for similar property. Seller to obtain a Waiver of Subrogation
Endorsement in favor of Buyer in reference to comprehensive general liability insurance.
14.2.3 Excess/Umbrella Liability Insurance with limits not less
than $5,000,000.
14.2.4 If the Seller, in its sole discretion, elects to obtain Boiler
and Machinery Insurance, Property Insurance or Business Interruption Insurance,
the coverages and deductible shall be additionally declared on the annual
insurance certification as required in section 14.3.
14.2.5 All of the above insurance coverages shall be placed with
insurance companies with an A.M. Best rating of A- or better and shall include:
a)A Waiver of Subrogation Endorsement in favor of the Buyer.
b)With respect to Comprehensive General Liability Insurance
and Excess/Umbrella Liability Insurance, an endorsement
naming Buyer as an additional insured, and loss payee.
c)The policy shall include a provision stating that such policy
shall not be canceled or the limits of liability reduced without
sixty (60) days' prior written notice to Seller. Seller shall
notify Buyer within five (5) Business Days after Seller receives
any such notice.
14.3 Seller to Provide Certificate of Insurance. As required in Section 4.1.7 of
this Agreement and annually thereafter, Seller shall furnish Buyer a certificate of
insurance evidencing the coverage and required endorsements as set forth above.
14.4 Seller to Notify Buyer of Loss of Coverage. If the insurance coverage
required by Section 14.2 shall lapse for any reason, Seller will immediately notify the
Buyer in writing. The notice will advise the Buyer of the specific reason for the lapse
and the steps the Seller is taking to reinstate the coverage.
PAGE 29
14.5 Seller's Failure to Maintain Required Insurance. Seller's failure to
maintain the insurance as required in this Article 14 shall be a Material Breach of this
Agreement.
ARTICLE 15
CREDIT AND COLLATERAL REQUIREMENTS
15.1 Financial Information.
15.1.1 The Buyer shall make available electronically to the Seller
(i)within one hundred-twenty (120) days following the end of a Buyer's fiscal year, a
copy of the Buyer's audited consolidated financial statements for its fiscal year, and
(ii)within sixty (60) days after the end of each of its first three (3) fiscal quarters of each
fiscal year, a copy of the Buyer's unaudited consolidated financial statements for such
fiscal quarter. In all cases, the statements shall be for the most recent accounting period
and prepared in accordance with generally accepted accounting principles, consistently
applied; provided, however, that should any such statements not be available on a timely
basis due to a delay in preparation or certification, such delay shall not be an Event of
Default so long as the Buyer diligently pursues the preparation of the statements. This
Financial Information is available on the Buyer's website www.idahoDower.cOm .
Buyer's assistance in guiding the Seller to this information on the Buyer's website will be
satisfaction of this requirement.
15.1.2 The Seller shall make available electronically to the Buyer
(i) within one hundred-twenty (120) days following the end of U.S. Geothermal's fiscal
year, a copy of U.S. Geothermal's audited consolidated financial statements for its fiscal
year, and (ii) within sixty (60) days after the end of each of its first three (3) fiscal
quarters of each fiscal year, a copy of U.S. Geothermal's unaudited consolidated financial
statements for such fiscal quarter. In all cases, the statements shall be for the most recent
accounting period and prepared in accordance with generally accepted accounting
principles, consistently applied; provided, however, that should any such statements not
be available on a timely basis due to a delay in preparation or certification, such delay
shall not be an Event of Default so long as the Seller diligently pursues the preparation,
certification and delivery of the statements. This Financial Information is available on
the Seller's website www.usgeothermal.com . Seller's assistance in guiding the Buyer to
this information on the Seller's website will be satisfaction of this requirement.
15.1.3 If during the Term of this Agreement any of the financial
statements required in Sections 15.1.1 or 15.1.2 are not publicly available, the Parties
shall mutually agree to confidentially agreements to allow exchange of confidential
information and/or alternative reporting that is acceptable documentation in lieu of the
documents required in Sections 15.1.1 and 15.1.2.
PAGE 30
15.2 Seller's Performance Assurances.
15.2.1 Exploration Performance Assurance. Within fifteen (15) Business
Days after the Seller fails to satisfy the second or third Project Milestones identified in
Appendix H, the Seller shall provide evidence to Buyer that Performance Assurance in
the amount of no less than $100,000 has been established and will be maintained until
such time as 1) this Agreement has been terminated, at which time the Seller will forfeit
the $100,000 Performance Assurance to Buyer, or 2) all Seller Project Milestone defaults
have been cured, at which time any rights the Buyer has to this specific Performance
Assurance will be released. Upon the Seller's default of these Project Milestones, Notice
of Default and the Default cure provisions as specified in Section 25.2 shall apply.
15.2.2 Development Performance Assurance - Within fifteen (15)
Business Days after the Seller fails to satisfy the fourth Project Milestone (power plant
engineer, procure, and construct notice to proceed) identified in Appendix H, the Seller
shall provide evidence to Buyer that Performance Assurance in the amount of no less
than $250,000 has been established and will be maintained until such time as this
Agreement has been terminated at which time the Seller shall forfeit this $250,000
Performance Assurance to the Buyer. If the Seller is able to demonstrate that the Seller
after commercially reasonable efforts was unable to achieve this Project Milestone due to
its inability to obtain project financing, the Buyer may still terminate the Agreement but
the $250,000 Performance Assurance shall not be forfeited to the Buyer. If all Seller
Project Milestone defaults have been cured, any rights the Buyer has to this Specific
Performance Assurance will be released. Upon the Seller's default of this Project
Milestone, Notice of Default and the Default cure provisions as specified in Section 25.2
shall apply.
15.2.3 Delay Performance Assurance - If the Facility does not achieve
its First Energy Date within ninety (90) days of the Scheduled First Energy Date, the
Seller shall within fifteen (15) Business Days provide evidence to Buyer that
Performance Assurance in the amount of no less than $250,000 has been established and
will be maintained until such time as 1) this Agreement has been terminated and all
damages due the Buyer have been satisfied, or 2) all Seller defaults and Material
Breaches have been cured, the First Energy Date has been achieved and all damages due
to the Buyer have been satisfied, at which time any rights the Buyer has to this specific
Performance Assurance will be released.
15.2.4 Operational Performance Assurance - If a Net Energy Shortfall as
determined by Section 8.5.5 exceeds thirty percent (30%) of the Annual Guaranteed
Output, the Seller shall within fifteen (15) Business Days provide evidence to Buyer that
Performance Assurance in the amount of no less than $250,000 has been established and
will be maintained until such time as 1) this Agreement has been terminated and all
damages due the Buyer have been satisfied, or 2) all Seller defaults and Material
Breaches have been cured, the Facility has met or exceeded its Annual Guaranteed
Output for two (2) consecutive Contract Years and no outstanding Net Energy Shortfall
exists, at which time any rights the Buyer has to this specific Performance Assurance will
be released.
PAGE 31
15.3 If Performance Assurance is required, the Seller shall provide one or a
combination of the following as Performance Assurance(s).
15.3.1 Cause Seller's Guarantor to execute and deliver to the Buyer a
Guaranty which is substantially in the form set forth as Appendix C (or, at Seller's
discretion, cause another guarantor that is not experiencing a Material Adverse Change
to execute and deliver to the Buyer a Guaranty which is substantially in the form set
forth as Appendix C or in another form acceptable to the Buyer); or
15.3.2 Establish and maintain at the Seller's expense an escrow account
for the benefit of the Buyer in a form reasonably acceptable to the Buyer; or
15.3.3 Provide a cash deposit to the Buyer; or
15.3.4 Provide a letter of credit in a form reasonably acceptable to the
Buyer.
15.4 Grant of Security Interest in Certain Collateral and Security. To secure its
obligations under this Agreement, Seller hereby grants to Buyer, a present and continuing
security interest in, and lien on (and right of setoff against), and assignment of, all cash
collateral and cash equivalent collateral and any and all proceeds resulting therefrom or
the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit
of, the secured Party. Seller shall take such action as Buyer reasonably requires in order
to perfect Buyer's first-priority security interest in, and lien on (and right of setoff
against), such collateral and any and all proceeds resulting therefrom or from the
liquidation thereof. This Section 15.4 applies only to cash collateral and cash equivalent
collateral established in accordance with Section 15.3 above.
15.5 Realization Upon Performance Assurance. Upon or at any time after the
occurrence and during the continuation of an Event of Default or an Early Termination
Date affecting Seller, the Buyer may do any one or more of the following: (i) exercise
any of the rights and remedies of a secured party with respect to all Performance
Assurance, including any such rights and remedies under law then in effect; (ii) exercise
its rights of setoff against any and all property of the Seller in the possession of the Buyer
or its agent; (iii) draw on any outstanding letter of credit issued for the Buyer's benefit;
and (iv) liquidate all Performance Assurance then held by or for the benefit of the Buyer
free from any claim or right of any nature whatsoever of the Seller, including any equity
or right of purchase or redemption by the Seller. The Buyer shall apply the proceeds of
the collateral realized upon the exercise of any such rights or remedies to reduce the
Seller's obligations under this Agreement, subject to the Buyer's obligation to return any
surplus proceeds remaining after such obligations are satisfied in full.
15.6 Interest Rate on Cash Collateral. Performance Assurance in the form of
cash shall bear interest at the Interest Rate and shall be paid to Seller on the third (3 d)
Business Day of each calendar month.
PAGE 32
ARTICLE 16
FORCE MAJEURE
16.1 Force Majeure.
16. 1.1 General. As used in this Agreement, "force majeure" or "an event
of force majeure" means any cause beyond the reasonable control of the Party claiming
force majeure which, despite the exercise of due diligence, such Party is unable to
prevent or overcome. Force majeure includes, but is not limited to, acts of God, fire,
flood, storms, wars, hostilities, civil strife, strikes and other labor disturbances (even if
such strikes or disturbances could be resolved by conceding to the demands of a labor
group), earthquakes, fires, lightning, epidemics, sabotage, severe weather, or changes in
law or regulation or governmental orders occurring after the Effective Date, to the extent
that by the exercise of reasonable foresight such Party could not reasonably have been
expected to avoid and by the exercise of due diligence it shall be unable to overcome
such force majeure event.
16.1.2 Events That Are Not "Force Maleure." Notwithstanding
Section 16.1.1, the term force majeure does not include: (a) Seller's ability to sell, or
Buyer's ability to purchase, Net Energy or Environmental Attributes at a more
advantageous price than is provided under this Agreement; (b) governmental or
regulatory action occurring after receipt of the Commission approval contemplated by
Article 27 and Article 28 that impairs Buyer's ability to recover the Contract Price in its
rates or that otherwise affects the value of this Agreement to Buyer or (c) the inability for
any reason to make payments hereunder when due.
16.13 Reiuirements Upon Occurrence of Force Maieure. If either Party
is rendered wholly or in part unable to perform its obligations under this Agreement
because of an event of force majeure, both Parties shall be excused from whatever
performance is affected by the event offorce rnajeure, provided that:
16.1.3.1 The Party claiming force majeure shall, as soon as
is reasonably possible after the occurrence of the force majeure, give the
other Party written notice describing the particulars of the occurrence. If
notice is provided by the Party claiming force majeure within seven days
of the actual event of force majeure, the Party claiming force majeure
may identify the start time of the force majeure event and upon the event
of force majeure being accepted by the notified Party, the party claiming
force majeure will be granted relief of obligations under this Agreement
from the date identified. If the Party claiming Force Majeure does not
provide notification to the other Party within seven days of the event, the
Party claiming force majeure will only be eligible to receive relief from
obligations within this agreement from the date the notice is provided..
PAGE 33

16.1.3.2 The suspension of performance shall be of no
greater scope and of no longer duration than is required by the event of
force majeure.

16.1.3.3 No obligations of either Party which arose before
the occurrence causing the suspension of performance and which could
and should have been fully performed before such occurrence shall be
excused as a result of such occurrence.

16.1.3.4 The Party claiming force nzajeure shall proceed
with reasonable diligence to remedy its inability to perform and shall
provide weekly progress reports to the other Party describing actions taken
to end the force majeure.

16.1.3.5 The Party claimingforce majeure is able to resume
performance of its obligations under this Agreement, that Party shall give
the other Party written notice to that effect.
Failure of a Party to comply with provisions of Sections 16.1.3.1, 16.1.3.2,
16.1.3.4 and 16.1.3.5 shall create liability of such Party only to the extent
the other Party is damaged by such failure.
16.2 Extension of Scheduled Operation Date and the Term. The Scheduled
Operation Date shall be extended on a day-for-day basis in the event offorce majeure. In
no event will any delay or failure of performance caused by any conditions or events of
force majeure extend this Agreement beyond its stated Term.
16.3 Termination for Extended Force Majeure. If a delay or failure of
performance caused by the event of force majeure results in a thirty percent (30%) or
more decrease in the delivery or receipt of Net Energy at the Metering Point of the
Facility when similarly compared to the most recently provided Annual Forecast
preceding the event offorce majeure and continues for an uninterrupted period of three
hundred sixty-five (365) days from the event's occurrence or inception, the Party not
claiming force majeure may, at any time following the end of such three hundred sixty-
five (365) day period, and prior to the event offorce majeure being cured, terminate this
Agreement upon written notice to the party claiming force majeure, without further
obligation by either Party except as to costs and balances incurred before the effective
date of such termination. The Party not claiming force majeure may, but shall not be
obligated to, extend such three hundred sixty-five (365) day period, for such additional
time as it, at its sole discretion, deems appropriate.
PAGE 34
ARTICLE 17
FORCED OUTAGE
17.1 Seller to Notify Buyer. Promptly upon the occurrence of an event at the
Facility that the Seller deems to be a Forced Outage the Seller shall notify the Buyer of
the declared Forced Outage and adjust the forecast if required as specified in Section 84.
17.2 Seller to Submit Explanation. Within two (2) Business Days of the Forced
Outage event the Seller shall submit to the Buyer a detailed explanation of the Forced
Outage event including but not limited to details of the equipment failure, apparent cause
of the failure, equipment affected by and taken out of service, estimated lost energy
production, and a schedule and plan for making the necessary repairs.
17.3 Buyer Shall Respond to Seller. Upon receipt of the detailed explanation of
the Forced Outage event, the Buyer shall within two (2) Business Days respond to the
Seller accepting, rejecting or requesting additional information in regards to the declared
Forced Outage event. If the Buyer does not respond to the Seller's initial submittal
within two (2) Business Days, the declared Forced Outage event shall be deemed to be
accepted.
17.4 Adjustment to Seller's Annual Guaranteed Output. Only after the
declared Forced Outage event has been accepted by the Buyer and the actual Net Energy
reduction of the specific Forced Outage event has been determined to be equal to or
greater than 33,000 kWh shall the Seller's Annual Guaranteed Output obligation be
adjusted to reflect the Net Energy curtailment that was a result of the Forced Outage. If
it is determined that the actual Net Energy reduction associated with the specific Forced
Outage event is less that 33,000 kWh, no adjustment of the Seller's Annual Guaranteed
Output shall be made.
ARTICLE 18
BUYER'S ACCESS RIGHTS
18.1 Seller to Provide Access. To the extent necessary, Seller hereby grants to
the Buyer for the Term of this Agreement all necessary right-of-ways and easements to
install, operate, maintain, replace, and remove the Buyer's Metering and Telemetry
Equipment, and other equipment and facilities necessary or useful to this Agreement,
including adequate and continuing access rights on property of the Seller.
18.2 Indemnity. If the Buyer exercises any right under this Agreement to
access or enter upon the Seller's property, such access or entry shall be at the Buyer's
sole risk and expense. Buyer shall hold the Seller harmless from, and indemnify the
Seller against, any and all liability for any loss, damage or injury to property or persons
arising from the Buyer's access to or entry upon to the Seller's property, except to the
extent that such loss, damage or injury is cause by the Seller's negligence or willful
misconduct.
PAGE 35
ARTICLE 19
NO THIRD PARTY LIABILITY,
NO DEDICATION OF FACILITY OR SYSTEM
19.1 No Third Party Liability. Nothing in this Agreement shall be construed to
create any duty to, any standard of care with reference to, or any liability to any person
not a Party to this Agreement. There are no third party beneficiaries of this Agreement.
19.2 No Dedication. No undertaking by one Party to the other under any
provision of this Agreement shall constitute the dedication of that Party's system or
facility or any portion thereof to the other Party or to the public or affect the status of the
Buyer as an independent public utility corporation or the Seller as an independent entity.
ARTICLE 20
SEVERAL OBLIGATIONS
Except where specifically stated in this Agreement to be otherwise, the duties,
obligations and liabilities of the Parties are intended to be several and not joint or
collective. Nothing contained in this Agreement shall ever be construed to create an
association, trust, partnership or joint venture, or impose a trust or partnership duty,
obligation or liability on or with regard to either Party. Each Party shall be individually
and severally liable for its own obligations under this Agreement.
ARTICLE 21
WAIVER
Any waiver at any time by either Party of its rights with respect to a default under
this Agreement or with respect to any other matters arising in connection with this
Agreement shall not be deemed a waiver with respect to any subsequent default or other
matter.
ARTICLE 22
CHOICE OF LAW
This Agreement shall be construed and interpreted in accordance with the laws of
the State of Idaho without reference to its choice of law provisions.
ARTICLE 23
LIMITATIONS
23.1 Remedies Satisfy Essential Purposes. THE PARTIES CONFIRM THAT
THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS
AGREEMENT SATISFY THE ESSENTIAL PURPOSES OF THIS AGREEMENT.
PAGE 36
23.2 Sole and Exclusive Remedies. FOR ANY PROVISION FOR WHICH
AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH
EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND
EXCLUSIVE REMEDY. THE OBLIGOR'S LIABILITY SHALL BE LIMITED AS
SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES
AT LAW OR IN EQUITY ARE WAIVED.
23.3 No Punitive, Conseuuential or Incidental Damages. IF NO REMEDY OR
MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN, THE OBLIGOR'S
LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH
DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY
AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE
WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL
BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR
INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION
DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY
PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE
LIMITATIONS IMPOSED IN THIS AGREEMENT ON REMEDIES AND THE
MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES
RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY,
WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR
ACTIVE OR PASSIVE.
23.4 Liquidated Damages. TO THE EXTENT ANY DAMAGES REQUIRED
TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE
THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR
OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND
THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE
APPROXIMATION OF THE HARM OR LOSS.
ARTICLE 24
DISPUTES
24.1 Disputes. If a dispute arises under this Agreement (a "Dispute"), within
ten (10) days following the delivered date of a written request by either Party (a "Dispute
Notice"), (1) each Party shall appoint a representative, and (2) the Parties' representatives
shall meet, negotiate and attempt in good faith to resolve the Dispute quickly, informally
and inexpensively. If the Parties' representatives cannot resolve the Dispute within
thirty (30) days after commencement of negotiations, then within ten (10) Business Days
following any request by either Party at any time thereafter, each Party representative
(3) shall independently prepare a written summary of the Dispute describing the issues
and claims, (4) shall exchange its summary with the summary of the Dispute prepared by
the other Party representative, and (5) shall submit a copy of both summaries to a senior
officer of the representative's Party with authority to irrevocably bind the Party to a
resolution of the Dispute. Within ten (10) Business Days after receipt of the Dispute
summaries, the senior officers for both Parties shall negotiate in good faith to resolve the
PAGE 37
Dispute. If the Parties are unable to resolve the Dispute within fourteen (14) Business
Days following receipt of the Dispute summaries by the senior offices, either Party may
seek available remedies.
24.2 Venue. Venue for any litigation arising out of or related to this Agreement
shall lie in the District Court of the Fourth Judicial District of Idaho in and for the County
of Ada.
ARTICLE 25
EVENTS OF DEFAULT, DELAY DAMAGES AND MATERIAL BREACHES
25.1 Events of Default. The following shall be deemed to be Events of Default:
25. 1.1 A Party's dissolution or liquidation;
25.1.2 A Party's assignment of this Agreement or any of its rights under
this Agreement for the benefit of creditors (except for an assignment to the Facility
Lender as security under the Financing Documents as permitted by this Agreement).
25.1.3 A Party's filing of a petition in bankruptcy or insolvency or for
reorganization or arrangement under the bankruptcy laws of the United States or under
any insolvency act of any state, or a Party voluntarily taking advantage of any such law
or act by answer or otherwise.
25.1.4 The filing of a case in bankruptcy or any proceeding under any
other insolvency law against a Party that could materially impact Buyer's ability to
perform its obligations under this Agreement if the affected Party does not obtain a stay
or dismissal of the filing within sixty (60) days after the Party receives a notice of default.
25.1.5 A Party's assignment of this Agreement, except as permitted by
this Agreement.
25.1.6 Any representation or warranty made by a Party in this Agreement
proves to have been false or misleading in any material respect when made or ceases to
remain true during the Term if such inaccuracy or cessation would reasonably be
expected to result in a significant adverse impact on the other Party and such default is
not cured within thirty (30) days after the Party's receipt of a notice of default.
25.1.7 Seller's failure to establish and maintain Performance Assurance as
required by this Agreement if the failure is not cured within thirty (30) days of Seller's
receipt of a notice of default.
25.1.8 A Guaranty Default affecting a Guaranty delivered in support of
this Agreement if the Guaranty Default is not cured within the time permitted by the
Guaranty and the Seller does not provide substitute Performance Assurance to replace the
Guaranty within fifteen (15) Business Days after the Seller's receipt of a notice of the
Guaranty Default.
PAGE38
25.1.9 Seller's unexcused failure to deliver energy from the Facility to
Buyer as required under this Agreement if the failure is not cured within fifteen (15)
Business Days of Seller's receipt of a notice of default.
25.1.10 Buyer's unexcused failure to receive and accept energy from the
Facility as required under this Agreement if the failure is not cured within fifteen (15)
days of Buyer's receipt of a notice of default.
25.1.11 Seller's failure to attain an actual Operation Date within 2,904
hours (4 months) of the Scheduled Operation Date.
25.1.12 A Party's failure to make a payment to the other Party when due
under this Agreement, if the failure is not cured within ten (10) Business Days of the
Party's receipt of a notice of default.
25.1.13 A Party's failure to comply with any material obligation under this
Agreement, if the failure would result in a significant adverse impact on the other Party
(other than a default already specifically enumerated in this Article) and the failure is not
cured within thirty (30) days of the Party's receipt of a notice of default; provided,
however, if such default cannot be cured within thirty (30) days despite Seller's diligent
efforts but Seller commences the cure within the thirty (30) day period and thereafter
diligently pursues the cure, the thirty (30) day period shall be extended for as long as is
reasonably required to cure the default (but in no event more than a total of one hundred
twenty (120) days.
25.1.14 Seller's failure to meet the requirements of any one of the Project
Milestones identified in Appendix H.
25.2 Notice of Default. If either Party defaults in its performance of this
Agreement as provided in Section 25. 1, the non-defaulting Party may give notice of the
default in writing to the defaulting Party, specifying in reasonable detail the nature of the
default. If the defaulting Party fails to cure the default within sixty (60) days or any other
cure period specifically identified for the default, the non-defaulting Party may exercise
the specific remedies identified for that default or if no specifics are identified, at its
option, terminate this Agreement and/or pursue its legal or equitable remedies, subject to
any limitation on remedies and damages set forth in this Agreement. The non-defaulting
Party has the right, but not the obligation, to extend the cure period if the non-defaulting
Party determines that the defaulting Party is using all commercially reasonable efforts to
cure the default but is unable to cure the default within an initial sixty (60) day cure
period or the specific cure period for the identified default.
25.3 Material Breaches. The notice and cure provisions in Article 25 do not
apply to defaults identified in this Agreement as Material Breaches. Material Breaches
must be cured as expeditiously as possible following occurrence of the breach and once
cured shall no longer be cause for termination under this Agreement.
PAGE 39
25.4 Delay Damages. If Seller fails to achieve the Operation Date within thirty
(30) days after the Scheduled Operation Date and such failure is not excused by force
majeure or Forced Outage by the Seller or by default or delay of Buyer Delay Liquidated
Damages will be calculated as defined in Section 1.13 of this agreement. Buyer shall
calculate and invoice the Seller and the Seller shall pay Buyer for any Delay Liquidated
Damages accrued during a given calendar month within fifteen (15) days of the receipt of
the Buyer's invoice. The calculation and payment of Delay Damages to the Buyer from
the Seller shall not exceed $690,000.
25.5 Limitations on Seller's Damages. The following limits shall apply to
Seller's liability for damages: (a) Seller's aggregate financial liability to the Buyer in the
event this Agreement is terminated as allowed in Section 26.5.2 shall be limited to any
Performance Assurances the Seller has been required to provide as specified within this
Agreement as of the date of the termination, (b) Seller's aggregate financial liability to
Buyer for Delay Damages shall not exceed the amount specified in Section 25.4,
(c) Seller's aggregate financial liability for Net Energy Shortfall Damages for any single
Contract Year shall not exceed the values as specified in Appendix D. The limitations on
damages set forth in this Section 25.5 shall not apply to damages arising out of either of
the following events:
25.5.1 Willful breach of this Agreement by Seller.
25.5.2 Any claim for indemnification under Article 14.
25.6 Duty to Mitigate Damages. Each Party agrees that it has a duty to mitigate
damages and covenants that it will use commercially reasonable efforts to minimize any
damages it may incur as a result of the other Party's performance or non-performance of
the Agreement.
25.7 Buyer's right to collect damages and any other unpaid amounts. The
Buyer shall have the right to withhold any past due, undisputed payments payable to the
Buyer from any payments payable to the Seller.
ARTICLE 26
TERMINATION
26.1 Termination. Upon execution, this Agreement shall continue in full force
and effect for the Term unless terminated in accordance with this Article.
26.2 Mutual Agreement. The Parties can mutually terminate this Agreement by
a writing signed by both Parties.
26.3 Event of Default. A non-defaulting Party may terminate this Agreement
in accordance with Article 25.
PAGE 40
26.4 Prolonged Force Majeure. A Party not claiming force majeure may
terminate this Agreement in accordance with Section 16.3.
26.5 Right to Terminate.
26.5.1 If the Commission issues a final order either disapproving this
Agreement or approving it with condition(s) or modification(s) unacceptable to the
Party or Parties adversely affected by such modification(s) or condition(s), either Party
has the right to terminate this Agreement by written notice to the other Party either
within ten (10) Business Days after the Commission denies any Petition(s) for
Reconsideration or, if the Commission grants reconsideration, within ten (10) Business
Days after the Commission renders a decision on reconsideration if said decision either
disapproves the Agreement or approves it with condition(s) or modification(s)
unacceptable to either Party. Any such termination under this Section shall be effective
ten (10) Business Days after such notice is given.
26.5.2 Either Party may terminate this Agreement as specified in Article 3
of this Agreement or if after commercially reasonable efforts the Seller is unable to
satisfy the fourth Project Milestone (issuance of power plant notice to proceed). If
termination occurs as a result of a default of the fourth Project Milestone and the Seller is
able to demonstrate to the Buyer's reasonable satisfaction that the uncured default was a
result of unforeseen Facility financing costs or construction costs, the Seller's
Performance Assurance shall be released and no damages to Buyer will be applicable.
26.5.3 If a Party does not give the other Party a notice of termination in
accordance with this Section 26.5 on or before the applicable date specified above, the
affected termination right under this Section 26.5 shall be deemed waived and this
Agreement shall remain in full force and effect in accordance with its terms regardless
of any subsequent Commission order.
26.5.4 Neither Party shall have any liability to the other Party for any
termination under this Section 26.5.
26.5.5 Any termination under this Section shall be effective ten (10)
Business Days after such notice is given.
26.5.6 If termination of this Agreement is due to a default or Material
Breach of this Agreement by the Seller neither the Seller, nor the Facility Lender or
Investor individually or collectively talcing title to the Facility by foreclosure or otherwise
shall make any arrangements with any party other than the Buyer for the sale of electric
energy generated from geothermal energy from this Site and the associated Neal Hot
Springs geothermal reservoir for a period of three (3) years from the date of the
termination. If after termination and within this three (3) year period, the Seller wishes to
resume operations of this Facility and prior to the Facility resuming operations; 1) all
applicable damages due the Buyer as a result of the termination shall have been satisfied,
and 2) a purchased power agreement for the sale of energy from this Facility to the Buyer
shall be completed. The parties shall act in good faith to negotiate a new purchase power
PAGE 41
agreement. The new purchase power agreement shall include terms and conditions
similar to this agreement, except for revisions required to update this agreement to
current industry standards and revisions required to address the termination of the prior
Agreement. Unless mutually agreed to, the energy pricing in this new purchase power
agreement shall be equal to the energy pricing contained within the Agreement.
ARTICLE 27
GOVERNMENTAL AUTHORIZATION
This Agreement is subject to the jurisdiction of those governmental agencies
having control over either Party of this Agreement, including, but not limited to, the
Commission.
ARTICLE 28
REGULATORY APPROVAL
28.1 Within ten (10) Business Days after the Effective Date Buyer shall file this
Agreement with the Commission, seeking Commission Approval.
ARTICLE 29
SUCCESSORS AND ASSIGNS
29.1 Binding Agreement. This Agreement and all of the terms and provisions
of this Agreement shall be binding upon and inure to the benefit of the respective
permitted successors and assigns of the Parties.
29.2 Assignment without Consent. Except as permitted in this Article, neither
Party shall assign this Agreement or any portion of this Agreement, without the prior
written consent of the other Party, which consent shall not be unreasonably withheld,
conditioned or delayed.
29.3 Seller's Consent Not Required. Seller's consent shall not be required for
Buyer to assign this Agreement to an Affiliate of the Buyer, provided that (1) the
assignee has the same or better credit rating from Moody's and S&P as the Buyer and (2)
the assignee's non-credit enhanced unsecured debt (a) has a rating by at least one of the
two rating agencies, and (b) does not have a Credit Rating below BBB- by S&P or below
Baa3 by Moody's, or does not have a Credit Rating of BBB— by S&P accompanied by a
negative watch or Baa3 by Moody's accompanied by a negative watch. If S&P changes
its rating system during the Term, "BBB-" shall be replaced by S&P's lowest investment
grade rating under the new rating system; likewise, if Moody's changes its rating system
during the Term, "Baa3" shall be replaced by Moody's lowest investment grade rating
under the new rating system.
PAGE 42
29.4 Buyer's Consent Not Required. Buyer's consent shall not be required:
29.4.1 For Seller to assign this Agreement for collateral purposes to the
Facility Lender; or
29.4.2 For Seller to assign this Agreement to any Affiliate of the Seller,
provided that the assignee provide the Performance Assurance of the Agreement; or
29.4.3 For Seller to Assign this Agreement to any third party or parties in
connection with a sale of the Facility to such third party or parties, provided that such
third party or parties shall either: (1) have at least three (3) years experience in operating
geothermal electric generating facilities with an installed nameplate capacity of ten
thousand (10,000) kW or greater; or (2) enter into an operating agreement with another
person (who may be the Seller or an Affiliate of the Seller) who has at least three (3)
year's experience in operating geothermal electric generating facilities with an installed
nameplate capacity of ten thousand (10,000) kW or greater; and (3) the third party or
parties shall provide the Performance Assurance of the Agreement.
29.5 Accommodation of Facility Lender or Investor. To facilitate the Seller's
obtaining of Project Financing or to facilitate investments in the Seller, Buyer shall use
commercially reasonable efforts to provide such consents to assignments, certifications,
representations, information, opinions or other documents as may be reasonably
requested by the Seller, the Facility Lender or the Investor in connection with the
financing of or investment in the Facility, provided that in responding to any such
request, the Buyer shall have no obligation to provide any consent, or enter into any
agreement that in Buyer's reasonable opinion significantly adversely affects or expands
any of the Buyer's rights, benefits, risks and/or obligations under this Agreement. Seller
shall reimburse, or shall cause the Facility Lender or the Investor to reimburse, the Buyer
for the incremental direct expenses (including, without limitation, the reasonable fees and
expenses of counsel) incurred by the Buyer in the preparation, negotiation, execution
and/or delivery of any documents requested by the Seller, Facility Lender or Investor,
and provided by the Buyer, pursuant to this Article. The rights of the Facility Lender or
Investor will be set forth in a collateral assignment, estoppel agreement, consent
agreement or similar instrument delivered at the closing of any Facility financing or any
investment and will include the following provisions:
29.5.1 Right to Cure Defaults. Facility Lender or Investor shall have the
right, but not the obligation, to perform any act required to be performed by the Seller
under this Agreement to prevent or cure a default by the Seller, and such act performed
by Facility Lender or Investor shall be as effective to prevent or cure a default as if done
by the Seller. Seller shall, in accordance with Article 32, provide the Buyer with a notice
identifying the agent or trustee of the Facility Lender or the Investor and providing
appropriate contact information for the Facility Lender or Investor. Following receipt of
such notice, Buyer shall provide copies of any notices provided to Seller concerning any
default or Event of Default described in this Agreement to the agent or trustee of the
Facility Lender or Investor specified by the Seller in accordance with Article 32, and the
Buyer will accept a cure performed by the agent or trustee of the Facility Lender or
PAGE 43
Investor and will negotiate in good faith with the agent or trustee of the Facility Lender
and Investor as to the cure period(s) that will be allowed for the Facility Lender or
Investor to cure any default or Event of Default hereunder and the Buyer will accept a
cure performed by the Facility Lender or Investor, so long as the cure is accomplished
within the applicable cure period so agreed to by the Buyer and the Facility Lender or
Investor. In complying with the notice provisions in this Section 29.5.1, Buyer will have
the right to rely on the information provided by the Seller in accordance with Article 32.
29.5.2 Right to Assume Agreement. If the Seller defaults under any
financing or investment documents, the Facility Lender or Investor may (but shall not be
obligated to) assume, or cause its designee to assume, all of the interests, rights, and
obligations of the Seller thereafter arising under this Agreement. Notwithstanding any
such assumption, the Seller shall not be released or discharged from and shall remain
liable for any and all obligations to the Buyer arising or accruing under this Agreement.
29.5.3 No Obligation to Perform. Buyer agrees that neither the Facility
Lender nor the Investor shall be obligated to perform any obligation or be deemed to
incur any liability or obligation provided in this Agreement on the part of the Seller or
shall have any obligation or liability to the Buyer with respect to this Agreement except
to the extent the Facility Lender or Investor has assumed the obligations of the Seller
under this Agreement pursuant to this Article; provided that the Buyer shall nevertheless
be entitled to exercise all of its rights under this Agreement against the Seller in the event
that the Seller, Facility Lender or Investor fails to perform the Seller's obligations under
this Agreement.
29.5.4 Notice of Facility Lender or Investor Action. Within ten (10)
Business Days following the Seller's receipt of each written notice from a Facility Lender
or an Investor of a default, or of Facility Lender's or Investor's intent to exercise any
remedies, under the Financing Documents or any investment agreement, Seller shall
deliver a copy of such notice to the Buyer.
29.5.5 If the Facility Lender or Investor directly or indirectly, takes
possession of or title to the Facility (including possession by a receiver or title by
foreclosure or deed in lieu of foreclosure), then the Facility Lender or Investor shall
assume all of the Seller's obligations under this Agreement. Provided that the Facility
Lender or Investor shall have no personal liability for any monetary obligations of Seller
under this Agreement which are due and owing to Buyer as of the assumption date.
29.5.6 If the Facility Lender or Investor elect to sell or transfer the
Facility (after directly or indirectly taking possession of, or title to, the Facility) or if the
sale of the Facility occurs through the actions of the Facility Lender or Investor
(including, a foreclosure sale where a third party is the buyer, or otherwise), then, as a
condition of such sale or transfer, the Facility Lender or Investor shall cause the buyer or
transferee of the Facility to assume all of Seller's obligations arising under this
Agreement from and after the date of such sale or transfer.
PAGE 44
29.6 Subcontracting. Seller may subcontract its duties or obligations under this
Agreement without the prior written consent of the Buyer, provided, that no such
subcontract shall relieve the Seller of any of its duties or obligations under this
Agreement.
29.7 Right of First Offer upon Sale of Facility Assets, increase of existing
Facility Name1ate rating, or addition of new generation capacity.
29.7.1 Facility Assets. If, at any time during the Term, Seller intends to
sell the assets comprising all or substantially all of the Facility (the "Facility Assets") to a
person or entity that is not an Affiliate of Seller, Seller shall first offer the Facility Assets
to Buyer. Seller's offer to the Buyer shall set forth, in writing and in reasonable detail,
substantially similar terms and conditions of the offer being proposed by the Seller to the
other person or entity. Seller shall promptly answer any questions that Buyer may have
concerning the offered terms and conditions and shall meet with Buyer to discuss the
offer.
29.7.2 Buyer's Rejection of Offer: Revival of Offer. If Buyer does not
provide notice of its intent to accept the offered terms and conditions within thirty (30)
days after receiving each of the Seller's offers made under 29.7.1, Seller may in its sole
discretion enter into an agreement to sell the Facility Assets to a third party in compliance
with the requirements of this Article 29 and on terms and conditions satisfactory to Seller
in its sole discretion. Seller may elect not to proceed with the sale of the Facility Assets.
29.7.3 Buyer's Acceptance of Offer. If Buyer provides notice of its intent
to accept the offer made by Seller under this Section, the Parties shall negotiate in good
faith to enter into a definitive sales agreement that incorporates the terms and conditions
of Seller's offer. The definitive agreement shall be subject to each Party's management
and regulatory approvals. If within thirty (30) days of Buyer's acceptance of the offer, a
written term sheet setting forth the major terms of the definitive sales agreement,
including a timeline to complete negotiations of the definitive sales agreement, has not
been executed by an officer of the Buyer and Seller, then either Party may terminate the
negotiations without further obligation to the other Party.
29.7.4 Limit on Right of First Offer. The right of first offer set forth in
this Section shall apply only if Seller sells all or substantially all of the assets comprising
the Facility in an asset sale to a third party. It shall not apply to changes in the
membership of Seller or any other reorganization, change of control or other transaction
directly or indirectly affecting Seller or an Affiliate of Seller.
29.7.5 Right of First Offer of additional geothermal generation. If at the
time of development of this Facility or at any future date, the Seller proposes to increase
the nameplate rating of this Facility or add additional geothermal electrical generation at
this Site or in close proximity to this Site, the Seller shall first offer the additional
geothermal electrical generation to the Buyer as an amendment to this Agreement, as a
separately negotiated purchase power agreement, or whole or partial ownership of the
Facility or the additional generation facilities. This offer from the Seller shall include but
PAGE 45
not be limited to proposed capacity, energy pricing, contract term, online date and other
information that will enable the Buyer to be able to evaluate the Buyer's interest in this
additional geothermal electrical generation. Upon receipt of the Seller's offer (containing
adequate information) the Buyer shall have sixty (60) days to respond to Seller's offer of
the Buyer's intent to continue negotiations for this additional geothermal electrical
generation. If the Buyer provides notice that the Buyer has no current intention to
continue negotiations the Seller may pursue other opportunities with other parties for the
development and sale of this additional geothermal electrical generation. If the Buyer
provides notice to the Seller of the desire to continue negotiations the Buyer and Seller
shall commence good faith negotiations of an amendment to this Agreement and/or a
separate agreement. If after one hundred and twenty (120) days of good faith
negotiations, an agreement is not completed and/or appears to not be imminent, the Seller
may provide notice to the Buyer of their intention to pursue opportunities with other
parties. By mutual consent, this one hundred twenty (120) day negotiation period may be
extended.
ARTICLE 30
MODIFICATION
No modification to this Agreement shall be valid unless it is in writing and signed
by both Parties and subsequently approved by the Commission.
ARTICLE 31
TAXES
Each Party shall pay before delinquency all taxes and other governmental charges
which, if failed to be paid when due, could result in a lien upon the Facility or the
Interconnection Facilities.
ARTICLE 32
NOTICES
All written notices under this Agreement shall be directed as follows and shall be
considered delivered when faxed, c-mailed and confirmed with deposit in the U.S. Mall,
first-class, postage prepaid, as follows:
To Seller: USG Oregon LLC
Attn: Manager
1505 Tyrell Lane
Boise, ID 83706
Phone: [phone]
Fax: [phone]
Email: dkunzusgeotherma1.com
PAGE 46
with a copy to: USG Oregon LLC
Attn: CFO
1505 Tyrell Lane
Boise, ID 83706
Phone: [phone]
Fax: [phone]
Email: [e-mail]
Facility Lender or Investor: To be identified by the Seller when applicable. The
Seller shall be limited to identify only one Facility
Lender or Investor.
To Buyer: Idaho Power Company
Attn: Senior Vice President, Power Supply
P.O. Box 70
Boise, ID 83707
Fax: [phone]
Email: [e-mail]
with a copy to: Idaho Power Company
Attn: Legal Department
P.O. Box 70
Boise, ID 83707
Fax: [phone]
Email: bkline®idahopower.com
By giving notice to the other Party, either Party may from time to time change the
address (es) to which notices or copies are to be sent to it under this Agreement.
ARTICLE 33
ADDITIONAL TERMS AND CONDITIONS
This Agreement includes the following appendices, which are attached hereto and
included by reference:
Appendix A Contract Prices
Appendix B Facility Description
Appendix C Sample Form of Seller Guaranty
Appendix D Net Energy Shortfall Price and Annual Cap
Appendix E Engineering Certificates
Appendix F Communications
Appendix G One-Line Diagram
Appendix H Project Milestones
PAGE 47
ARTICLE 34
SEVERABILITY
The invalidity or unenforceability of any term or provision of this Agreement
shall not affect the validity or enforceability of any other terms or provisions and this
Agreement shall be construed in all other respects as if the invalid or unenforceable term
or provision were omitted, unless the deletion of such provision or provisions would
result in such a material change so as to cause completion of the transactions
contemplated herein to be unreasonable.
ARTICLE 35
CONFIDENTIAL BUSINESS INFORMATION
35.1 Definition. The following constitutes "Confidential Business
Information," whether oral or written: (1) Parties' proposals and negotiations before the
Effective Date concerning this Agreement, and (2) information that a Party stamps or
otherwise identifies as "confidential" or "proprietary" before disclosing it to the other
Party. Notwithstanding the foregoing, "Confidential Business Information" does not
include (A) information that was publicly available at the time of the disclosure thereof
by one Party to the other, other than as a result of a disclosure by the receiving Party in
breach of this Article; (B) information that becomes publicly available through no fault of
the receiving Party after the time of the disclosure by the disclosing Party to the receiving
Party; (C) information that was rightfully in the possession of the receiving Party
(without confidential or proprietary restriction) at the time of disclosure or that becomes
available to the receiving Party from a source not subject to any restriction against
disclosing such information to the receiving Party; and (D) information that the receiving
Party independently developed without a violation of this Agreement. The Confidential
Business Information specified in item (1) above shall be considered the Confidential
Business Information of both Seller and Buyer and, therefore, exceptions (C) and (D)
above shall not apply to such information.
35.2 Duty to Maintain Confidentiality. Each Party agrees not to disclose
Confidential Business Information of the other Party to any other person (other than its
Affiliates, counsel, consultants, lenders, prospective lenders, purchasers, investors,
contractors constructing or providing services to the Facility (including but not limited to
turbine suppliers), employees, officers and directors who agree to be bound by the
provisions of this Article), without the prior written consent of the other Party, provided
that either Party may disclose Confidential Business Information if and to the extent such
disclosure is required (1) by any Requirements of Law, (2) in order for the Buyer to
receive regulatory recovery of expenses related to the Agreement, (3) pursuant to an
order of a court or regulatory agency or (4) in order to enforce this Agreement or to seek
approval of this Agreement. In addition, Seller may include information concerning the
terms or conditions of this Agreement in financial statements to the extent that such
information is required to be included in financial statements prepared with respect to the
PAGE 48
Facility, Seller or any Affiliate of the Seller in accordance with generally accepted
accounting principles consistently applied. In the event a Party is required by
Requirements of Law or by a court or regulatory agency to disclose Confidential
Business Information, such Party shall to the extent possible notify the other Party at least
three (3) Business Days in advance of such disclosure and the other Party may seek an
appropriate protective order or waive compliance with the confidentiality terms of this
Agreement. In that event, the Party required by Requirements of Law or by a court or
regulatory agency to disclose Confidential Business Information will cooperate fully with
the other Party in seeking a protective order or other assurance that confidential treatment
will be accorded to the Confidential Business Information.
35.3 Irreparable Injury: Remedies. Each Party agrees that violation of the
terms of this Article constitutes irreparable harm to the other, and that the harmed Party
may seek any and all remedies available to it at law or in equity, including but not limited
to injunctive relief.
ARTICLE 36
REPRESENTATIONS AND WARRANTIES
36.1 Seller's Representations, Warranties and Covenants. Seller hereby
represents and warrants as follows:
36.1.1 Seller is a Delaware Limited Liability company, organized and
existing under the laws of the State of Delaware with a principal place of business at
1505 Tyrell Lane, Boise, ID 83706. Seller is qualified to do business in each other
jurisdiction where the failure to so qualify would have a material adverse effect on the
business or financial condition of the Seller; and the Seller has all requisite power and
authority to conduct its business, to own its properties, and to execute, deliver, and
perform its obligations under this Agreement.
36.1.2 The execution, delivery, and performance of its obligations under
this Agreement by the Seller have been duly authorized by all necessary business entity
action(s), and do not and will not:
36.1.2.1 Require any consent or approval by any governing body
of the Seller, other than that which has been obtained and is in full force
and effect (evidence of which shall be delivered to the Buyer upon its
request);
36.1.2.2 violate any provision of law, rule, regulation, order, writ,
judgment, injunction, decree, determination, or award currently in effect
having applicability to the Seller or violate any provision in any formation
documents of the Seller, the violation of which could have a material
adverse effect on the ability of the Seller to perform its obligations under
this Agreement;
PAGE 49
36.1.2.3 result in a breach or constitute a default under the
Seller's formation documents or bylaws, or under any agreement relating
to the management or affairs of the Seller or any indenture or loan or
credit agreement, or any other agreement, lease, or instrument to which the
Seller is a party or by which the Seller or its properties or assets may be
bound or affected, the breach or default of which could reasonably be
expected to have a material adverse effect on the ability of the Seller to
perform its obligations under this Agreement; or
36.1.2.4 result in, or require the creation or imposition of any
mortgage, deed of trust, pledge, lien, security interest, or other charge or
encumbrance of any nature (other than as may be contemplated by this
Agreement) upon or with respect to any of the assets or properties of the
Seller now owned or hereafter acquired, the creation or imposition of
which could reasonably be expected to have a material adverse effect on
the ability of the Seller to perform its obligations under this Agreement.
36.1.3 This Agreement is a valid and binding obligation of the Seller.
36.1.4 The execution and performance of this Agreement will not conflict
with or constitute a breach or default under any contract or agreement of any kind to
which the Seller is a party or any judgment, order, statute, or regulation that is applicable
to the Seller or the Facility.
36.2 Seller's Disclaimer of Certain Representations and Warranties.
NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT,
36.2.1 SELLER DISCLAIMS ALL WARRANTIES OF
MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE WITH
RESPECT TO THE SALE OF TEST ENERGY, NET ENERGY AND
ENVIRONMENTAL ATTRIBUTES.
36.2.2 SELLER MAKES NO REPRESENTATION OR WARRANTY,
EITHER EXPRESS OR IMPLIED, REGARDING THE CURRENT OR FUTURE
EXISTENCE OF ANY ENVIRONMENTAL ATTRIBUTES UNDER THIS
AGREEMENT OR OTHERWISE OR THEIR CHARACTERIZATION OR
TREATMENT UNDER APPLICABLE LAW OR OTHERWISE.
36.3 Buyer's Representations. Warranties and Covenants. Buyer hereby
represents and warrants as follows:
36.3.1 Buyer is a corporation duly organized, validly existing and in good
standing under the laws of the State of Idaho and is qualified in each other jurisdiction
where the failure to so qualify would have a material adverse effect upon the business or
financial condition of the Buyer; and the Buyer has all requisite power and authority to
conduct its business, to own its properties, and to execute, deliver, and perform its
obligations under this Agreement.
PAGE 50
36.3.2 The execution, delivery, and performance of its obligations under
this Agreement by the Buyer has been duly authorized by all necessary corporate action.
36.3.2.1 violate any provision of law, rule, regulation, order, writ,
judgment, injunction, decree, determination, or award currently in effect
having applicability to the Buyer or violate any provision in any corporate
documents of the Buyer, the violation of which could have a material
adverse effect on the ability of the Buyer to perform its obligations under
this Agreement;
36.3 .2.2 result in a breach or constitute a default under the
Buyer's corporate charter or bylaws, or under any agreement relating to
the management or affairs of the Buyer, or any indenture or loan or credit
agreement, or any other agreement, lease, or instrument to which the
Buyer is a party or by which the Buyer or its properties or assets may be
bound or affected, the breach or default of which could reasonably be
expected to have a material adverse effect on the ability of the Buyer to
perform its obligations under this Agreement; or
36.3.2.3 result in, or require the creation or imposition of any
mortgage, deed of trust, pledge, lien, security interest, or other charge or
encumbrance of any nature (other than as may be contemplated by this
Agreement) upon or with respect to any of the assets or properties of the
Buyer now owned or hereafter acquired, the creation or imposition of
which could reasonably be expected to have a material adverse effect on
the ability of the Buyer to perform its obligations under this Agreement.
36.3.3 Subject to Commission Approval, this Agreement is a valid and
binding obligation of the Buyer.
36.3.4 The execution and performance of this Agreement will not conflict
with or constitute a breach or default under any contract or agreement of any kind to
which the Buyer is a party or any judgment, order, statute, or regulation that is applicable
to the Buyer.
36.3.5 Except for Commission Approval, to the best knowledge of the
Buyer, all approvals, authorizations, consents, or other action required by any
Governmental Authority to authorize the Buyer's execution, delivery and performance of
this Agreement have been duly obtained and are in full force and effect.
ARTICLE 37
ENTIRE AGREEMENT
PAGE 51
This Agreement constitutes the entire Agreement of the Parties concerning the
subject matter of this Agreement and supersedes all prior or contemporaneous oral or
written agreements between the Parties concerning the subject matter of this Agreement.
No oral or written representation, warranty, course of dealing or trade usage not
contained or referenced herein shall be binding on either Party.
ARTICLE 38
COUNTERPARTS
This Agreement may be executed by the Parties in two or more separate
counterparts (including by facsimile transmission), each of which shall be deemed an
original, and all of said counterparts taken together shall be deemed to constitute one and
the same instrument.
ARTICLE 39
CAPTIONS
The captions for Articles and Sections contained in this Agreement are for
convenience and reference only and in no way define, describe, extend or limit the scope
of this Agreement or the intent of any provision contained herein.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed
in their respective names on the dates set forth below:
USG Oregon LLC IDAHO POWER COMPANY
By By
Daniel Kunz Lisa A. Grow
Printed Name Printed Name
Manager - USG Oregon LLC Senior Vice President, Power Supply
I2111/oo' l_. I
Date Date
PAGE 52
APPENDIX A
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
CONTRACT PRICES ($/MWH)
Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2012 96.00 96.00 70.37 70.37 70.37 96.00 115.20 115.20 96.00 96.00 115.20 115.20
2013 99.00 99.00 72.57 72.57 72.57 99.00 118.80 118.80 99.00 99.00 118.80 118.80
2014 102.78 102.78 75.34 75.34 75.34 102.78 123.34 123.34 102.78 102.78 123.34 123.34
2015 106.79 106.79 78.28 78.28 78.28 106.79 128.15 128.15 106.79 106.79 128.15 128.15
2016 109.27 109.27 80.09 80.09 80.09 109.27 131.12 131.12 109.27 109.27 131.12 131.12
2017 111.83 111.83 81.97 81.97 81.97 111.83 134.20 134.20 111.83 111.83 134.20 134.20
2018 114.49 114.49 83.92 83.92 83.92 114.49 137.38 137.38 114.49 114.49 137.38 137.38
2019 11645 11645 8536 8536 8536 11645 13974 13974 11645 11645 13974 13974
APPENDIX A - PAGE 1 OF 2
2020 118.46 118.46 86.83 86.83 86.83 118.46 142.15 142.15 118.46 118.46 142.15 142.15
2021 120.52 120.52 88.34 88.34 88.34 120.52 144.62 144.62 120.52 120.52 144.62 144.62
2022 122.63 122.63 89.89 89.89 89.89 122.63 147.16 147.16 122.63 122.63 147.16 147.16
2023 124.37 124.37 91.16 91.16 91.16 124.37 149.24 149.24 124.37 124.37 149.24 149.24
2024 126.13 126.13 92.46 92.46 92.46 126.13 151.36 151.36 126.13 126.13 151.36 151.36
2025 127.94 127.94 93.78 93.78 93.78 127.94 153.52 153.52 127.94 127.94 153.52 153.52
2026 129.77 129.77 95.12 95.12 95.12 129.77 155.73 155.73 129.77 129.77 155.73 155.73
2027 131.65 131.65 96.50 96.50 96.50 131.65 157.98 157.98 131.65 131.65 157.98 157.98
2028 132.92 132.92 97.43 97.43 97.43 132.92 159.51 159.51 132.92 132.92 159.51 159.51
2029 134.21 134.21 98.38 98.38 98.38 134.21 161.05 161.05 134.21 134.21 161.05 161.05
2030 135.52 135.52 99.33 99.33 99.33 135.52 162.62 162.62 135.52 135.52 162.62 162.62
2031 136.84 136.84 100.30 100.30 100.30 136.84 164.21 164.21 136.84 136.84 164.21 164.21
2032 138.18 138.18 101.29 101.29 101.29 138.18 165.82 165.82 138.18 138.18 165.82 165.82
2033 139.54 139.54 102.28 102.28 102.28 139.54 167.45 167.45 139.54 139.54 167.45 167.45
2034 140.92 140.92 103.29 103.29 103.29 140.92 169.10 169.10 140.92 140.92 169.10 169.10
2035 142.31 142.31 104.32 104.32 104.32 142.31 170.78 170.78 142.31 142.31 170.78 170.78
2036 143.73 143.73 105.35 105.35 105.35 143.73 172.47 172.47 143.73 143.73 172.47 172.47
APPENDIX A - PAGE 2 OF 2
APPENDIX B
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
FACILITY DESCRIPTION
B-i DESCRIPTION OF FACILITY
The Facility is the Neal Hot Springs Unit #1 geothermal power plant.
The Buyer shall update this Description of Facility to be consistent with the Buyers
Facility description contained within the Buyers notice to proceed to the primary
contractor responsible for the construction of the Neal Hot Springs Geothermal Power
Plant within sixty (60) days of the date the Seller issues this notice to proceed. The
revised Description of Facility must include specific generation and geothermal plant
information. Including but not limited to generation unit nameplate ratings, VAR
capability, approximated geothermal production and injection well configuration,
geothermal fluid delivery and handling system and any other information deemed to be
appropriate to specifically identify the Facility subject to the terms and conditions of this
Agreement.
As of the Effective Date of this Agreement the Description of the Facility is as follows:
Summary Description of Facility:
The Facility will be comprised of two or three modular power plant units
provided by Turbine Air Systems. The units will be air cooled. Geothermal
fluid will be produced from two or more production wells and injected back via
two or more injection wells.
Expected Annual Average Capacity from the Facility:
The facility is expected to provide between 14,000 - 25,000 kW annual
average capacity, excluding Forced and Scheduled Outages. This will be
updated to a single annual average design capacity number as part of the
requirements of the fourth Project Milestone of Appendix H and will be used in
the Annual Output Forecast (Section 8.5.4).
APPENDEXB -PAGE 1 OF 2
B-2 LOCATION OF FACILITY
The Neal Hot Springs geothermal resource is located in north-central Malheur County, Oregon,
12 miles west-northwest of the town of Vale, Figure B-i. The project encompasses
approximately 6,300 acres of private land leased from JR Land and Livestock Inc. and Cyprus
Gold, all located in the Bully Creek Drainage. Equipment and wells will be located in Sections
5, 8, and 9, Township 18 South, Range 43 East, Willamette Meridian
Access is provided by state and county road systems to the project site. Travel west on State
Highway 20 & 26 from Ontario Oregon to Vale Oregon. On the west edge of Vale turn right on
Graham road, and then west 5.2 miles to the Bully Creek Road. Travel north and west on Bully
Creek road approximately 8 miles to the project site.
Figure B-i: Location of Neal Hot Springs
To To John Day
/
NEAL$OT \\
SPRIMp \PAYErrE
PROJE
K ( L 0 To 8,M OREGON
V
NY$S4
APPENDEX B - PAGE 2 OF 2
APPENDIX C
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
SAMPLE FORM OF SELLER GUARANTY
($ XXX, 000)
,20_
Idaho Power Company
P0 Box 70
Boise, Idaho 83707
Fax:
Ladies and Gentlemen:
The __(the "Guarantor"), a corporation duly organized under the
laws of the State of is the of; a limited liability company duly
organized under the laws of the State of "Company"). Guarantor understands
and acknowledges that Idaho Power Company, an Idaho corporation ("Buyer"), has entered into
that certain Power Purchase Agreement between the Company and Buyer dated as of the
effective date hereof (the "Power Purchase Agreement"). For value received, and under the
provisions of the Power Purchase Agreement, Guarantor hereby unconditionally and, subject to
the provisions of the fifth and sixth paragraphs hereof, irrevocably guarantees the prompt and
complete payment as and when due, whether by acceleration or otherwise, of the payment
obligations, whether now in existence or hereafter arising, under the Power Purchase Agreement
(which guaranty, along with the other terms and conditions set forth herein, is hereafter referred
to as the "Guaranty"). This Guaranty is one of payment and not of collection. Capitalized terms
used but not defined in this Guaranty have the meaning given to them in the Power Purchase
Agreement.
The maximum aggregate liability of the Guarantor in respect of amounts claimed by
Buyer under or pursuant to this Guaranty shall at no time exceed an amount equal to
dollars ($); provided, however, that Guarantor also
APPENDIX C - PAGE 1 OF 3
guaranties payment in full (that is, without limitation as to amount) of any reasonable out-of-
pocket legal fees, costs and/or expenses, whether at trial, on appeal or in any arbitration, by
Buyer in connection with prevailing in enforcing the terms of this Guaranty.
The Guarantor hereby waives notice of acceptance of this Guaranty and notice of any
obligation or liability to which it may apply, and waives presentment, demand for payment,
protest, notice of dishonor or non-payment of any such obligation or liability, suit or the taking
of other action by Buyer against, and any other notice to, the Company, the Guarantor or others.
Buyer may at any time and from time to time without notice to or consent of the
Guarantor and without impairing or releasing the obligations of the Guarantor hereunder: (1)
agree with the Company to make any change in the terms of any obligation or liability of the
Company to Buyer, including any modification or amendment to the Power Purchase Sales
Agreement, (2) take or fail to take any action of any kind in respect of any security for any
obligation or liability of the Company to Buyer, (3) exercise or refrain from exercising any rights
against the Company or others, (4) fail to first take action against the Company for amounts due
under the Power Purchase Agreement, and/or (5) compromise or subordinate any obligation or
liability of the Company to Buyer including any security therefore. Any other suretyship
defenses are hereby waived by the Guarantor.
This Guaranty shall terminate on the earlier to occur of (i) the substitution of an alternate
form of Seller Performance Assurance in accordance with the Power Purchase Agreement; and
(ii) the later of (A) the termination or expiration of the Power Purchase Agreement and (B) the
satisfaction of all obligations of the Company under the Power Purchase Agreement.
Notwithstanding the foregoing, the Guarantor further agrees that if at any time payment, or any
part thereof, of any of the obligations guaranteed hereunder, is rescinded, is demanded to be
returned and/or must otherwise be restored or returned by Buyer in connection with the
bankruptcy, insolvency, dissolution, reorganization or similar proceeding of the Company, this
Guaranty shall continue to be effective or be reinstated as the case may be; provided that this
Guaranty may not be reinstated for any reason after its termination under clause (i) of this
paragraph.
Guarantor may not assign its rights nor delegate its obligations under this Guaranty, in
whole or in part, without prior written consent of Buyer, and any purported assignment or
delegation absent such consent is void, except for an assignment and delegation of all of the
Guarantor's rights and obligations hereunder in whatever form the Guarantor determines may be
appropriate to a partnership, corporation, trust or other organization in whatever form that
succeeds to all or substantially all of the Guarantor's assets and business and that assumes such
obligations by contract, operation of law or otherwise. Upon any such delegation and
assumption of obligations, the Guarantor shall be relieved of and fully discharged from all
obligations hereunder, whether such obligations arose before or after such delegation and
assumption.
In the event any payment owing to Buyer under the Power Purchase Agreement or under
this Guaranty is not promptly and completely paid as and when due, any indebtedness of
Company to Guarantor and any payment or distribution right held by Guarantor against the
Company shall be subordinated to the due and unpaid indebtedness to Buyer until paid in full.
Guarantor shall have no right of subrogation until the Company's due and unpaid indebtedness to
Buyer is paid in full.
APPENDIX C - PAGE 2 OF 3
This Guaranty constitutes the entire agreement and supersedes all prior agreements and
understandings, both written and oral, between Guarantor and Buyer with respect to the subject
matter hereof. This Guaranty may not be modified except pursuant to a written instrument
signed by Buyer and Guarantor. The execution, delivery and performance of this Guaranty have
been duly authorized by all requisite corporate action on the part of the Guarantor. The
provisions of this Guaranty are severable, and if any clause or provision shall be held invalid or
unenforceable in whole or in part, then such invalidity or unenforceability shall affect only such
clause or provision, or part thereof, and shall not affect the validity or enforceability of any other
clause or provision.
THIS GUARANTY SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF WITHOUT
GIVING EFFECT TO PRINCIPLES OF CONFLICTS OF LAW. GUARANTOR AGREES TO
THE EXCLUSIVE JURISDICTION OF COURTS LOCATED IN THE STATE OF____
UNITED STATES OF AMERICA, OVER ANY DISPUTES ARISING UNDER OR
RELATING TO THIS GUARANTY.
Very truly yours,
LIM
Authorized Officer
APPENDIX C- PAGE 30F3
APPENDIX D
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
NET ENERGY SHORTFALL PRICE AND ANNUAL CAP
Net Energy Shortfall Price The Net Energy Shortfall Price shall be (1) the mathematical
average of the individual Contract Month's monthly Market Energy Cost values of the applicable
Annual Guaranteed Output period or (2) one hundred fifty percent (1501/16) of the Contract Price
specified in Appendix A for the month of June for the Calendar Year which corresponds to that
of the first month of the Annual Guaranteed Output period, whichever is less, minus the Contract
Price as specified in Appendix A for the month of June for the Calendar Year which corresponds
to that of the first month of the Annual Guaranteed Output period. If this Net Energy Shortfall
Price calculation results in a value less than zero (0) then the result will be zero (0).
Example 1
A Net Energy Shortfall occurs for the Contract Year of March 1, 2016 through February
28,2017:
Contract Price: 109.27 nulls/kWh
Mathematical average of the Contract Month's monthly Market Energy Cost
values for the period of March 1, 2016 through February 28, 2017:
40.00 mills/kWh
150% of the Contract Price: 109.27 * 150% = 163.91 mills/kWh
Net Energy Shortfall Price calculation
The average Market Energy Cost (40.00) is less than 150% of the Annual
Rate (163.91). Therefore the Net Energy Shortfall Price calculation is
equal to:
Market Energy Cost (40.00) minus Contract Price (109.27) = -69.27
APPENDIX D - PAGE 1 OF 3
As the calculation results in a value less than 0, (-69.27) the Net Energy
Shortfall Price equals 0.00 mills/kWh.
Example 2
A Net Energy Shortfall occurs for the Contract Year of March 1, 2016 through February
28,2017:
Contract Price: 109.27 mills/kWh
.
Mathematical average of the Contract Month's monthly Market Energy Cost
values for the period of March 1, 2016 through February 28, 2017:
125.00 mills/kWh
150% of the Contract Price: 109.27 * 150% = 163.91 mills/kWh
Net Energy Shortfall Price calculation
The average Market Energy Cost (125.00) is less than 150% of the Annual
Rate (163.91). Therefore the Net Energy Shortfall Price calculation is
equal to:
Market Energy Cost (125.00) minus Contract Price (109.27) = 15.73
Net Energy Shortfall Price equals 15.73 mills/kWh
Example 3
A Net Energy Shortfall occurs for the Contract Year of March 1, 2016 through February
28,2017:
Contract Price: 109.27 mills/kWh
Mathematical average of the Contract Month's monthly Market Energy Cost
values for the period of March 1, 2016 through February 28,2017:
180.00 mills/kWh
1501/6 of the Contract Price: 109.27 * 150% = 163.91 mills/kWh
Net Energy Shortfall Price calculation
APPENDIX D - PAGE 2 OF 3
The average Market Energy Cost (180.00) is greater than 150% of the
AnnualRate (163.91). Therefore the Net Energy Shortfall Price calculation
is equal to:
150% of Contract Price (163.91) minus Contract Price (109.27) = 54.64
Net Energy Shortfall Price equals 54.64 mills/kWh
Net Energy Shortfall Dama2es Cap
Contract
Year
Net Energy
Shortfall Damages Cap
- Contract
Year
Net Energy
Shortfall
Damages Cap
1 $0.00 14 $573,073
2 $0.00 - 15 $590,265
3 $414,000 - 16 $607,973
4 $426,420 = 17 $626,212
5 $439,213 18 $644,998
6 $452,389 - 19 $664,349
7 $465,961 - 20 $684,279
8 $479,939 21 $690,000
9 $494,338 - 22 $690,000
10 $509,168 23 $690,000
11 $524,443 24 $690,000
12 $540,176 - 25 See Note I
13 $556,382 1
Note I - The Net Energy Shortfall Damages Cap in the final year shall be $690,000 prorated to
the number of months in the Annual Output Forecast
APPENDIX D- PAGE 3OF3
APPENDIX E
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
ENGINEERING CERTIFICATIONS
Continued on next page
APPENDIX E - PAGE 1 OF 7
ENGINEER'S CERTIFICATION
KI
OPERATIONS & MAINTENANCE POLICY
The undersigned , on behalf of himself and
hereinafter collectively referred to as
"Engineer," hereby states and certifies to the Seller as follows:
1.That Engineer is a Licensed Professional Engineer in good standing.
2.That Engineer has reviewed the Power Purchase Agreement, hereinafter
"Agreement," between Idaho Power as Buyer, and as Seller, dated
3.That the geothermal power production Facility which is the subject of the
Agreement and this statement is identified as the and is
hereinafter referred to as the "Facility."
4.That the Facility is located in Section , Range________
County, Oregon.
5.That Engineer recognizes that the Agreement provides for the Facility to furnish
electrical energy to Idaho Power for a twenty five (25) year period.
6.That Engineer has substantial experience in the design, construction and operation
of electric power plants of the same type as this Facility.
7.The Engineer will identify any material economic relationship to the Design
Engineer of this Facility.
APPENDIX E - PAGE 2 OF 7
8.That Engineer has reviewed and/or supervised the review of the operation and
maintenance policies ("O&M") for this Facility and it is his professional opinion that, provided
said Facility has been designed and built to appropriate standards, adherence to said O&M
policies will result in the Facility's producing at or near the design electrical output, efficiency
and plant factor for a twenty five (25) year period.
9.That Engineer recognizes that Idaho Power, in accordance with Article 3 and 4 of
the Agreement, is relying on Engineer's representations and opinions contained in this Statement.
10.That Engineer certifies that the above statements are complete, true and accurate
to the best of his knowledge and therefore sets his hand and seal below.
(P.E. Stamp)
Date
APPENDIX E - PAGE 3 OF 7
ENGINEER'S CERTIFICATION
ONGOING OPERATIONS AND MAINTENANCE
The undersigned , on behalf of himself
and hereinafter collectively referred to as
"Engineer," hereby states and certifies to the Seller as follows:
1.That Engineer is a Licensed Professional Engineer in good standing.
2.That Engineer has reviewed the Power Purchase Agreement, hereinafter
"Agreement," between Idaho Power as Buyer, and as Seller,
dated
3.That the geothermal power production Facility which is the subject of the
Agreement and this statement is identified as the
and is hereinafter referred to as the "Facility."
4.That the Facility is located in Section Township , Range_______
County, Oregon.
5.That Engineer recognizes that the Agreement provides for the Facility to furnish
electrical energy to Idaho Power for a twenty five (25) year period.
6.That Engineer has substantial experience in the design, construction and operation
of electric power plants of the same type as this Facility.
7.The Engineer shall identify any material economic relationship to the Design
Engineer of this Facility.
8.That Engineer has made a physical inspection of said Facility, its operations and
maintenance records since the last previous certified inspection. It is Engineer's professional
opinion, based on the Facility's appearance, that its ongoing O&M has been substantially in
APPENDIX E - PAGE 4 OF 7
accordance with said O&M Policy; that it is in reasonably good operating condition; and that if
adherence to said O&M Policy continues, the Facility will continue producing at or near its
design electrical output, efficiency and plant factor, within the limits of the geothermal reservoir
capability of the Facility for the remaining ______years of the Agreement
9.That Engineer recognizes that Idaho Power, in accordance with Article 3 and 4 of
the Agreement, is relying on Engineer's representations and opinions contained in this
Statement.
10.That Engineer certifies that the above statements are complete, true and accurate
to the best of his knowledge and therefore sets his hand and seal below.
LO
(P.E. Stamp)
Date
APPENDIX E - PAGE 5 OF 7
ENGINEER'S CERTIFICATION
OF
DESIGN & CONSTRUCTION ADEQUACY
The undersigned , on behalf of himself and
hereinafter collectively referred to as
"Engineer", hereby states and certifies to Idaho Power as follows:
1.That Engineer is a Licensed Professional Engineer in good standing.
2.That Engineer has reviewed the Power Purchase Agreement, hereinafter
"Agreement," between Idaho Power as Buyer, and as Seller, dated
3.That the geothermal power production Facility which is the subject of the
Agreement and this statement is identified as the and
is hereinafter referred to as the "Facility."
4.That the Facility is located in Section Range
County, Oregon.
5.That Engineer recognizes that the Agreement provides for the Facility to furnish
electrical energy to Idaho Power for a twenty five (25) year period.
6.That Engineer has substantial experience in the design, construction and operation
of electric power plants of the same type as this Facility.
7.The Engineer shall identify any material economic relationship to the Design
Engineer of this Facility and has made the analysis of the plans and specifications independently.
8.That Engineer has reviewed the engineering design and construction of the
Facility, including the civil work, electrical work, generating equipment, prime mover
APPENDIX E - PAGE 6 OF 7
conveyance system, Seller furnished Interconnection Facilities and other Facility facilities and
equipment..
9 That the Facility has been constructed in accordance with said plans and
specifications, all applicable codes and consistent with Good Utility Practices as that term is
described in the Agreement.
10.That the design and construction of the Facility is such that with reasonable and
prudent operation and maintenance practices by Seller, the Facility is capable of performing in
accordance with the terms of the Agreement and with Prudent Electrical Practices for a
year period
11.That Engineer recognizes that Idaho Power, in accordance with Article 3 and 4 of
the Agreement, in interconnecting the Facility with its system, is relying on Engineer's
representations and opinions contained in this Statement.
12.That Engineer certifies that the above statements are complete, true and accurate
to the best of his knowledge and therefore sets his hand and seal below.
(P.E. Stamp)
Date
APPENDIX E - PAGE 7 OF 7
APPENDIX F
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
COMMUNICATIONS
Buyer Contact Information
Idaho Power Company
1221 West Idaho Street
Boise, ID 83702
Telephone: [phone]
Mr. Karl Bokenkamp
General Manager Power Supply Operations & Planning
Telephone: [phone]
Email: kbokenkampidahopower.com
Mr. Mel Chick
Supervisor Generation Dispatch
Telephone: [phone]
Email: [e-mail]
Ms. Tess Park
Manager Power Operations
Telephone: [phone]
Email: [e-mail]
Mr. Chris Nebrigich
Leader, Transaction Specialist
Telephone: [phone]
Email: tnebrigichidahopower.com
APPENDIX F - PAGE 1 OF 2
Seller Contact Information
USG Oregon LLC
1505 Tyrell Lane
Boise, ID 83706
208-424-1027
Daniel Kunz
Chief Executive Office
dkunz®usgeothermal.com
Kerry Hawkley
Chief Financial Officer
khawkleyusgeothermal.com
24-Hour Project Operational Contact (To be provided prior to First Energy Date)
Name:
Telephone Number:
Cell Phone:
E-Mail:
Fax:
Project On-site Contact information (To be provided prior to First Energy Date)
Phone:
E-mail:
APPENDIX F - PAGE 2 OF 2
APPENDIX G
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
ONE-LINE DIAGRAM OF GENERATING FACILITY
AND
INTERCONNECTION FACILITIES
This Appendix shall contain a one-line diagram of the proposed Facility, Interconnection
Facilities, Point of Delivery, ownership and location of Meters at the Metering Point and any
other data that is deemed to be pertinent in identifying ownership of equipment, energy
deliveries to the Buyer and/or any other responsibilities of the Parties pertinent to this
Agreement.
No later than thirty (30) days after the execution of the Interconnection Agreement, the Seller
shall provide updates to this one-line diagram and/or confirmation that the previously provided
one-line diagram is still accurate.
APPENDIX 0- PAGE 1 OF 1
APPENDIX H
TO
POWER PURCHASE AGREEMENT
BETWEEN
USG OREGON LLC
AND
IDAHO POWER COMPANY
PROJECT MILESTONE REQUIREMENTS AND COMPLETION DATES
All Project Milestones may be completed earlier then the stated time at the sole option of the
Seller. Failure to complete the requirements of a Project Milestone by the specified
completion date shall be an event of default.
Project Milestones -
1.Exploration Schedule
Delivery of a report and exploration schedule to the Buyer.
Completion Date: The required documentation is due within thirty (30) days
of the date that final Commission Approval is received for
this Agreement.
Documentation: Seller shall provide the Buyer a schedule of the additional
exploration activities at this site beyond what has been
completed as of the date of this Agreement. This schedule
shall include but not be limited to key activities required to
establish an estimated MW rating of a potential generation
facility at this site, and the reporting requirements of
Section 5.2.
2.Additional Well Development
Seller shall have commenced the drilling of an additional geothermal fluid production
or injection well in addition to the single existing well.
Completion Date: June 30, 2011.
I
APPENDIX H - PAGE 1 of 3
Documentation: Seller shall provide the Buyer with written documentation
of the commencement of well drilling.
3.Exploration Completion and Resource Feasibility Report
Seller shall have completed adequate exploration and study of the proposed Site to
enable the Seller to establish the estimated electrical generation capability of the
geothermal resource.
Completion Date: The required documentation shall be delivered to Buyer no
later than December 31, 2013
Documentation: The Seller shall supply the Buyer a summary report
including the Seller's statement of the kW rating of the
Facility this geothermal resource is able to support for the
term of this Agreement The report shall include a
summary of the findings of the various studies and
exploration and a recommendation from the Seller as to the
site's ability to accommodate the Facility as envisioned by
this Agreement. This recommendation shall reference and
be supported by the detailed studies and exploration.
Information contained in the report shall include, but not be
limited to, information on the projected electrical
generation capability of this site, ability of the site to
sustain the projected electrical generation facility, and
recommended site development plans to maximize the
usage of the identified geothermal resource. Buyer shall
have the right to request additional detail supporting the
summary report and/or discussions with the parties that
performed or validated the studies.
4.Executed EPC Aireement and NTP
Seller shall have executed an engineering, procurement and construction (EPC)
contract with the primary power plant contractor for construction of the Facility and a
notice—to-proceed (NT?) shall have been issued.
Completion Date: Seller shall have issued the required NTP described above
no later than December 31, 2014
APPENDIX H - PAGE 2 of 3
Documentation: Seller shall provide the Buyer with written confirmation
that a signed NTP was issued and the date on which that
NTP was issued.
Seller shall also meet the documentation requirements of
the Agreement that reference the fourth Project Milestone
included in Article 3.
APPENDIX H - PAGE 3 of 3
CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
OF J.R. SIMPLOT COMPANY AND CLEARWATER PAPER
CORPORATION
ATTACHMENT 2
Office of the Secretary
Service Date
May 1, 2006
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IFC-E-06-3
APPROVAL OF A FIRM ENERGY SALES )
AGREEMENT FOR THE SALE AND )
PURCHASE OF ELECTRIC ENERGY )
BETWEEN IDAHO POWER COMPANY ) ORDER NO. 30028
AND J. R. SIMPLOT COMPANY )
On February 10, 2006, Idaho Power Company (Idaho Power; Company) filed an
Application with the Idaho Public Utilities Commission (Commission) requesting approval of a
Firm Energy Sales Agreement between Idaho Power and J.R. Simplot Company (Simplot) dated
February 8, 2006 (Agreement).
Simplot currently owns, operates and maintains an 18.75 MW cogeneration facility
(Project) at its industrial site near Pocatello, Idaho. The facility is located in the South 1/2 of
Section 7, Township 6 South, Range 34 East, Boise Meridian, Power County, Idaho. The Project
is a qualified cogeneration facility under the applicable provisions of the Public Utility
Regulatory Policies Act of 1978 (PURPA). As reflected in the Company's Application, the
Simplot Project is currently interconnected to Idaho Power and is selling energy to Idaho Power
as a qualifying facility (QF) in accordance with a Firm Energy Sales Agreement dated June 18,
2004 and an approved effective date of March 1, 2004. Reference Case No. IPC-E-04-16, Order
No. 29577.
The existing Firm Energy Sales Agreement is a one-year agreement which permits
automatic renewals of one year on March 1 of each year. The Agreement also specifies that,
with appropriate notice, either party may terminate the Agreement effective March 1. Simplot
has timely requested to terminate the existing Firm Energy Sales Agreement for this Project and
enter into a new Firm Energy Sales Agreement for its Pocatello facility. Idaho Power contends
that the terms of the new Agreement conform to the terms and conditions of Commission Order
No. 29632 (U.S. Geothermal et al. v. Idaho Power) and Commission avoided cost Order No.
29646 (Case No. IPC-E-04-25) for energy deliveries of less than 10 aMW.
Under the terms of the submitted Agreement, Simplot has elected to contract with
Idaho Power for a seven-year term. The Agreement contains non-levelized published avoided
ORDER NO. 30028 1
cost rates established by the Commission in Order No. 29646 (December 1, 2004) for energy
deliveries less than 10 aMW for a contract year beginning February 8, 2006.
As reflected in Agreement ¶ 1.13 and specified in Item B-3 of the Agreement
Appendix B, the maximum capacity of the cogeneration facility is 12 MW. As defined in
Agreement 11.9 and as described further in 14.1.3, Simplot will be required to provide data on
the facility that Idaho Power will use to determine whether, under normal and/or average
conditions, the facility will not exceed 10 aMW on a monthly basis. Idaho Power states that it
has reviewed the historical generation data for the Simplot facility. As reflected in Agreement ¶
7.3, should the Simplot facility exceed 10 aMW on a monthly basis, Idaho Power will accept any
energy (Inadvertent Energy) that does not exceed the maximum capacity amounts; however,
Idaho Power will not purchase or pay for this Inadvertent Energy.
Agreement 125 provides that the Agreement will not become effective until the
Commission has approved without change all the Agreement terms and conditions and declared
that all payments to Simplot that Idaho Power makes for purchases of energy will be allowed as
prudently incurred expenses for ratemaking purposes.
On March 3, 2006, the Commission issued Notices of Application and Modified
Procedure in Case No. IPC-E-06-3. The deadline for filing written comments was March 24,
2006. Comments were received from Commission Staff and a Caldwell customer of the
Company. The customer sees no reason that Idaho Power can't buy Simplot's power as long as
the utility doesn't come back next week and request a rate increase. Commission Staff
recommends that the Agreement be approved.
Staff notes that there are two primary differences between the submitted Agreement
and the one it replaces. First, under the terms of the submitted Agreement, Simplot has elected
to contract with Idaho Power for a seven-year term. This eliminates the automatic annual
renewals that occurred under the prior Agreement. Staff notes that because the prior Agreement
was renewed automatically at the prevailing avoided cost rates during each renewal year, the
submitted Agreement contains the same rates as it would have contained under the prior
Agreement. The second primary difference revises the definition of the 10 MW threshold for
eligibility for published avoided cost rates. Under the prior Agreement, Simplot was limited to
generating no more than 10,000 kWh per hour. Under the submitted Agreement, Simplot is
ORDER NO. 30028 2
limited to generating no more than 10 aMW per month. This revised generation limit is
consistent with the definition of the 10 MW threshold established in the U.S Geothermal case
(Order No. 29632).
Commission Findings
The Commission has reviewed and considered the filings of record in Case No. IPC-
E-06-3, including the underlying Agreement and the comments and recommendations of
Commission Staff. We have also reviewed public comment filed in support of the project.
Idaho Power requests approval of a February 8, 2006 Firm Energy Sales Agreement
between Idaho Power and J.R. Simplot Company for Commission consideration and approval.
The nameplate rating of the cogeneration facility is 18.75 MW. The contract is for a seven-year
term and contains non-levelized published avoided cost rates for energy deliveries not exceeding
10 aMW on a monthly basis. The Commission finds that the Agreement submitted in this case
contains acceptable contract provisions and rates and comports with the terms and conditions of
Order Nos. 29632 and 29682 in Case Nos. IPC-E-04-8; 04-10.
The Commission finds it reasonable that the submitted Agreement be approved
without further notice or procedure. IDAPA 31.01.01.204. We further find it reasonable to
allow payments made under the Agreement as prudently occurred expenses for ratemaking
purposes.
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 (PURPA).
The Commission has authority under PURPA 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 the Commission
does hereby approve the February 8, 2006 Firm Energy Sales Agreement between Idaho Power
Company and J.R. Simplot Company for an effective date of February 8, 2006.
ORDER NO. 30028 3
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.
MA DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this I '
day of j2006.
z ~.':; ;~' WAIO~'
PAUL KJELL
@t,#& jj&"--X--oe
MARSHA H. SMITH, COMMISSIONER
bENNIS "S. HANS , OM I S S I O-N- MER
ATTEST:
JeJ D. Jewell (J
Commission Secretary
bls/0:IPC-E-06-03_sw
ORDER NO. 30028 4
OR IDAHO IDAHO POWER COMPANY 99 P.O. BOX 70 PAIER BOISE, IDAHO 83707
An IDACORP Company
February 9, 2006
MONICA MoE N
Attorney
r: 1•,:.i
I L_.
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. 0. Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-06-
Application For Approval of A Firm Energy Sales
Agreement Between Idaho Power Company and
J.R. Simplot Company
Dear Ms. Jewell:
Please find enclosed for filing an original and seven (7) copies of Idaho
Power Company's Application for the approval of a Firm Energy Sales Agreement
between Idaho Power Company and J.R. Simplot Company.
I would appreciate it if you would return a stamped copy of this transmittal
letter in the enclosed self-addressed, stamped envelope.
Very truly yours,
Monica Moen
MM:jb
Enclosures
Telephone [phone], Fax [phone], e-mail [e-mail]
MONICA MOEN, ISB # 5734
BARTON KLINE, ISB # 1526
Idaho Power Company
1221 West Idaho Street
P. 0. Box 70
Boise, Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
7:F9
Attorney for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR APPROVAL)
OF AN AGREEMENT FOR SALE AND )
PURCHASE OF ELECTRIC ENERGY )
BETWEEN IDAHO POWER COMPANY AND )
THE J. R. SIMPLOT COMPANY )
)
CASE NO. IPC-E-06-.Q3
APPLICATION
COMES NOW Idaho Power Company ("Idaho Power" or the "Company") and,
pursuant to IPUC Rule of Procedure 52, hereby applies for an Idaho Public Utilities
Commission ("IPUC" or the "Commission") Order approving an Agreement between Idaho
Power and the J. R. Simplot Company ("Simplot") under which Simplot would sell and
Idaho Power would purchase electric energy generated by the Simplot cogeneration facility
located at the J R Simplot industrial site near Pocatello, Idaho.
This Application is based on the following:
Simplot currently owns, operates and maintains a cogeneration facility
("Project") at its industrial site near Pocatello, Idaho. The Project is a qualified small
APPLICATION -1
power production facility under the applicable provisions of the Public Utilities
Regulatory Policy Act of 1978 ("PURPA").
This Project is currently interconnected to Idaho Power and is selling
energy to Idaho Power as a Qualifying Facility in accordance with a Firm Energy Sales
agreement dated March 1, 2004. The Project has been selling energy to Idaho Power
since January 1991. Prior to the March 1, 2004 agreement, the Project was selling
energy to the Company under a Firm Energy Sales agreement dated January 24, 1991
and subsequently amended on November 30, 1993 and February 23, 2001. Simplot
has requested a new Firm Energy Sales Agreement for this Project to take effect on
March 1, 2006 upon expiration of the March 1, 2004 agreement.
The March 1, 2004 agreement is a one-year agreement which permits
automatic renewals of one year on March 1 of each year. The agreement also
specifies that, with appropriate notice, either party may terminate the agreement
effective March 1. Simplot has timely requested to terminate the March 1, 2004 Firm
Energy Sales Agreement for this Project and enter into a new Firm Energy Sales
Agreement for this Facility. On February 8, 2006, Idaho Power and Simplot entered
into a Firm Energy Sales Agreement ("Agreement") pursuant to the terms and
conditions of Commission Order No. 29632 and Commission Order 29646 for energy
deliveries of less than 10 average MW. Under the terms of that Agreement, Simplot
elected to contract with Idaho Power for a 7-year term. Simplot further elected to
contract with the Company using the Non-Levelized Published Avoided Cost Rate as
currently established by the Commission for energy deliveries of less than 10 average
APPLICATION -2
MW. A copy of the Agreement between Idaho Power and Simplot is attached hereto
as Exhibit 1.
Iv.
This Agreement is similar to recent agreements entered into by Idaho Power
and approved by the Commission (e.g., Pilgrim Stage Station Wind Park (IPUC Order
29771) Oregon Trails Wind Park (IPUC Order 29772), Tuana Gulch Wind Park (IPUC
Order 29773) and the Thousand Springs Wind Park (IPUC Order 29770)). The Simplot
Agreement contains the various PURPA terms and conditions previously approved by the
Commission in other PURPA agreements and as revised by Commission Order No. 29632
in Case No. IPC-E-04-8 (US Geothermal complaint).
V.
The Maximum Capacity of this Facility is 12 MW as defined in Paragraph
1.13 and specified in Item B-3 of Appendix B of the Agreement. As defined in
Paragraph 1.9 of the Agreement and as described in Paragraph 4.1.3 of the
Agreement, Simplot will be required to provide data on the Facility that Idaho Power will
use to determine whether, under normal and/or average conditions, the Facility will not
exceed 10 average MW on a monthly basis. Idaho Power has reviewed the historical
generation data for this Facility. The data supports Simplot's representation that, under
current normal and/or average conditions, the Facility in the recent past has not
exceeded 10 average MW in generation on a monthly basis. Furthermore, as
described in Paragraph 7.3 of the Agreement, should the Facility exceed 10 average
MW on a monthly basis, Idaho Power will accept any energy ("Inadvertent Energy") that
does not exceed the Maximum Capacity Amount; however, Idaho Power will not
purchase or pay for this Inadvertent Energy.
APPLICATION -3
VI.
Section 25 of the Agreement provides that the Agreement will not become
effective until the Commission has approved all of the Agreement's terms and conditions
and declared that all payments Idaho Power makes for purchases of energy to Simplot will
be allowed as prudently incurred expenses for ratemaking purposes.
VII.
Within this Agreement, various requirements have been placed upon Simplot
in order for Idaho Power to continue to accept energy deliveries from this Project. Idaho
Power will monitor compliance with these initial requirements in addition to the ongoing
requirements through the full term of this Agreement. Should the Commission approve this
Agreement, Idaho Power intends to consider the Effective Date of the Agreement to be
February 8, 2006.
VIII.
The Agreement, as signed and submitted by the Parties thereto, contains
Non-Levelized Published Avoided Cost Rates in conformity with applicable IPUC Orders.
All applicable interconnection charges and monthly Operation and Maintenance charges
under Schedule 72 will be assessed Simplot.
I K111
Service of pleadings, exhibits, orders and other documents relating to this
proceeding should be served on the following:
Monica B. Moen, Attorney II
Barton L. Kline, Senior Attorney
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
[e-mail]
[e-mail]
Randy C. Allphin
Contract Administrator
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
rallphin@idahor)ower.com
APPLICATION -4
NOW, THEREFORE, based on the foregoing, Idaho Power Company hereby
requests that the Commission issue its Order:
(1)Approving the Firm Energy Sales Agreement between Idaho Power
Company and J R Simplot Company without change or condition; and
(2)Declaring that all payments for purchases of energy under the firm
Energy Sales Agreement between Idaho Power Company and J R Simplot Company be
allowed as prudently incurred expenses for ratemaking purposes.
Respectfully submitted this 9th day of February 2006.
440~~ $~ qfeV,_
MONICA B. MOEN
Attorney for Idaho Power Company
APPLICATION -5
CERTIFICATE OF MAILING
I HEREBY CERTIFY that on the 9 day of February 2006,1 served a true and
correct copy of the within and foregoing APPLICATION upon the following named parties
by the method indicated below, and addressed to the following:
J R Simplot Company Hand Delivered
Attn: David Hawk x U.S. Mail
P.O. Box 27 Overnight Mail
Boise, ID 83707 FAX
MONICA B. MOEN
CERTIFICATE OF SERVICE
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-06- 03
IDAHO POWER COMPANY
EXHIBIT 1
FIRM ENERGY SALES AGREEMENT
BETWEEN
IDAHO POWER COMPANY
AND
J.R. SIMPLOT COMPANY
TABLE OF CONTENTS
Article TITLE
1 Definitions
2 No Reliance on Idaho Power
3 Warranties
4 Conditions to Acceptance of Energy
5 Term and Operation Date
6 Purchase and Sale of Net Energy
7 Purchase Price and Method of Payment
8 Environmental Attributes
9 Facility and Interconnection
10 Disconnection Equipment
11 Metering and Telemetry
12 Records
13 Protection
14 Operations
15 Reliability Management System
16 Indemnification and Insurance
17 Force Majeure
18 Land Rights
19 Liability; Dedication
20 Several Obligations
21 Waiver
22 Choice of Laws and Venue
23 Disputes and Default
24 Governmental Authorization
25 Commission Order
26 Successors and Assigns
27 Modification
28 Taxes
29 Notices
30 Additional Terms and Conditions
31 Severability
32 Counterparts
• 33 Entire Agreement Signatures
Appendix A
• Appendix B
• Appendix C
Appendix D
21612006
FIRM ENERGY SALES AGREEMENT
(10 aMW or Less)
SIMPLOT - POCATELLO
Project Number: 41866112
THIS AGREEMENT, entered into on this ___ day of Eek w f 2006 between
ff
J R SIMPLOT COMPANY, a Nevada Corporation (Seller), and IDAHO POWER COMPANY, an Idaho
corporation (Idaho Power), hereinafter sometimes referred to collectively as "Parties" or individually as
"Party."
WrFNESSETH:
WHEREAS, Seller has designed, constructed, owns, maintains and operates an electric
generation facility; and
WHEREAS, Seller wishes to sell, and Idaho Power is willing to purchase, firm electric energy
produced by the Seller's Facility.
THEREFORE, In consideration of the mutual covenants and agreements hereinafter set forth, the
Parties agree as follows:
ARTICLE I: DEFINITIONS
As used in this Agreement and the appendices attached hereto, the following terms
shall have the following meanings:
1.1 "Commission" - The Idaho Public Utilities Commission.
1.2 "Contract Year" - The period commencing each calendar year on the same calendar date as the
Operation Date and ending 364 days thereafter.
1.3 "Designated Dispatch Facility" - Idaho Power's Systems Operations Group, or any subsequent
group designated by Idaho Power.
1.4 "Disconnection Equipment" - All equipment specified in Schedule 72 and the Generation
Interconnection Process and any additional equipment specified in Appendix B or Appendix D.
1.5 "Facility" - That electric generation facility described in Appendix B of this Agreement.
- 1-
2/6/2006
1.6 "Generation Interconnection Process" - Idaho Power's generation interconnection application
and engineering review process developed to ensure a safe and reliable generation
interconnection in compliance with all applicable regulatory requirements, Prudent Electrical
Practices and national safety standards.
1.7 "Inadvertent Energy" - Electric energy Seller does not intend to generate. Inadvertent energy is
more particularly described in paragraph 7.3 of this Agreement.
1.8 'Interconnection Facilities" - All equipment specified in Schedule 72 and the Generation
Interconnection Process and any additional equipment specified in Appendix B or Appendix D.
1.9 "Initial Capacity Determination" - The process by which Idaho Power confirms that under
normal or average design conditions the Facility will generate at no more than 10 average MW
per month and is therefore eligible to be paid the published rates in accordance with Commission
Order No. 29632.
1.10 "Losses" - The loss of electrical energy expressed in kilowatt hours (kWh) occurring as a result
of the transformation and transmission of energy between the point where the Facility's energy is
metered and the point the Facility's energy is delivered to the Idaho Power electrical system. The
loss calculation formula will be as specified in Appendix B of this Agreement.
1.11 "Market Energy Cost" - Eighty-five percent (85%) of the 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. If the Dow Jones Mid-Columbia Index price is discontinued by the reporting agency, both
Parties will mutually agree upon a replacement index, which is similar to the Dow Jones Mid-
Columbia Index. The selected replacement index will be consistent with other similar agreements
and a commonly used index by the electrical industry.
1.12 "Material Breach" -. A Default (paragraph 23.2.1) subject to paragraph 23.2.2.
1.13 "Maximum Capacity Amount" - The maximum capacity (MW) of the Facility will be as
specified in Appendix B of this Agreement.
1.14 "Metering Equipment" - All equipment specified in Schedule 72, the Generation Interconnection
Process, this Agreement and any additional equipment specified in Appendix B or Appendix D
-2-
21612006
required to measure, record and telemeter power flows between the Seller's electric generation
plant and Idaho Power's system.

1.15 "Net Energy" - All of the electric energy produced by the Facility, less Station Use, less Losses,
expressed in kilowatt hours (kWh). Seller commits to deliver all Net Energy to Idaho Power at
the Point of Delivery for the full term of the Agreement. Net Energy does not include Inadvertent
Energy.
1.16 "Operation Date" - The beginning of the day specified in paragraph 5.2 of this Agreement.
1.17 "Point of Delivery'- The location specified in Appendix B, where Idaho Power's and the
Seller's electrical facilities are interconnected.
1.18 "Prudent Electrical Practices" - Those practices, methods and equipment that are commonly and
ordinarily used in electrical engineering and operations to operate electric equipment lawfully,
safely, dependably, efficiently and economically.
1.19 "Schedule 7T'- Idaho Power's Tariff No 101, Schedule 72 or its successor schedules as
approved by the Commission.
1.20 "Season" - The three periods identified in paragraph 6.2.1 of this Agreement.

1.21 "Special Facilities" - Additions or alterations of transmission and/or distribution lines and
transformers as described in Appendix B, Appendix D, Schedule 72 or the Generation
Interconnection Process required to safely interconnect the Seller's Facility to the Idaho Power
- system.
1.22 "Station Use" - Electric energy that is used to operate equipment that is auxiliary or otherwise
related to the production of electricity by the Facility.
1.23 "Surplus Energy" - (1) Net Energy produced by the Seller's Facility and delivered to the Idaho
Power electrical system during the month which exceeds 110% of the monthly Net Energy
Amount for the corresponding month specified in paragraph 6.2. or (2) If the Net Energy
produced by the Seller's Facility and delivered to the Idaho Power electrical system during the
month is less than 90% of the monthly Net Energy Amount for the corresponding month
specified in paragraph 6.2, then all Net Energy delivered by the Facility to the Idaho Power
-3-
2/6/2006
electrical system for that given month or (3) All Net Energy produced by the Seller's Facility and
delivered by the Facility to the Idaho Power electrical system prior to the satisfactory completion
of all requirements of Article IV, Conditions to Continued Acceptance of Energy
1.24 "Total Cost of the Facility" - The total cost of structures, equipment and appurtenances.
ARTICLE II: NO RELIANCE ON IDAHO POWER
2.1 Seller Independent Investigation - Seller warrants and represents to Idaho Power that in entering
into this Agreement and the undertaking by Seller of the obligations set forth herein, Seller has
investigated and determined that it is capable of performing hereunder and has not relied upon
the advice, experience or expertise of Idaho Power in connection with the transactions
contemplated by this Agreement.
2.2 Seller Independent Experts - All professionals or experts including, but not limited to, engineers,
attorneys or accountants, that Seller may have consulted or relied on in undertaking the
transactions contemplated by this Agreement have been solely those of Seller.
ARTICLE ifi: WARRANTIES
3.1 No Warranty by Idaho Power - Any review, acceptance or failure to review Seller's design,
specifications, equipment or facilities shall not be an endorsement or a confirmation by Idaho
Power and Idaho Power makes no warranties, expressed or implied, regarding any aspect of
Seller's design, specifications, equipment or facilities, including, but not limited to, safety,
durability, reliability, strength, capacity, adequacy or economic feasibility.
3.2 Qualifying Facility Status Seller warrants that the Facility is a "Qualifying Facility," as that term
is used and defined in 18 CFR §292.207. After initial qualification, Seller will take such steps as
may be required to maintain the Facility's Qualifying Facility status during the term of this
Agreement and Seller's failure to maintain Qualifying Facility status will be a Material Breach of
this Agreement. Idaho Power reserves the right to review the Seller's Qualifying Facility status
and associated support and compliance documents at anytime during the term of this Agreement.
-4-
216/2006
ARTICLE IV: CONDITIONS TO CONTINUED ACCEPTANCE OF ENERGY
4.1 Prior to the Seller requesting an Operation Date and an Operation Date being assigned for this
Agreement as specified in paragraph 5.2 of this Agreement, the following requirements shall be
completed;
4.1.1 This Facility is currently interconnected to Idaho Power and is selling energy to Idaho
Power as a Qualifying Facility in accordance with a Firm Energy Sales agreement dated
March 1, 2004. The Seller shall submit proof to Idaho Power that all licenses, permits or
approvals necessary for Seller to continue operations have been obtained from applicable
federal, state or local authorities, including, but not limited to, evidence of compliance
with Subpart B, 18 CFR 292.207.
4.1.1.1 As a condition of the Firm Energy Sales Agreement dated March 1, 2004, the
Seller provided Idaho Power a letter (dated February 1, 2005) certifying that all
licenses, permits or approvals necessary for Seller to continue operations were in
full force and effect. Idaho Power will rely on this previous letter as still being
accurate.
4.1.2 Opinion of Counsel - Seller shall submit to Idaho Power an Opinion Letter signed by an
attorney admitted to practice and in good standing in the State of Idaho providing an
opinion that Seller's licenses, permits and approvals as set forth in paragraph 4.1.1 above
are legally and validly issued, are held in the name of the Seller and, based on a
reasonable independent review, counsel is of the opinion that Seller is in substantial
compliance with said permits as of the date of the Opinion Letter. The Opinion Letter
will be in a form acceptable to Idaho Power and will acknowledge that the attorney
rendering the opinion understands that Idaho Power is relying on said opinion. Idaho
Power's acceptance of the form will not be unreasonably withheld. The Opinion Letter
will be governed by and shall be interpreted in accordance with the legal opinion accord
of the American Bar Association Section of Business Law (1991).
-5-
2/6/2006
4.1.2.1 As a condition of the Firm Energy Sales Agreement dated March 1, 2004, the
Seller provided Idaho Power an acceptable Opinion of Counsel letter (dated
February 1, 2005). Idaho Power will rely on this previous letter as still being
accurate.
4.1.3 Initial Capacity Determination - Submit to Idaho Power such data as Idaho Power may
reasonably require to perform the Initial Capacity Determination. Such data will include
but not be limited to, equipment specifications, prime mover data, resource
characteristics, normal and/or average operating design conditions and Station Use data.
Upon receipt of this information, Idaho Power will review the provided data and if
necessary, request additional data to complete the Initial Capacity Determination within
a reasonable time.
4.1.4 Engineer's Certifications - This Facility is currently interconnected to the Idaho Power
system. The Seller will submit an Engineer's Certification of Operations and
Maintenance ("O&M") Policy as described in Commission Order No. 21690. This
certificate will be in the form specified in Appendix C but may be modified to the extent
necessary to recognize the different engineering disciplines providing the certificates.
4.1.4.1 As a condition of the Firm Energy Sales Agreement dated March 1, 2004, the
Seller provided Idaho Power an acceptable Engineer's Certificate dated August
31, 2004. Idaho Power will accept this previously provided Engineer's
Certification to satisfy this requirement.
4.1.5 Insurance - Seller shall submit written proof to Idaho Power of all insurance required in
Article XVI.
4.1.6 Interconnection - Seller shall complete all interconnection modifications, upgrades or
additions as specified in Appendix D of this Agreement.
4.1.7 Written Acceptance - Obtain written confirmation from Idaho Power that all conditions to
acceptance of energy have been fulfilled. Such written confirmation shall not be
unreasonably withheld by Idaho Power.
-6-
2/612006
ARTICLE V: TERM AND OPERATION DATE
5.1 Term - Subject to the provisions of paragraph 5.2 below, this Agreement shall become effective
as of the date of this Agreement and shall continue in full force and effect for a period of seven
(7) Contract Years from the Operation Date.
5.2 Operation Date - The Operation Date shall be March 1, 2006 contingent upon all requirements of
Article N being completed and accepted by Idaho Power Company no later than March 1, 2006.
ARTICLE VI: PURCHASE AND SALE OF NET ENERGY.
6.1 Delivery and Acceptance of Net Energy - Except when either Party's performance is excused as
provided herein, Idaho Power will purchase and Seller will sell all of the Net Energy to Idaho
Power at the Point of Delivery. All Inadvertent Energy produced by the Facility will also be
delivered by the Seller to Idaho Power at the Point of Delivery. At no time will the total amount
of Net Energy and/or Inadvertent Energy produced by the Facility and delivered by the Seller to
the Point of Delivery exceed the Maximum Capacity Amount.
6.2 Net Energy Amounts - Seller intends to produce and deliver Net Energy in the following monthly
amounts:
6.2.1 Initial Year Monthly Net Energy Amounts:
Month kWh
March 5,669,280
Season I April 5,486,400
May 5,669,280
July 6,233,232
August 6,233,232
Season 2 November 5,486,400
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216/2006
December 5,669,280
June 2,432,819
September 6,032,160
Season 3 October 5,669,280
January 5,669,280
February 5,120,640
6.2.2 Ongoing Monthly Net Energy Amounts - Seller shall initially provide Idaho Power with
one year of monthly generation estimates (Initial Year Monthly Net Energy Amounts)
and beginning at the end of month nine and every three months thereafter provide Idaho
Power with an additional three months of forward generation estimates. This information
will be provided to Idaho Power by written notice in accordance with paragraph 29.1, no
later than 5:00 PM of the 5 th day following the end of the previous month. If the Seller
does not provide the Ongoing Monthly Net Energy amounts in a timely manner, Idaho
Power will use the most recent 3 months of the Initial Year Monthly Net Energy
Amounts specified in paragraph 6.2.1 for the next 3 months of monthly Net Energy
amounts.
6.2.3 Seller's Adjustment of Net Energy Amount -
6.2.3.1 No later than the Operation Date, by written notice given to Idaho Power in
accordance with paragraph 29.1, the Seller may revise all of the previously
provided Initial Year Monthly Net Energy Amounts.
6.2.3.2 Beginning with the end of the 3rd month after the Operation Date and at the end
of every third month thereafter: (1) the Seller may not revise the immediate next
three months of previously provided Net Energy Amounts, (2) but by written
notice given to Idaho Power in accordance with paragraph 29.1, no later than
5:00 PM of the 5th day following the end of the previous month, the Seller may
revise all other previously provided Net Energy Amounts. Failure to provide
timely written notice of changed amounts will be deemed to be an election of no
change.
In
2F6/2006
6.2.4 Idaho Power Adjustment of Net Energy Amount - If Idaho Power is excused from
accepting the Seller's Net Energy as specified in paragraph 14.2.1 or if the Seller declares
a Suspension of Energy Deliveries as specified in paragraph 14.3.1 and the Seller's
declared Suspension of Energy Deliveries is accepted by Idaho Power, the Net Energy
Amount as specified in paragraph 6.2 for the specific month in which the reduction or
suspension under paragraph 14.2.1 or 14.3.1 occurs will be reduced in accordance with
the following:
Where:
NEA = Current Month's Net Energy Amount (Paragraph 6.2)
SGU = a.) If Idaho Power is excused from accepting the Seller's Net
Energy as specified in paragraph 14.2.1 this value will be
equal to the percentage of curtailment as specified by
Idaho Power multiplied by the TGU as defined below.
b.) If the Seller declares a Suspension of Energy Deliveries as
specified in paragraph 14.3.1 this value will be the sum of
the individual generation units size ratings as specified in
Appendix B that are impacted by the circumstances
causing the Seller to declare a Suspension of Energy
Deliveries.
TGU = Sum of all of the individual generator ratings of the generation
units at this Facility as specified in Appendix B of this
agreement.
RSH - - Actual hours the Facility's Net Energy deliveries were either
reduced or suspended under paragraph 14.2.1 or 14.3.1
TH = Actual total hours in the current month
Resulting formula being:
Adjusted
TGU NEA ) x(
) )
Net Energy = NEA - ( ( SGU i H
Amount \TH
This Adjusted Net Energy Amount will be used in applicable Surplus Energy calculations for
only the specific month in which Idaho Power was excused from accepting the Seller's Net
Energy or the Seller declared a Suspension of Energy.
-9-
21612006

6.3 Unless excused by an event of Force Majeure, Seller's failure to deliver Net Energy in any
Contract Year in an amount equal to at least ten percent (10%) of the sum of the Initial Year Net
Energy Amounts as specified in paragraph 6.2 shall constitute an event of default.
ARTICLE VII: PURCHASE PRICE AND METHOD OF PAYMENT

7.1 Net Energy Purchase Price - For all Net Energy, Idaho Power will pay the non-levelized energy
price in accordance with Commission Order 29646 with seasonalization factors applied:
Season I - (73.50 %) Season 2 - (120.00 %) Season 3 - (100.00 %)
Year Mills/kWh Mills/kWh Mills/kWh
2006 37.85 61.80 51.50
2007 38.73 63.23 52.69
2008 39.62 64.68 53.90
2009 40.53 66.17 55.14
2010 41.46 67.69 56.41
2011 42.42 69.25 57.71
2012 43.39 70.85 59.04

7.2 Surplus Energy Price - For all Surplus Energy, Idaho Power shall pay to the Seller the current
month's Market Energy Cost or the Net Energy Purchase Price specified in paragraph 7. 1,
whichever is lower.

7.3 Inadvertent Energy -
7.3.1 Inadvertent Energy is electric energy produced by the Facility, expressed in kWh, which
the Seller delivers to Idaho Power at the Point of Delivery that exceeds 10,000 kW
multiplied by the hours in the specific month in which the energy was delivered. (For
example January contains 744 hours. 744 hours times 10,000 kW = 7,440,000 kWh.
Energy delivered in January in excess of 7,440, 000 kWh in this example would be
Inadvertent Energy.)
7.3.2 Although Seller intends to design and operate the Facility to generate no more than 10
average MW and therefore does not intend to generate Inadvertent Energy, Idaho Power
will accept Inadvertent Energy that does not exceed the Maximum Capacity Amount but
will not purchase or pay for Inadvertent Energy
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7.4 Payment Due Date - Energy payments to the Seller will be disbursed within 30 days of the date
which Idaho Power receives and accepts the documentation of the monthly Net Energy and
Inadvertent Energy actually produced by the Seller's Facility and delivered to Idaho Power as
specified in Appendix A.
7.5 Continuing Jurisdiction of the Commission —This Agreement is a special contract and, as such,
the rates, terms and conditions contained in this Agreement will be construed in accordance with
Idaho Power Company v. Idaho Public Utilities Commission and Afton Energy, Inc., 107 Idaho
781, 693 P.2d 427 (1984); Idaho Power Company v. Idaho Public Utilities Commission, 107
Idaho 1122, 695 P.2d 1 261 (1985); Afton Energy. Inc. v. Idaho Power Company, 111 Idaho 925,
729 P.2d 400 (1986); Section 210 of the Public Utilities Regulatory Policies Act of 1978 and 18
CFR §292.303-308.
ARTICLE VIII: ENVIRONMENTAL ATTRIBUTES
8.1 Idaho Power waives any claim to ownership of Environmental Attributes. Environmental
Attributes include, but are not limited to, Green Tags, Green Certificates, Renewable Energy
Credits (RECs) and Tradable Renewable Certificates (TRCs) directly associated with the
production of energy from the Seller's Facility.
ARTICLE IX: FACILITY AND INTERCONNECTION
9.1 Design of Facility - This Facility is interconnected to Idaho Power and is selling energy to Idaho
Power as a Qualifying Facility in accordance with a Firm Energy Sales agreement dated March 1,
2004. In this previous agreement, Seller was required to design, construct, install, own, operate
and maintain the Facility and any Seller-owned Interconnection Facilities so as to allow safe and
reliable generation and delivery of electric energy to Idaho Power for the full term of the
Agreement. Seller will be required to maintain these same standards in the on-going operations
of this facility for the term of this Agreement.
9.2 Interconnection Facilities - This Facility is interconnected to Idaho Power and is selling energy to
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Idaho Power as a Qualifying Facility in accordance with a Firm Energy Sales agreement dated
March 1, 2004. Idaho Power has reviewed the existing Interconnection Facilities and has
identified specific items that will require modification, upgrades or additions to the existing
equipment. These items are documented in Appendix D of this agreement. The Seller will be
responsible to complete the modifications, upgrades or additions as specified in Appendix D. All
costs of all items identified within Appendix D and payment to Idaho Power will be in
accordance with Schedule 72.
ARTICLE X: DISCONNECTION EOUIPMENT
10.1 This Facility is interconnected to Idaho Power and is selling energy to Idaho Power as a
Qualifying Facility in accordance with a Firm Energy Sales agreement dated March 1, 2004.
Idaho Power has reviewed the existing Disconnection Equipment and has identified specific items
that will require modification, upgrades or additions to the existing equipment. These items are
documented in Appendix D of this agreement. The Seller will be responsible to complete the
modifications, upgrades or additions as specified in Appendix D. All costs of all items identified
within Appendix D and payment to Idaho Power will be in accordance with Schedule 72.
ARTICLE XI: METERING AND TELEMETRY
11.1 Metering - This Facility is interconnected to Idaho Power and is selling energy to Idaho Power as
a Qualifying Facility in accordance with a Firm Energy Sales agreement dated March 1, 2004.
Idaho Power has reviewed the Metering and Telemetry and has identified specific items that will
require modification, upgrades or additions to the existing equipment. These items are
documented in Appendix D of this agreement. The Seller will be responsible to complete the
modifications, upgrades or additions as specified in Appendix D. All costs of all items identified
within Appendix D and payment to Idaho Power will be in accordance with Schedule 72. All
meters used to determine the billing hereunder shall be sealed and the seals shall be broken only
by Idaho Power when the meters are to be inspected, tested or adjusted.
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11.1.1 Meter Inspection - Idaho Power shall inspect and test all meters upon their Installation
and at least once every four (4) years thereafter. If requested by Seller, Idaho Power shall
make a special inspection or test of a meter and Seller shall pay the reasonable costs of
such special inspection. Both Parties shall be notified of the time when any inspection or
test shall take place, and each Party may have representatives present at the test or
inspection. If a meter is found to be inaccurate or defective, it shall be adjusted, repaired
or replaced, at Idaho Power's expense in order to provide accurate metering. If a meter
fails to register, or if the measurement made by a meter during a test varies by more than
two percent (2%) from the measurement made by the standard meter used in the test,
adjustment (either upward or downward) to the payments Seller has received shall be
made to correct those payments affected by the inaccurate meter for the actual period
during which inaccurate measurements were made. if the actual period cannot be
determined, corrections to the payments will be based on the shorter of (1) a period equal
to one-half the time from the date of the last previous test of the meter to the date of the
test which established the inaccuracy of the meter; or (2) six (6) months.
11.2 Telemetry - Metering, communications and telemetry equipment is required which is capable of
providing Idaho Power with continuous instantaneous telemetry of Seller's net generation to
Idaho Power's Designated Dispatch Facility. This Facility is interconnected to Idaho Power and
is selling energy to Idaho Power as a Qualifying Facility in accordance with a Firm Energy Sales
agreement dated March 1, 2004. Idaho Power has reviewed the Telemetry Equipment and has
identified specific items that will require modification, upgrades or additions to the existing
equipment in order for the parties to perform under this agreement. These items are documented
in Appendix D of this agreement. The Seller will be responsible to complete the modifications,
upgrades or additions as specified in Appendix D. All costs of all items identified within
Appendix D and payment to Idaho Power will be in accordance with Schedule 72.
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ARTICLE XII- RECORDS
12.1 Maintenance of Records - Seller shall maintain at the Facility or such other location mutually
acceptable to the Parties adequate total generation, Net Energy, Station Use, Inadvertent Energy
and maximum generation (kW) records in a form and content recommended by Idaho Power.
12.2 Inspection - Either Party, after reasonable notice to the other Party, shall have the right, during
normal business hours, to inspect and audit any or all generation, Net Energy, Station Use,
Inadvertent Energy and maximum generation (kW) records pertaining to the Seller's Facility.
ARTICLE Xffl - PROTECTION
13.1 This Facility is interconnected to Idaho Power and is selling energy to Idaho Power as a
Qualifying Facility in accordance with a Firm Energy Sales agreement dated March 1, 2004.
Idaho Power has reviewed the existing Protection equipment and has identified specific items that
will require modification, upgrades or additions to the existing equipment. These items are
documented in Appendix D of this agreement. The Seller will be responsible to complete the
modifications, upgrades or additions as specified in Appendix D. All costs of all items identified
within Appendix D and payment to Idaho Power will be in accordance with Schedule 72. Seller
shall provide and maintain adequate protective equipment sufficient to prevent damage to the
Facility and Seller-furnished Interconnection Facilities. In some cases, some of Seller's
protective relays will provide back-up protection for Idaho Power's facilities. In that event, Idaho
Power will test such relays annually and Seller will pay the actual cost of such annual testing.
ARTICLE XIV - OPERATIONS
14.1 Communications - Idaho Power and the Seller shall maintain appropriate operating
communications through Idaho Power's Designated Dispatch Facility in accordance with
Appendix A of this Agreement.
14.2 Energy Acceptance -
14.2.1 Idaho Power shall be excused from accepting and paying for Net Energy or accepting
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Inadvertent Energy produced by the Facility and delivered by the Seller to the Point of
Delivery, if it is prevented from doing so by an event of Force Majeure, or if Idaho Power
determines that curtailment, interruption or reduction of Net Energy or Inadvertent
Energy deliveries is necessary because of line construction or maintenance requirements,
emergencies, electrical system operating conditions on its system or as otherwise required
by Prudent Electrical Practices. If, for reasons other than an event of Force Majeure,
Idaho Power requires such a curtailment, interruption or reduction of Net Energy
deliveries for a period that exceeds twenty (20) days, beginning with the twenty-first day
of such interruption, curtailment or reduction, Seller will be deemed to be delivering Net
Energy at a rate equivalent to the pro rata daily average of the amounts specified for the
applicable month in paragraph 6.2. Idaho Power will notify Seller when the interruption,
curtailment or reduction is terminated.
14.2.2 If, in the reasonable opinion of Idaho Power, Seller's operation of the Facility or
Interconnection Facilities is unsafe or may otherwise adversely affect Idaho Power's
equipment, personnel or service to its customers, Idaho Power may physically interrupt
the flow of energy from the Facility as specified within Schedule 72 or take such other
reasonable steps as Idaho Power deems appropriate.
14.2.3 Under no circumstances will the Seller deliver Net Energy and/or Inadvertent Energy
from the Facility to the Point of Delivery in an amount that exceeds the Maximum
Capacity Amount. Seller's failure to limit deliveries to the Maximum Capacity Amount
will be a Material Breach of this Agreement.
14.3 Seller Declared Suspension of Energy Deliveries
14.3.1 If the Seller's Facility experiences a forced outage due to equipment failure which is not
caused by an event of Force Majeure or by neglect, disrepair or lack of adequate
preventative maintenance of the Seller's Facility, Seller may, after giving notice as
provided in paragraph 14.3.2 below, temporarily suspend all deliveries of Net Energy to
Idaho Power from the Facility or from individual generation unit(s) within the Facility
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impacted by the forced outage for a period of not less than 48 hours to correct the forced
outage condition ("Declared Suspension of Energy Deliveries"). The Seller's Declared
Suspension of Energy Deliveries will begin at the start of the next full hour following the
Seller's telephone notification as specified in paragraph 14.3.2 and will continue for the
time as specified (not less than 48 hours) in the written notification provided by the
Seller. In the month(s) in which the Declared Suspension of Energy occurred, the Net
Energy Amount will be adjusted as specified in paragraph 6.2.4.
14.3.2 If the Seller desires to initiate a Declared Suspension of Energy Deliveries as provided in
paragraph 14.3.1, the Seller will notify the Designated Dispatch Facility by telephone.
The beginning hour of the Declared Suspension of Energy Deliveries will be at the
earliest the next full hour after making telephone contact with Idaho Power. The Seller
will, within 24 hours after the telephone contact, provide Idaho Power a written notice in
accordance with Article XXIX that will contain the beginning hour and duration of the
Declared Suspension of Energy Deliveries and a description of the conditions that caused
the Seller to initiate a Declared Suspension of Energy Deliveries. Idaho Power will
review the documentation provided by the Seller to determine Idaho Power's acceptance
of the described forced outage as qualifying for a Declared Suspension of Energy
Deliveries as specified in paragraph 14.3.1. Idaho Power's acceptance of the Seller's
forced outage as an acceptable forced outage will be based upon the clear documentation
provided by the Seller that the forced outage is not due do an event of Force Majeure or
by neglect, disrepair or lack of adequate preventative maintenance of the Seller's Facility.
14.4 Voltage Levels - Seller, in accordance with Prudent Electrical Practices shall minimize voltage
fluctuations and maintain voltage levels acceptable to Idaho Power. Idaho Power may, in
accordance with Prudent Electrical Practices, upon one hundred eighty (180) days' notice to the
Seller, change its nominal operating voltage level by more than ten percent (10%) at the Point of
Delivery, in which case Seller shall modify, at Idaho Power's expense, Seller's equipment as
necessary to accommodate the modified nominal operating voltage level.
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14.5 Generator Ramping - Idaho Power, in accordance with Prudent Electrical Practices, shall have the
right to limit the rate that generation is changed at startup, during normal operation or following
reconnection to Idaho Power's electrical system. Generation ramping may be required to permit
Idaho Power's voltage regulation equipment time to respond to changes in power flow.
14.6 Scheduled Maintenance - On or before January 31 of each calendar year, Seller shall submit a
written proposed maintenance schedule of significant Facility maintenance for that calendar year
and Idaho Power and Seller shall mutually agree as to the acceptability of the proposed schedule.
The Parties determination as to the acceptability of the Seller's timetable for scheduled
maintenance will take into consideration Prudent Electrical Practices, Idaho Power system
requirements and the Seller's preferred schedule. Neither Party shall unreasonably withhold
acceptance of the proposed maintenance schedule.
14.7 Maintenance Coordination - The Seller and Idaho Power shall, to the extent practical, coordinate
their respective line and Facility maintenance schedules such that they occur simultaneously.
14.8 Contact Prior to Curtailment - Idaho Power will make a reasonable attempt to contact the Seller
prior to exercising its rights to curtail, interrupt or reduce deliveries from the Seller's Facility.
Seller understands that in the case of emergency circumstances, real time operations of the
electrical system, and/or unplanned events Idaho Power may not be able to provide notice to the
Seller prior to interruption, curtailment, or reduction of electrical energy deliveries to Idaho
Power.
ARTICLE XV: RELIABILITY MANAGEMENT SYSTEM
15.1 Purpose. In order to maintain the reliable operation of the transmission grid, the WECC
Reliability Criteria Agreement sets forth reliability criteria adopted by the WECC to which this
Seller and Idaho Power Company shall be required to comply. Seller acknowledges receipt of
and understanding of the WECC Reliability Criteria Agreement and how it pertains to the Seller's
facility.
15.2 Compliance. This Seller shall comply with the requirements of the WECC Reliability Criteria
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Agreement, including the applicable WECC reliability criteria set forth in Section IV of Annex A
thereof, and, in the event of failure to comply, Seller agrees to be subject to the sanctions
applicable to such failure. Such sanctions shall be assessed pursuant to the procedures contained
in the WECC Reliability Criteria Agreement. Each and all of the provisions of the WECC
Reliability Criteria Agreement are hereby incorporated by reference into this Article 15 as though
set forth fully herein, and Seller shall for all purposes be considered a Participant, and shall be
entitled to all of the rights and privileges and be subject to all of the obligations of a Participant,
under and in connection with the WECC Reliability Criteria Agreement, including, but not
limited to the rights, privileges and obligations set forth in Sections 5, 6 and 10 of the WECC
Reliability Criteria Agreement.
15.3 Payment of Sanctions. Seller shall be responsible for reimbursing Idaho Power Company for any
monetary sanctions assessed against Idaho Power Company due to the action or inaction of the
Seller by WECC pursuant to the WECC Reliability Criteria Agreement. Seller also shall be
responsible for payment of any monetary sanction assessed against the Seller by WECC pursuant
to the WECC Reliability Criteria Agreement. Any such payment shall be made pursuant to the
procedures specified in the WECC Reliability Criteria Agreement.
15.4 Transfer of Control or Sale of Generation Facilities. In any sale or transfer of control of any
generation facilities subject to this Agreement, Seller shall, as a condition of such sale or transfer,
require the acquiring party or transferee with respect to the transferred facilities either to assume
the obligations of the Seller with respect to this Agreement or to enter into an agreement with
Idaho Power Company imposing on the acquiring party or transferee the same obligations
applicable to the Seller pursuant to this Article 15.
15.5 Publication. Seller consents to the release by the WECC of information related to the Seller's
compliance with this Agreement only in accordance with the WECC Reliability Criteria
Agreement.
15.6 Third Parties. Except for the rights and obligations between the WECC and the Seller specified
in this Article 15, this Agreement creates contractual rights and obligations solely between the
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Parties. Nothing in this Agreement shall create, as between the Parties or with respect to the
WECC: (a) any obligation or liability whatsoever (other than as expressly provided in this
Agreement), or (b) any duty or standard of care whatsoever. In addition, nothing in this
Agreement shall create any duty, liability or standard of care whatsoever as to any other party.
Except for the rights, as a third-party beneficiary under this Article 15, of the WECC against the
Seller for the Seller, no third party shall have any rights whatsoever with respect to enforcement
of any provision of this Agreement. Idaho Power Company and the Seller expressly intend that
the WECC is a third-party beneficiary to this Article 15, and the WECC shall have the right to
seek to enforce against the Seller any provision of this Article 15, provided that specific
performance shall be the sole remedy available to the WECC pursuant to Article 15 of this
Agreement, and the Seller shall not be liable to the WECC pursuant to this Agreement for
damages of any kind whatsoever (other than the payment of sanctions to the WECC, if so
construed), whether direct, compensatory, special, indirect, consequential, or punitive.
15.7 Reserved Rights. Nothing in the Article 15 of this Agreement or the WECC Reliability Criteria
Agreement shall affect the right of Idaho Power Company, subject to any necessary regulatory
approval, to take such other measures to maintain reliability, including disconnection that Idaho
Power Company may otherwise be entitled to take.
15.8 Termination of Article 15. Seller may terminate its obligations pursuant to this Article 15:
15.8.1 If after the effective date of this Article 15, the requirements of the WECC Reliability
Criteria Agreement applicable to the Seller are amended so as to adversely affect the
Seller, provided that the Seller gives fifteen (15) days' notice of such termination to
Idaho Power Company and WECC within forty-five (45) days of the date of issuance
of a Commission order accepting such amendment for filing, provided further that the
forty-five (45) day period within which notice of termination is required may be
extended by the Seller for an additional forty-five (45) days if the Seller gives written
notice to Idaho Power Company of such requested extension within the initial forty-
five (45) day period; or
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15.8.2 For any reason on one year's written notice to Idaho Power Company and the WECC.
ARTICLE XVI: INDEMNIFICATION AND INSURANCE
16.1 Indemnification - Each Party shall agree to hold harmless and to indemnify the other Party, its
officers, agents, affiliates, subsidiaries, parent company and employees against all loss, damage,
expense and liability to third persons for injury to or death of person or injury to property,
proximately caused by the indemnifying Party's construction, ownership, operation or
maintenance of, or by failure of, any of such Party's works or facilities used in connection with
this Agreement. The indemnifying Party shall, on the other Party's request, defend any suit
asserting a claim covered by this indemnity. The indemnifying Party shall pay all costs, including
reasonable attorney fees that may be incurred by the other Party in enforcing this indemnity.
16.2 Insurance - During the term of this Agreement, Seller shall secure and continuously carry the
following insurance coverage:
16.2.1 Comprehensive General Liability Insurance for both bodily injury and property damage
with limits of $2,000,000 each occurrence, combined single limit. The deductible for
such insurance shall be consistent with current Insurance Industry Utility practices for
similar property. Seller will be responsible for any deductible applicable to losses
covered by this insurance.
16.2.2 The above insurance coverage shall be placed with an insurance company with an A.M.
Best Company rating of A- or better and shall include:
(a)An endorsement naming Idaho Power as an additional insured and loss payee as
applicable; and
(b)A provision stating that such policy shall not be canceled or the limits of liability
reduced without sixty (60) days' prior written notice to Idaho Power.
16.3 Seller to Provide Certificate of Insurance - As required in paragraph 4.1.5 herein and annually
thereafter, Seller shall furnish Idaho Power a certificate of insurance, together with the
endorsements required therein, evidencing the coverage as set forth above.
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16.4 Seller to Notify Idaho Power of Loss of Coverage - If the insurance coverage required by
paragraph 16.2 shall lapse for any reason, Seller will immediately notify Idaho Power in writing.
The notice will advise Idaho Power of the specific reason for the lapse and the steps Seller is
taking to reinstate the coverage. Failure to provide this notice and to expeditiously reinstate or
replace the coverage will constitute a Material Breach of this Agreement.
ARTICLE XVII. FORCE MAJEURE
17.1 As used in this Agreement, "Force Majeure" or "an event of Force Majeure" means any cause
beyond the control of the Seller or of Idaho Power which, despite the exercise of due diligence,
such Party is unable to prevent or overcome. Force Majeure includes, but is not limited to, acts of
God, fire, flood, storms, wars, hostilities, civil strife, strikes and other labor disturbances,
earthquakes, fires, lightning, epidemics, sabotage, or changes in law or regulation occurring after
the Operation Date, which, by the exercise of reasonable foresight such party could not
reasonably have been expected to avoid and by the exercise of due diligence, it shall be unable to
overcome. If either Party is rendered wholly or in part unable to perform its obligations under
this Agreement because of an event of Force Majenre, both Parties shall be excused from
whatever performance is affected by the event of Force Majeure, provided that:
(1)The non-performing Party shall, as soon as is reasonably possible after the
occurrence of the Force Majeure, give the other Party written notice describing
the particulars of the occurrence.
(2)The suspension of performance shall be of no greater scope and of no longer
duration than is required by the event of Force Majeure.
(3)No obligations of either Party which arose before the occurrence causing the
suspension of performance and which could and should have been fully
performed before such occurrence shall be excused as a result of such
occurrence.
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ARTICLE XVffl: LAND RIGHTS
18.1 Seller to Provide Access - Seller hereby grants to Idaho Power for the term of this Agreement all
necessary rights-of-way and easements to install, operate, maintain, replace, and remove Idaho
Power's Metering Equipment, Interconnection Equipment, Disconnection Equipment, Protection
Equipment and other Special Facilities necessary or useful to this Agreement, including adequate
and continuing access rights on property of Seller. Seller warrants that it has procured sufficient
easements and rights-of-way from third parties so as to provide Idaho Power with the access
described above. All documents granting such easements or rights-of-way shall be subject to
Idaho Power's approval and in recordable form.
18.2 Use of Public Rights-of-Way - The Parties agree that it is necessary to avoid the adverse
environmental and operating impacts that would occur as a result of duplicate electric lines being
constructed in close proximity. Therefore, subject to Idaho Power's compliance with paragraph
18.4, Seller agrees that should Seller seek and receive from any local, state or federal
governmental body the right to erect, construct and maintain Seller-furnished Interconnection
Facilities upon, along and over any and all public roads, streets and highways, then the use by
Seller of such public right-of-way shall be subordinate to any future use by Idaho Power of such
public right-of-way for construction and/or maintenance of electric distribution and transmission
facilities and Idaho Power may claim use of such public right-of-way for such purposes at any
time. Except as required by paragraph 18.4, Idaho Power shall not be required to compensate
Seller for exercising its rights under this paragraph 18.2.
18.3 Joint Use of Facilities - Subject to Idaho Power's compliance with paragraph 18.4, Idaho Power
may use and attach its distribution and/or transmission facilities to Seller's Interconnection
Facilities, may reconstruct Seller's Interconnection Facilities to accommodate Idaho Power's
usage or Idaho Power may construct its own distribution or transmission facilities along, over and
above any public right-of-way acquired from Seller pursuant to paragraph 18.2, attaching Seller's
Interconnection Facilities to such newly constructed facilities. Except as required by paragraph
18.4, Idaho Power shall not be required to compensate Seller for exercising its rights under this
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paragraph 18.3.
18.4 Conditions of Use - It is the intention of the Parties that the Seller be left in substantially the same
condition, both financially and electrically, as Seller existed prior to Idaho Power's exercising its
rights under this Article XVIII. Therefore, the Parties agree that the exercise by Idaho Power of
any of the rights enumerated in paragraphs 18.2 and 18.3 shall: (1) comply with all applicable
laws, codes and Prudent Electrical Practices, (2) equitably share the costs of installing, owning
and operating jointly used facilities and rights-of-way. If the Parties are unable to agree on the
method of apportioning these costs, the dispute will be submitted to the Commission for
resolution and the decision of the Commission will be binding on the Parties, and (3) shall
provide Seller with an interconnection to Idaho Power's system of equal capacity and durability
as existed prior to Idaho Power exercising its rights under this Article XVffl.
ARTICLE X1X: LIABILITY: DEDICATION
19.1 Nothing in this Agreement shall be construed to create any duty to, any standard of care with
reference to, or any liability to any person not a Party to this Agreement. No undertaking by one
Party to the other under any provision of this Agreement shall constitute the dedication of that
Party's system or any portion thereof to the other Party or to the public or affect the status of
Idaho Power as an independent public utility corporation or Seller as an independent individual or
entity.
ARTICLE XX: SEVERAL OBLIGATIONS
20.1 Except where specifically stated in this Agreement to be otherwise, the duties, obligations and
liabilities of the Parties are intended to be several and not joint or collective. Nothing contained
in this Agreement shall ever be construed to create an association, trust, partnership or joint
venture or impose a trust or partnership duty, obligation or liability on or with regard to either
Party. Each Party shall be individually and severally liable for its own obligations under this
Agreement.
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ARTICLE XXI: WAIVER
21.1 Any waiver at any time by either Party of its rights with respect to a default under this Agreement
or with respect to any other matters arising in connection with this Agreement shall not be
deemed a waiver with respect to any subsequent default or other matter.
ARTICLE XXII: CHOICE OF LAWS AND VENUE
22.1 This Agreement shall be construed and interpreted in accordance with the laws of the State of
Idaho without reference to its choice of law provisions.
22.2 Venue for any litigation arising out of or related to this Agreement will lie in the District Court of
the Fourth Judicial District of Idaho in and for the County of Ada.
ARTICLE XXffl: DISPUTES AND DEFAULT
23.1 Disputes - All disputes related to or arising under this Agreement, including, but not limited to,
the interpretation of the terms and conditions of this Agreement, will be submitted to the
Commission for resolution.
23.2 Notice of Default -

23.2.1 Defaults. If either Party fails to perform any of the terms or conditions of this
Agreement (an "event of default"), the nondefaulting Party shall cause notice in
writing to be given to the defaulting Party, specifying the manner in which such
default occurred. If the defaulting Party shall fail to cure such default within the sixty
(60) days after service of such notice, or if the defaulting Party reasonably
demonstrates to the other Party that the default can be cured within a commercially
reasonable time but not within such sixty (60) day period and then falls to diligently
pursue such cure, then, the nondefaulting Party may, at its option, terminate this
Agreement and/or pursue its legal or equitable remedies.

23.2.2 Material Breaches - The notice and cure provisions in paragraph 23.2.1 do not apply
to defaults identified in this Agreement as Material Breaches. Material Breaches must
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be cured as expeditiously as possible following occurrence of the breach.
23.3 Security for Performance - Prior to the Operation Date and thereafter for the full term of this
Agreement, Seller will provide Idaho Power with the following:
23.3.1 Insurance - Evidence of compliance with the provisions of paragraph 16.2. if Seller
fails to comply, such failure will be a Material Breach and may QflIX be cured by
Seller supplying evidence that the required insurance coverage has been replaced or
reinstated;
23.3.2 Engineer's Certifications - Within 30 days of August 31, 2007 and then every three
(3) years after August 31, 2007, Seller will supply Idaho Power with a Certification of
Ongoing Operations and Maintenance (0 & M) from a Registered Professional
Engineer licensed in the State of Idaho, which Certification of Ongoing 0 & M shall
be in the form specified in Appendix C. Seller's failure to supply the required
certificate will be an event of default. Such a default may only be cured by Seller
providing the required certificate; and
23.3.3 Licenses and Permits - During the full term of this Agreement, Seller shall maintain
compliance with all permits and licenses described in paragraph 4.1.1 of this
Agreement. In addition, Seller will supply Idaho Power with copies of any new or
additional permits or licenses. At least every fifth Contract Year, Seller will update the
documentation described in Paragraph 4.1.1. If at any time Seller fails to maintain
compliance with the permits and licenses described in paragraph 4.1.1 or to provide
the documentation required by this paragraph, such failure will be an event of default
and may gall be cured by Seller submitting to Idaho Power evidence of compliance
from the permitting agency.
ARTICLE XXIV: GOVERNMENTAL AUTHORIZATION
24.1 This Agreement is subject to the jurisdiction of those governmental agencies having control over
either Party of this Agreement.
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ARTICLE XXV: COMMISSION ORDER
25.1 This Agreement shall become finally effective upon the Commission's approval of all terms and
provisions hereof without change or condition and declaration that all payments to be made to
Seller hereunder shall be allowed as prudently incurred expenses for ratemaking purposes.
ARTICLE XXVI: SUCCESSORS AND ASSIGNS

26.1 This Agreement and all of the terms and provisions hereof shall be binding upon and inure to the
benefit of the respective successors and assigns of the Parties hereto, except that no assignment
hereof by either Party shall become effective without the written consent of both Parties being
first obtained. Such consent shall not be unreasonably withheld. Notwithstanding the foregoing,
any party which Idaho Power may consolidate, or into which it may merge, or to which it may
convey or transfer substantially all of its electric utility assets, shall automatically, without further
act, and without need of consent or approval by the Seller, succeed to all of Idaho Power's rights,
obligations and interests under this Agreement. This article shall not prevent a financing entity
with recorded or secured rights from exercising all rights and remedies available to it under law
or contract. Idaho Power shall have the right to be notified by the financing entity that it is
exercising such rights or remedies.
ARTICLE XXVII: MODIFICATION

27.1 No modification to this Agreement shall be valid unless it is in writing and signed by both Parties
and subsequently approved by the Commission.
ARTICLE XXVffl: TAXES

28.1 Each Party shall pay before delinquency all taxes and other governmental charges which, if failed
to be paid when due, could result in a lien upon the Facility or the Interconnection Facilities.
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ARTICLE XXIX: NOTICES
29.1 All written notices under this agreement shall be directed as follows and shall be considered
delivered when deposited in the U. S. Mail, first-class postage prepaid, as follows:
To Seller:
Original document to:
J R Simplot Company
Attn: Corporate Secretary
P 0 Box 27
Boise, Idaho 83707
Cony of document to:
J R Simplot Company
Attn: David Hawk
P 0 Box 27
Boise, Idaho 83707
To Idaho Power:
Original document to:
Vice President, Power Supply
Idaho Power Company
P 0 Box 70
Boise, Idaho 83707
Cony of document to:
Cogeneration and Small Power Production
Idaho Power Company
P 0 Box 70
Boise, Idaho 83707
ARTICLE XXX: ADDITIONAL TERMS AND CONDITIONS
30.1 This Agreement includes the following appendices, which are attached hereto and included by
reference:
Appendix A - Generation Scheduling and Reporting
Appendix B - Facility and Point of Delivery
Appendix C - Engineer's Certifications
Appendix D - Modifications, Upgrades and Additions
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ARTICLE XXXI: SEVERABILITY
31.1 The invalidity or unenforceability of any term or provision of this Agreement shall not affect the
validity or enforceability of any other terms or provisions and this Agreement shall be construed
in all other respects as if the invalid or unenforceable term or provision were omitted.
ARTICLE XXXII: COUNTERPARTS
32.1 This Agreement may be executed in two or more counterparts, each of which shall be deemed an
original but all of which together shall constitute one and the same instrument.
ARTICLE XXXIII: ENTIRE AGREEMENT
33.1 This Agreement constitutes the entire Agreement of the Parties concerning the subject matter
hereof and supersedes all prior or contemporaneous oral or written agreements between the
Parties concerning the subject matter hereof.
IN WITNESS WHEREOF, The Parties hereto have caused this Agreement to be executed in their
respective names on the dates set forth below:
Idaho Power Company J R Simplot Company
By Llt__
6h C. Miller, Sr. Vice President, Power Supply
Dated oc
"Idaho Power"
By d. .14~
Dated -i2ZZ2 01 / / "Seller"
Ma
2/6/2006
APPENDIX A
A —1 MONTHLY POWER PRODUCTION AND SWITCHING REPORT
At the end of each month the following required documentation will be submitted to:
Idaho Power Company
Attn: Cogeneration and Small Power Production
P 0 Box 70
Boise, Idaho 83707
The Meter readings required on this report will be the reading on the Idaho Power Meter
Equipment measuring the Facility's total energy production, Station Usage, Inadvertent Energy delivered
to Idaho Power and the maximum generated energy (kW) as recorded on the Meter Equipment and/or any
other required energy measurements to adequately administer this Agreement.
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Idaho Power Company
Cogeneration and Small Power Production
MONTHLY POWER PRODUCTION AND SWITCHING REPORT
Month Year
Project Name Project Number:
Address Phone Number:
City State Zip
Facility Station Station
Output

Usage Usage
Meter Number:
End of Month kWh Meter Reading:
Beginning of Month kWh Meter:
Difference:
Metered
Maximum Generation
kW
Times Meter Constant: Net Generation
kWh for the Month:
Metered Demand:
Breaker Opening Record Breaker Closing Record
Date Time Meter Reason Date Time Meter
* Breaker Onenina Reason Codes
1 Lack of Adequate Prime Mover I hereby certify that the above meter readings are 2 Forced Outage of Facility true and correct as of Midnight on the last day of the 3 Disturbance of IPCo System above month and that the switching record is accurate
4 Scheduled Maintenance and complete as required by the Finn Energy Sales
5 Testing of Protection Systems Agreement to which I am a Party.
6 Cause Unknown
7 Other (Explain)
Signature Date
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L
A-2 ROUTINE REPORTING
Idaho Power Contact Information
Daily Energy Production Reporting
Call daily by 10 am., 1-800-356-4328 or 1-800-635-1093 and leave the following
information:
• Project Identification - Project Name and Project Number
• Current Meter Reading
• Estimated Generation for the current day
• Estimated Generation for the next day
Planned and Unylanned Project outages
Call 1-800-345-1319 and leave the following information:
• Project Identification - Project Name and Project Number
• Approximate time outage occurred
• Estimated day and time of project coming back online
Seller's Contact Information
24-Hour Project Operational Contact
Name:
Telephone Number:
Cell Phone:
Project On-site Contact information
Telephone Number:
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APPENDIX B
FACILITY AND POINT OF DELIVERY
PROJECT NO. 41866112
SIMPLOT POCATELLO
B-i DESCRIPTION OF FACILITY
The Seller's Facility is described as one General Electric synchronous generator with a three-
phase nameplate rating of 18.75 MVA at 13.2 kV three phase, 60 hertz, driven by a steam turbine.
B-2 LOCATION OF FACILITY
The Facility is located in the South Half of Section 7, Township 6 South, Range 34 East, Boise
Meridian, Power County, Idaho.
B-3 MAXIMUM CAPACITY AMOUNT: This value will be 12 MW. This value is the maximum
energy (MW) that potentially could be delivered by the Seller's Facility to the Idaho Power
electrical system at any moment in time.
B-4 POINT OF DELIVERY
The Point of Delivery of energy from the Seller to Idaho Power is the 12.47 kV bushings of the
Idaho Power owned phosphate substation metaiclad vacuum breaker connected to the Simplot
three-phase transformer bank. This isolation transformer bank, which consists of three single phase
5000 kVA/6250 kVA transformers, is connected 12.47 kV Delta to 13.09/7.56 kV grounded wye
three phase, and the underground primary conductors connecting the transformer to the metalciad
is owned by Simplot.
B-5 METERING
The Metering Equipment is located at Don Substation on the Don 015 metalclad bus and consists
of potential and current transformers, and a Scientific Columbus JEM 2 electronic bi—directional
demand meter. The meter registers kilowatt-hours and kilowatts of demand.
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B-6 SPECIAL FACILITIES
The completion of the fifth distribution feeder bay including metalciad and metering at Don
Substation, installation of new substation 12.47 kV underground getaway cables, construction of a
section of overhead three phase 12.47 kV distribution feeder, and the installation of a section of
underground three phase 12.47 kV distribution feeder, has been provided by Idaho Power as
Special Facilities.
B-7 DISCONNECTION EQUIPMENT
Disconnection Equipment is required to insure that the Seller's Facility will be disconnected from
Idaho Power's system in the event of a disturbance on either Idaho Power's system or the Seller's
Facility. This equipment is for the protection of Idaho Power's equipment only. Idaho Power has
installed the protective equipment in a new substation to be called Phosphate. This equipment
consists of a metal clad vacuum breaker, potential transformers, and relaying and associated
wiring. Idaho Power will rely on generator emergency batteries and certain generator fault relays
for fault detection. Idaho Power did connect and test the equipment prior to the operation of the
facility. The total cost of the Disconnection Equipment, connection and testing has been
reimbursed to Idaho Power by the Seller.
B-8 COSTS
The total cost of Special Facilities and metering was $214,989. The total cost of the Disconnecting
Equipment was $84,052. The total cost paid by the Seller was $299,041. In addition to the
installation and construction charges above, during the term of the Agreement Seller will pay Idaho
Power an operation and maintenance charge of the sum of the following:
Original Equipment - This Facility has been interconnected and delivering energy to Idaho
Power Company under previous agreements. The monthly Schedule 72 operations and
maintenance expense in regards to the equipment originally installed at a total cost of
$299,041 will continue on the same operations and maintenance schedule as specified in
Schedule 72 based upon the original installation date of this equipment. Thus, for the
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calendar year from January 1, 2006 through December 31, 2006 Contract Year, the
Schedule 72 Contract Year to be referenced to the Schedule 72 Operations and
Maintenance table will be Contract Year 16, January 1, 2007 through December 31, 2007
Contract Year, the Schedule 72 Contract Year to be referenced to the Schedule 72
Operations and Maintenance table will be Contract Year 17 and so on for the term of the
this Agreement.
Additional Equipment - any new equipment installations beyond the scope of routine
maintenance of the Original Equipment will considered to be Additional Equipment and the
Schedule 72 Contract year will be determined based upon the completed installation date of
the Additional Equipment. The complete installed cost of the Additional Equipment will
be the bases that the appropriate Schedule 72 Operations and Maintenance percentage shall
be applied.
B-9 SALVAGE
No later than sixty (60) days after the termination or expiration of this Agreement, Idaho Power
will prepare and forward to Seller an estimate of the remaining value of those Idaho Power
furnished Interconnection Facilities described in this Appendix, less the cost of removal and
transfer to Idaho Power's nearest warehouse. If the Interconnection Facilities will be removed,
Idaho Power may then be invoiced by Seller for the net salvage value estimated by Idaho Power
for the interconnection facilities and shall pay such amount to Seller within thirty (30) days after
receipt of said invoice.
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APPENDIX C
ENGINEER'S CERTIFICATION
OF
OPERATIONS & MAINTENANCE POLICY
The undersigned , on behalf of himself and
hereinafter collectively referred to as "Engineer,"
hereby states and certifies to the Seller as follows:
1.That Engineer is a Licensed Professional Engineer in good standing in the State of Idaho.
2.That Engineer has reviewed the Energy Sales Agreement, hereinafter "Agreement," between
Idaho Power as Buyer, and as Seller, dated
3.That the cogeneration or small power production project which is the subject of the Agreement
and this Statement is identified as IPCo Facility No. and is hereinafter referred to as
the "Project."
4.That the Project, which is commonly known as the , is located in
Section Township , Range , Boise Meridian, County, Idaho.
5.That Engineer recognizes that the Agreement provides for the Project to furnish electrical energy
to Idaho Power for a twenty (20) year period.
6.That Engineer has substantial experience in the design, construction and operation of electric
power plants of the same type as this Project.
7.That Engineer has no economic relationship to the Design Engineer of this Project.
8.That Engineer has reviewed and/or supervised the review of the Policy for Operation and
Maintenance ("O&M") for this Project and it is his professional opinion that, provided said Project has
been designed and built to appropriate standards, adherence to said O&M Policy will result in the
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Project's producing at or near the design electrical output, efficiency and plant factor for a twenty (20)
year period.
9.That Engineer recognizes that Idaho Power, in accordance with paragraph 5.2 of the Agreement,
is relying on Engineer's representations and opinions contained in this Statement.
10.That Engineer certifies that the above statements are complete, true and accurate to the best of his
knowledge and therefore sets his hand and seal below.
UM
(P.E. Stamp)
Date
-36-
21612006
APPENDIX C
ENGINEER'S CERTIFICATION
OF
ONGOING OPERATIONS AND MAINTENANCE
The undersigned on behalf of himself and
hereinafter collectively referred to as "Engineer," hereby
states and certifies to the Seller as follows:
1.That Engineer is a Licensed Professional Engineer in good standing in the State of Idaho.
2.That Engineer has reviewed the Energy Sales Agreement, hereinafter "Agreement," between
Idaho Power as Buyer, and as Seller, dated
3.That the cogeneration or small power production project which is the subject of the Agreement
and this Statement is identified as IPCo Facility No. _ and hereinafter referred to as the
"Project".
4.That the Project, which is commonly known as the Project,
is located at
5.That Engineer recognizes that the Agreement provides for the Project to furnish electrical energy
to Idaho Power for a twenty (20) year period.
6.That Engineer has substantial experience in the design, construction and operation of electric
power plants of the same type as this Project.
7.That Engineer has no economic relationship to the Design Engineer of this Project.
8.That Engineer has made a physical inspection of said Project, its operations and maintenance
records since the last previous certified inspection. It is Engineer's professional opinion, based on the
Project's appearance, that its ongoing O&M has been substantially in accordance with said O&M Policy;
that it is in reasonably good operating condition; and that if adherence to said O&M Policy continues, the
Project will continue producing at or near its design electrical output, efficiency and plant factor for the
remaining years of the Agreement.
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9.That Engineer recognizes that Idaho Power, in accordance with paragraph 5.2 of the Agreement,
is relying on Engineer's representations and opinions contained in this Statement.
10.That Engineer certifies that the above statements are complete, true and accurate to the best of his
knowledge and therefore sets his hand and seal below.
By
• (P.E. Stamp)
Date
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2/6/2006
APPENDIX C
ENGINEER'S CERTIFICATION
OF
DESIGN & CONSTRUCTION ADEQUACY
The undersigned , on behalf of himself and
hereinafter collectively referred to as "Engineer",
hereby states and certifies to Idaho Power as follows:
1.That Engineer is a Licensed Professional Engineer in good standing in the State of Idaho.
2.That Engineer has reviewed the Firm Energy Sales Agreement, hereinafter "Agreement",
between Idaho Power as Buyer, and as Seller, dated
3.That the cogeneration or small power production project, which is the subject of the
Agreement and this Statement, is identified as IPCo Facility No and is hereinafter
referred to as the "Project".
4.That the Project, which is commonly known as the
Project, is located in Section , Township ______, Range ______, Boise Meridian,
County, Idaho.
5.That Engineer recognizes that the Agreement provides for the Project to furnish electrical
energy to Idaho Power for a (_) year period.
6.That Engineer has substantial experience in the design, construction and operation of
electric power plants of the same type as this Project.
7.That Engineer has no economic relationship to the Design Engineer of this Project and
has made the analysis of the plans and specifications independently.
8.That Engineer has reviewed the engineering design and construction of the Project,
including the civil work, electrical work, generating equipment, prime mover conveyance system, Seller
furnished Interconnection Facilities and other Project facilities and equipment.
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9.That the Project has been constructed in accordance with said plans and specifications, all
applicable codes and consistent with Prudent Electrical Practices as that term is described in the
Agreement.
10.That the design and construction of the Project is such that with reasonable and prudent
operation and maintenance practices by Seller, the Project is capable of performing in accordance with the
terms of the Agreement and with Prudent Electrical Practices for a _________ ( ) year period.
11.That Engineer recognizes that Idaho Power, in accordance with paragraph 5.2 of the
Agreement, in interconnecting the Project with its system, is relying on Engineer's representations and
opinions contained in this Statement.
12.That Engineer certifies that the above statements are complete, true and accurate to the
best of his knowledge and therefore sets his hand and seal below.
M. (P.E. Stamp)
Date
NMI
21612006
APPENDIX D
MODIFICATIONS, UPGRADES AND ADDITIONS
PROJECT NO. 41866112
SIMPLOT POCATELLO
This Facility is interconnected to Idaho Power and is selling energy to Idaho Power as a Qualifying
Facility in accordance with a Firm Energy Sales Agreement dated March 1, 2004, prior to that agreement
this Facility was selling energy to Idaho Power as a Qualifying Facility in accordance with a Firm Energy
Sales agreement dated January 24, 1991, first amendment of November 30, 1993 and second amendment
dated February 23, 2001. The Interconnection Facilities, Disconnection Equipment, Metering Equipment,
Telemetry Equipment and Protection Equipment were designed, installed, operated and maintained in
accordance with these previous agreements.
Idaho Power has reviewed the existing Interconnection Facilities, Disconnection Equipment, Metering
Equipment, Telemetry Equipment and Protection Equipment and listed below are specific modifications,
upgrades and /or additions required for these facility to continue to deliver energy to Idaho Power at the
Point of Delivery under this new Energy Sales Agreement. The Seller will be responsible to complete the
modifications, upgrades or additions as specified in this Appendix D. All costs of all items identified
within this Appendix D and payment to Idaho Power will be in accordance with Schedule 72.
D-1 INTERCONNECTION FACILITIES
Idaho Power has reviewed the existing Interconnection Facilities at the Sellers facility and finds
that no upgrades, modifications or additions are required that the Seller would at this time be
responsible for. If in the future, Prudent Electrical Practices, regulations, electrical codes or
safety codes require upgrades, modifications or additions to the existing equipment, Idaho Power
will notify the Seller of these requirements and the Seller will be responsible for all costs of all
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items identified and payment to Idaho Power will be in accordance with Schedule 72.
D-2 DISCONNECTION EQUIPMENT
Idaho Power has reviewed the existing Disconnection Equipment at the Sellers facility and finds
that no upgrades, modifications or additions are required that the Seller would at this time be
responsible for. If in the future, Prudent Electrical Practices, regulations, electrical codes or
safety codes require upgrades, modifications or additions to the existing equipment, Idaho Power
will notify the Seller of these requirements and the Seller will be responsible for all costs of all
items identified and payment to Idaho Power will be in accordance with Schedule 72.
D-3 METERING EQUIPMENT
Idaho Power has reviewed the existing Metering Equipment at the Sellers facility and finds that
no upgrades, modifications or additions are required that the Seller would at this time be
responsible for. If in the future, Prudent Electrical Practices, regulations, electrical codes or
safety codes require upgrades, modifications or additions to the existing equipment, Idaho Power
will notify the Seller of these requirements and the Seller will be responsible for all costs of all
items identified and payment to Idaho Power will be in accordance with Schedule 72.
D-4 TELEMETRY EQUIPMENT
Idaho Power has reviewed the existing Telemetry Equipment at the Sellers facility and finds that
no upgrades, modifications or additions are required that the Seller would at this time be
responsible for. If in the future, Prudent Electrical Practices, regulations, electrical codes or
safety codes require upgrades, modifications or additions to the existing equipment, Idaho Power
will notify the Seller of these requirements and the Seller will be responsible for all costs of all
items identified and payment to Idaho Power will be in accordance with Schedule 72.
D-5 PROTECTION EQUIPMENT
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Idaho Power has reviewed the existing Protection Equipment at the Sellers facility and finds that
no upgrades, modifications or additions are required that the Seller would at this time be
responsible for. If in the future, Prudent Electrical Practices, regulations, electrical codes or
safety codes require upgrades, modifications or additions to the existing equipment, Idaho Power
will notify the Seller of these requirements and the Seller will be responsible for all costs of all
items identified and payment to Idaho Power will be in accordance with Schedule 72.
Facility Owned Protective Relays - The facility owns and operates several protective
relays that provide protection to the Idaho Power System. As specified in paragraph 13.1
of this Agreement, when the Seller's protective relays provide protection for the Idaho
Power system, Idaho Power annually tests these relays at the Seller' s expense.
Historically, this testing has been accomplished by Idaho Power witnessing the Seller's
annual tests of these relays. The Seller being responsible for costs of the tests and the
cost of Idaho Power providing a witness to these tests. This arrangement has
accommodated both parties in the past and will be continued until such time as either
Idaho Power or the Seller request in writing a change in this testing procedure.
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CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
OF J.R. SIMPLOT COMPANY AND CLEARWATER PAPER
CORPORATION
ATTACHMENT 3
Office of the Secretary
Service Date
January 15, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT PETITION )
OF AVISTA CORPORATION AND ) CASE NO. AVU-E-03-7
POTLATCH CORPORATION FOR )
APPROVAL OF A POWER PURCHASE AND )
SALE AGREEMENT ) ORDER NO. 29418
On August 25, 2003, Avista Corporation dba Avista Utilities (Avista) and Potlatch
Corporation (Potlatch) filed a Joint Petition with the Idaho Public Utilities Commission
(Commission) requesting an Order approving a submitted Power Purchase and Sale Agreement
(Agreement) between Avista and Potlatch dated July 22, 2003. Potlatch operates a wood pulp,
paperboard, tissue and wood product manufacturing facility in Lewiston, Idaho Potlatch owns
and operates four electric generators at the Lewiston plant that are capable of generating
approximately 130 megawatts (MWs) of energy. The Potlatch electric generators are qualifying
facilities (QFs) pursuant to the Public Utilities Regulatory Policies Act of 1978 (PURPA).
Direct testimony of Avista supporting the Purchase and Sale Agreement was filed with the
Commission on September 26, 2003. Also filed with the Commission on October 10, 2003 is a
related Interconnection Agreement dated September 22, 2003.
The Commission in this Order approves the submitted Avista/Potlatch Power
Purchase and Sale Agreement dated July 22, 2003. In doing so we find the contract terms,
pricing, jurisdictional allocation and proposed recovery method to be reasonable and acceptable.
The Commission in this Order approves a recovery method and authorizes the booking of
Avista's power purchase costs in the Company's PCA deferral account. This Order has no
immediate rate effect and does not change the tariff rates for other customers. Recovery of
Potlatch power purchase costs by the Company will require a rate case or PCA filing.
Agreement
The submitted Power Purchase and Sale Agreement is for a ten-year term beginning
July 1, 2003 and ending June 30, 2013. The Agreement is conditioned upon approval by the
Commission of 1) a direct assignment to Avista's Idaho operations of all power purchase costs
paid by Avista to Potlatch under the Purchase and Sale Agreement and 2) deferral and recovery
of 100% of all power purchase costs paid by Avista to Potlatch under the Agreement to Avista's
ORDER NO. 29418 1
Idaho Power Cost Adjustment (PCA) mechanism (Schedule 66) or otherwise recovered by
Avista through base rates.
As recited in the Joint Petition of the parties, Avista will be the sole purchaser of
Potlatch's generation and said purchase is intended to satisfy Avista's obligations under PURPA
to purchase power from the qualifying facilities at the Lewiston plant. Avista will pay Potlatch
$42.92 per MWII up to a maximum base generation amount of 543,120 MWh (544,608 during a
leap year) generated by Potlatch during each July 1 through June 30 period (Operating Year) of
the Agreement. This amount is equivalent to 62 average megawatts (aMW) and is referred to in
the Agreement as the "Base Generation Amount." Amounts generated by Potlatch in excess of
the maximum Base Generation Amount each Operating Year ("Excess Generation Amount")
will either be purchased by Avista at 85% of the applicable Mid-Columbia Firm Index Price,
with a price cap of $55 per M'ATh, or used by Potlatch to reduce its load requirements from
Avista. The purchase of Potlatch's Excess Generation Amounts by Avista is limited to 43,800
MWII (5 aMW) each Operating Year. Excess Generation Amounts above this level would be
used by Potlatch to serve its load requirements.
Additionally, it is noted that Potlatch has the capacity to generate additional amounts
("Incremental Generation Amounts") under certain circumstances. The Purchase and Sale
Agreement provides for the purchase by Avista of Incremental Generation Amounts when it is
mutually beneficial to both parties, under the terms and conditions specified in the Agreement.
As reflected in the Agreement, Avista will serve Potlatch's load requirements at
Potlatch's Lewiston plant under its Extra Large General Service Schedule 25 rates, including the
present Power Cost Adjustment (PCA) surcharge and all applicable rate adjustments, unless the
Commission issues an Order in the future authorizing different billing rates.
Avista and Potlatch request that the Commission issue an Order approving the
Purchase and Sale Agreement as a settlement of all known existing disputes between the parties,
including without limitation, Case No. AVU-E-01-5 (In the matter of the Petition of Potlatch
Corporation for an Order determining the terms and conditions of Potlatch's purchase of
electricity from Avista Utilities) and Case No. AVU-E-02-8 (a Potlatch complaint alleging that
Avista was refusing to purchase the cogeneration of Potlatch's PURPA qualifying facilities at its
Lewiston plant).
ORDER NO. 29418 2
On October 23, 2003, the Commission issued Notices of Joint Petition and Modified
Procedure in Case No. AVU-E-03-7. The deadline for filing written comments was November
14, 2003. The reply deadline was November 28, 2003. Commission Staff was the only party to
file comments. No reply comments were filed.
Staff Comments
Staff recommends that the Commission approve the submitted Power Purchase and
Sale Agreement between Avista and Potlatch. Staff comments can be summarized as follows:
Proposed Price for Potlatch Generation
Staff notes that Potlatch's generators have been certified by the Federal Energy
Regulatory Commission (FERC) as PURPA "Qualifying Facilities." As such, Avista has an
obligation under PURPA to purchase power offered for sale at avoided cost rates established by
the Commission. The established method for determining avoided cost rates for projects larger
than 10 megawatts is an Integrated Resource Plan (IRP)-based methodology. The avoided cost
methodology is described in Order No. 26576 and its accompanying Settlement Stipulation. The
rate computed for Potlatch is the first under the IRP-based methodology.
A. Determination of the Contract Rate for Base Generation
Avista performed an analysis using the AURORA computer model to determine the
value of Potlatch's generation. Using the same computer model, Staff reviewed the analysis and
computations done by Avista, verified the input data and the assumptions and confirmed the rate
offered to Potlatch. Staff believes Avista has correctly followed the methodology for computing
an avoided cost rate as described in Order No. 26576. The rate for Base Generation Amounts of
$42.92 per MWIi is the 10-year levelized avoided cost rate from Avista's 2002 IRP. The rate
represents an estimate of future market prices that fully reflects the fixed costs of new
generation.
Another method used by Staff to verify the value established for Potlatch generation
was to compare the purchase price to published avoided cost rates for projects 10 MW and
smaller. The non-fueled published avoided cost rate for a 10-year contract length with a 2003
online date is $44.43 per MWh. These rates are based on the cost of generating energy using a
gas-fired combined cycle combustion turbine (CCCT). The small difference in these two prices,
Staff contends, can be justified based on the different operating characteristics of Potlatch
generation and a CCCT. The 10-year levelized price approved by the Commission and paid by
ORDER NO. 29418 3
Avista for Potlatch generation in the 1992 special contract was $41.50 per MW1I. The annual
cost for Avista to purchase Potlatch generation is only $420,000 more than it was under the old
contract and will remain in effect over the entire life of the new Agreement.
Staff concludes that the contract rate for Base Generation was appropriately derived
and reasonably supported and recommends approval.
B. Contract Rates for Excess and Incremental Generation Amounts
Under the Agreement, Excess Generation (i.e., amounts generated by Potlatch in
excess of the Base Generation Amount) will either be purchased by Avista at 85% of the
applicable Mid-Columbia (Mid-C) firm index price, with a price cap of $55 per MWII, or used
by Potlatch to reduce its load requirements from Avista. The purchase of Potlatch's Excess
Generation Amounts by Avista is limited to 5 aMW (43,800 MWh) each operating year. Staff
believes that a purchase price equal to 85% of the Mid-C index price is reasonable. In addition,
Staff contends that the rate is consistent with comparable rates paid by other utilities. The price
is the same as the price paid by Idaho Power Company for the equivalent of excess energy in
some of its PURPA contracts and is also equal to Idaho Power's non-firm energy rate under its
electric Schedule 86.
Staff also believes it is reasonable to cap the price paid for Excess Generation
amounts at $55 per MWh. A price cap of $55 will insure that Avista is not forced to pay
excessive amounts, yet it will provide the Company an opportunity to purchase small amounts of
energy at below market prices when supplies are limited.
Incremental Generation is energy produced by Potlatch that exceeds the Base
Generation Amounts and the Excess Generation Amounts. The rates for Incremental Generation
are either: a) for prescheduled generation, 85% of market price from a unit contingent sale that
Avista is able to make with a third party, or b) on a real-time basis at 80% of market price for the
hour. Staff believes that these rates are reasonable for Incremental Generation. As the
Agreement is structured, both parties will benefit from the sale and purchase of Incremental
Generation. Potlatch will be able to receive additional benefit from its extra generation during
periods when market prices are high, while Avista will be able to benefit by purchasing from
Potlatch at below market prices.
Staff concludes that the methodology for calculation of contract rates for Excess and
Incremental Generation Amounts is reasonable and recommends approval.
ORDER NO. 29418 4
Service Pricing
Staff notes that the 1992 special contract price for Avista to serve Potlatch was
essentially based on electric prices in the market place: The price of all but the 25 MW of
interruptible load also included floor and ceiling prices. The average cost for non-interruptible
service under the old contract was approximately $42.50 per MWh in 2001.
Under the proposed Agreement, Avista will provide service to Potlatch under the
terms and conditions of the Company's existing Extra Large General Service Schedule 25. This
schedule requires Potlatch to pay an average base rate of $31.71 per MWh, generating
approximately $27.7 million per year in base revenues. Potlatch will also be subject to the Tax
Adjustment Schedule 58, the Temporary Rate Adjustment Schedule 65, the Power Cost
Adjustment Schedule 66 and the Energy Efficiency Rider Adjustment Schedule 91. When the
rate from non-tax Schedules 65, 66 and 91 are added to the base rate, the 2003 price paid by
Potlatch for service averages $38.65 per MWh. Although Potlatch's 100 MW of load exceeds
the Schedule 25 limit of approximately 25 MW, Schedule 25A which is part of Schedule 25
states:
Customers whose demand from all such meters exceeds 25,000 KVA (25
MW) may be served under special contract wherein the rates, terms and
conditions of service are specified and approved by the IPUC. If customer
requires service during either the contract negotiation or resolution period,
service will be supplied under this rate schedule...
Potlatch, Staff notes, is by far Avista' s largest single customer and electric Schedule
25 has the largest load requirement currently approved by the Commission for Avista. Absent an
analysis to specifically identify Potlatch service costs, Staff contends that Schedule 25 is the
most appropriate proxy to reflect Potlatch embedded cost of service. Given that current
Schedule 25 rates are based on the embedded cost to serve a group of industrial customers that
are much smaller than Potlatch, Staff speculates that it is likely that specific embedded costs to
serve Potlatch could be lower than those used to set Schedule 25 rates. The Agreement allows
either party in the context of a future proceeding to argue that the cost to serve Potlatch justifies
rates that are either higher or lower than those found in Schedule 25.
Staff concludes that without a cost of service study the Agreement's proposed use of
Schedule 25 as a proxy for pricing Potlatch's load is reasonable and recommends approval.
ORDER NO. 29418 5
Jurisdictional Allocation
A.Background
The methodology approved by the Commission to historically allocate cost between
Avista' s various jurisdictions includes an allocation of all generation costs based on the
jurisdictional weighting of demand and energy (67% Washington; 33% Idaho). Revenue, on the
other band, has always been directly assigned to the jurisdiction where the customer resides.
Prior to 1992, Avista paid nothing for Potlatch generation and received revenue from
Potlatch based upon the net load served after Potlatch used its generation to partially offset its
load. Revenues from this service arrangement remained in the Idaho jurisdiction and generation
costs associated with serving the net load were allocated among the Idaho and Washington
jurisdictions.
Under the 1992 special contract, Avista purchased all Potlatch generation at a pre-
established price and received revenue from Potlatch based on its total load. The effect of this
service arrangement under traditional jurisdictional allocation methodology was simply an
increase in generation costs allocated to other jurisdictions. This is due to a traditional allocation
methodology that adds generation cost to the system on the margin but allocates increased
system generation costs to Idaho on the average (i.e., treating Potlatch load that was previously
self-generated as having an entitlement to embedded cost resources). Allocation of all revenues
on a situs basis compounded the problem. To counteract this effect, the 1992 contract approval
included allocation of 60 MW of Potlatch revenues as well as purchase power costs of 60
megawatts of Potlatch generation on a jurisdictional basis. This adjustment was a compromise
that balanced costs allocated to the various jurisdictions with offsetting revenues and worked
fairly well because revenues from 60 megawatts of Potlatch load were fairly close to the costs of
purchasing 60 megawatts of Potlatch generation.
B.Agreement - New Potlatch Allocation Methodology
Under the new Agreement, the cost of purchasing 60 megawatts of Potlatch
generation is significantly higher than the revenue generated from serving 60 megawatts of
Potlatch load. Consequently, the Company is proposing a different jurisdictional allocation
method. Avista proposes to directly assign all revenues and costs associated with the additional
60 megawatts of Potlatch load and generation to Idaho. This allocation methodology places the
net cost of buying from Potlatch and selling to Potlatch on the Idaho jurisdiction. Under the
ORDER NO. 29418 6
net cost of buying from Potlatch and selling to Potlatch on the Idaho jurisdiction. Under the
Company's allocation proposal, all of the Company's other jurisdictions will be held harmless.
Although no other generation costs are jurisdictionally allocated in this fashion, the
Company believes it is appropriate in this case because the Agreement provides the opportunity
for additional benefits to Idaho customers and Idaho is the primary beneficiary of "secondary"
benefits. Avista states also that it does not believe the Washington Utilities and Transportation
Commission (WUTC) would accept the ratemaking consequences of the Agreement using
traditional allocation methodology. Nor, the Company states, does it believe that Avista
shareholders should bear the additional costs deemed unacceptable by the WUTC. The
Company believes the Agreement is "an Idaho solution to an Idaho problem."
Staff notes that the Company has conditioned the appropriateness of the proposed
purchase/sale rates on the Commission's approval of the Company-proposed allocation method.
The fact is, Staff observes, the net cost of the Agreement increases under the proposed rates
because expenses exceed revenues. For Avista to be made whole under the jurisdictional
allocation previously approved for the old contract, the Company must collect a large portion of
the excess costs from Washington customers. From a practical standpoint, someone must pay
the difference between serving Potlatch at embedded cost and purchasing Potlatch generation at
marginal cost. Staff recognizes that Potlatch is an Idaho customer providing employment and
taxes in Idaho. If rates are appropriately established and if benefits accrue primarily to Idaho,
Staff believes it is also reasonable to recover the costs from Idaho customers. Staff supports and
recommends approval of the Company-proposed method of cost allocation.
Cost Recovery and Revenue Impact
For the purposes of this case, Staff evaluated Idaho revenue impact by comparing net
revenues/costs included in base rates under the 1992 contract to revenues/costs that will be
included in rates under the new Agreement. Until the new jurisdictional allocation methodology
and revenues/costs of the new Agreement are included in base rates as part of a general rate case,
the Company proposes to account for the changes through the Company's Idaho PCA. The
comparison also reflects that Potlatch is subject to the PCA under the new Agreement but was
not subject to the PCA under the old contract.
The simplest way to evaluate the impact of the new Agreement, Staff contends, is to
compare the net cost of the two contracts on a system basis. The old contract had annual system
ORDER NO. 29418 7
expenses of $28.8 million and annual system revenues of $26.2 million for a net annual cost of
$2.6 million. The new Agreement has annual system expenses of $31.25 million and annual
revenues of $27.7 million for a net system cost of $3.6 million. Therefore, the new Agreement
increases annual net costs by approximately $1 million on a system basis.
However, the proposed change in the jurisdictional allocation, Staff notes, shifts most
of the costs to the Idaho jurisdiction. Under the jurisdictional allocation methodology approved
with the old contract, the net cost allocated annually to Idaho is actually a benefit of $296,000.
Under the allocation methodology proposed with the new Agreement, Idaho costs increase by
$4.1 million for the term of the Agreement, from a $296,000 allocated net benefit to a $3.8
million directly assigned net cost. A $4.1 million increase in Idaho's revenue requirement
represents the equivalent of a 2.3% overall rate increase. Until power purchase costs are
included in base rates, the Company proposes to pass 100% of this annual expense increase
through the Idaho PCA. Staff agrees with the recovery method proposed. Staff notes that
Potlatch will contribute approximately $5.3 million during the current year as a Schedule 25
customer subject to the PCA. The resultant net effect of the new Agreement during the 2003
PCA period is a $1.2 million reduction in deferred costs borne by other Idaho customers.
The above analysis of revenue impact, however, is valid only under existing rates and
continued service to Potlatch under Schedule 25. Staff notes that there is a possibility that the
net cost of the Agreement could increase in the future if rates applied to serve Potlatch are
reduced. Moreover, there will be no offsetting revenue through the PCA from Potlatch under
normal water and power supply conditions to offset the effect of higher base rates. In fact,
during high water conditions, Potlatch will receive some of the PCA credit that would otherwise
go to other Idaho customers. However, because the rate paid to Potlatch for generation is fixed,
Staff believes that it is likely that the cost differential between the cost to serve Potlatch and the
cost to buy its generation will ultimately decline.
Commission Findings
The Commission has reviewed and considered the filings of record in Case No.
AVIJ-E.-03-7, including the underlying Agreement, the supporting filings of Avista and the
comments and recommendations of Commission Staff. We find that the established record in
this case presents an adequate basis for decision. We therefore continue to find it reasonable to
process this case pursuant to Modified Procedure. Reference IDAPA 31.01.01.204.
ORDER NO. 29418 8
Power Purchases (Power Deliveries to A vista)
The submitted Agreement represents that Potlatch's electric generators at its
Lewiston plant are PIJRPA qualifying facilities. Section 210 of PURPA requires that electric
utilities offer to purchase power produced by co-generation or small power producers that obtain
qualifying facility (QF) status under Section 201. Under the implementing rules and regulations
of the Federal Energy Regulatory Commission (FBRC), the rate a QF is to receive for the sale of
its power is generally referred to as the "avoided cost" rate, the incremental cost to an electric
utility of electric energy or capacity or both which, but for the purchase from the QF, such utility
would generate itself or purchase from another source. 18 C.F.R. § 292.101 (b)(6).
The Commission finds that the $42.92IMWh levelized purchase price for the Potlatch
"base generation amount" (62 aMW) is a reasonable approximation of Avista's avoided cost and
was correctly calculated under the Commission approved IRP-based avoided cost methodology.
Reference Order No. 26576. We further find the 10-year contract term beginning July 1, 2003 to
be reasonable. Locking in the purchase rate for that term, we find, provides benefit to the -
Company, its Idaho customers and Potlatch.
We find the proposed market pricing method of Excess Generation amounts to be
reasonable and consistent with comparable rates paid by other electric utilities. Also reasonable
are the related 5 aMW operating year limit on Excess Generation and the $55 per MWh price
cap. The third component of the Purchase Agreement is Incremental Generation. This
generation is also market-based and is priced in a manner that we find reasonable. With market-
based pricing, we find that the potential purchase of both Excess and Incremental Generation
will provide benefit to the Company and its Idaho customers.
Power Sales (Power Deliveries to Potlatch)
The Agreement provides that Avista will provide electric service to Potlatch under
the terms and conditions of the Company's existing extra large general service Schedule 25
tariff. Schedule 25 is a default rate for a customer as large as Potlatch. The Company's tariffs
envision that a customer whose demand exceeds 25 MW will be served under a special contract.
The Agreement allows either party in the context of a future proceeding to argue that Potlatch's
service should be priced at rates other than Schedule 25 rates. Agreement § 5(b). Avista has
informed the Commission of its intent to file a general rate case in early 2004. Absent further
analysis and study Staff contends that Schedule 25 is the most appropriate proxy to reflect
ORDER NO. 29418 9
Potlatch's embedded cost of service. Until the service rates for Potlatch are otherwise
determined, the Commission finds that it is reasonable to serve Potlatch under Schedule 25. As a
Schedule 25 tariff customer, Potlatch is subject to all the same rate adjustments applicable to
other Schedule 25 customers.
Jurisdictional Allocation/Cost Recovery
The jurisdictional allocation method proposed by the Company is a departure from
historical allocation. What is proposed is the allocation of 100% of Potlatch power purchase
costs to Idaho. Without changing the allocation methodology, power purchase costs would be
treated as generation and based on the jurisdictional weighting of demand and energy shared
between Washington (67%) and Idaho (33%).
Avista and its Idaho customers have long benefited from Potlatch's self-generation
capability. Prior to 1992 and from January 1, 2002 through June 30, 2003, Potlatch used its
generation to reduce its load requirement while purchasing the remainder from Avista. From
1992 to 2002 Idaho received a net benefit from the Potlatch contract.
Avista contends that its proposed allocation of Potlatch power purchase costs is
appropriate because Idaho realizes all the benefit of Potlatch's 100 MW of load and Schedule 25
revenue. Additional secondary benefits cited by the Company as accruing to Idaho and its
citizens from Potlatch's continued operation in Lewiston are the benefits from continued
employment, a bolstered tax base and economic spin-off benefits for other businesses.
As further justification for the proposed treatment of power purchase costs, the
Company notes that the Washington Utilities and Transportation Commission (WUTC) takes a
much different view of PURPA purchases than the Idaho Commission. Avista contends that the
Agreement eliminates potential inter-jurisdictional disputes. The submitted Agreement, the
Company contends, is an Idaho solution to an Idaho problem. While we appreciate the
Company's perspective, we believe it is fair to recognize also that a utility operating in multiple
jurisdictions has voluntarily assumed regulatory challenges and the related risk of disparate
treatment.
Until such time as the purchase contract is reflected in base rates, the Company
proposes to defer 100% of the power purchase costs for recovery in its Idaho PCA. We note that
the generators owned by Potlatch are PURPA qualifying facilities. The purchase by Avista is
obligatory and mandated by federal law and FERC regulations, i.e., 18 C.F.R. § 292.303. We
ORDER NO. 29418 10
have always treated purchases from PURPA QFs as non-discretionary and have authorized
recovery of contract costs. The $42.92 per megawatt hour purchase price set forth in the
Agreement for 62 aMW of annual base generation we find is just and reasonable and a good
approximation of the Company's avoided cost. 18 C.F.R. § 292.304. The additional excess and
incremental energy offered by Potlatch we find are also PURPA purchases. Potlatch is a unique
customer of Avista with long and strong economic ties to Idaho. As Staff notes, from a practical
standpoint, someone must pay the difference between serving Potlatch at embedded cost and
purchasing Potlatch generation at marginal cost. While not choosing to speculate what the
Washington Commission would do if presented with this Agreement, we find the Company's
allocation proposal on the facts presented to be one of fairness and equity. As the benefits and
revenue of Potlatch accrue to Idaho, so too, we find, should the related costs. Accordingly, we
find it reasonable to approve the proposed allocation and method of power purchase cost
recovery. In approving the requested recovery method, we authorize the booking of Avista's
power purchase costs in the Company's PCA deferral account. Recovery of Potlatch power
purchase costs by the Company will require a rate case or PCA filing.
Settlement ofAll Known Existing Disputes
Part of the mutual consideration recited in the Joint Petition is the settlement of all
known existing disputes between the parties before the Idaho Commission and Idaho Courts.
Joint Petition ¶ 11(b). Specifically mentioned in the Agreement are Potlatch's complaint in
Idaho U.S. District Court, Case No. CV02-543-C-EJL alleging that Avista violated the terms of
the 1992 Avista/Potlatch Agreement and Potlatch's complaint in Commission Case No. AVU-E-
02-8 alleging that Avista had refused to purchase the co-generation output of the Lewiston plant.
Agreement § 31. The Commission acknowledges that the Agreement by its terms intends to put
an end to all existing litigation between the parties. We find that in addition to the cases cited,
the Agreement also finally concludes Commission Case No. AVTJ--01-5, a Potlatch Petition
regarding the purchase of power from Avista.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Avista Corporation dba
Avista Utilities, an electric utility, pursuant to the authority granted the Commission in Idaho
Code, Title 61 and the Public Utility Regulatory Policies Act of 1978 (PUIRPA).
ORDER NO. 29418 11
The Commission has authority under PURPA 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 and as more particularly described above, IT IS
HEREBY ORDERED and the Commission does hereby approve the Power Purchase and Sale
Agreement (Agreement) between Avista and Potlatch dated July 22, 2003.
IT IS FURTHER ORDERED and the Commission hereby authorizes the booking of
all power purchase costs paid by Avista to Potlatch under the Agreement in the Company's
Power Cost Adjustment (PCA) deferral account. PCA recovery of Potlatch power purchase costs
is authorized until such costs are otherwise included in the Company's base rates.
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.
ORDER NO. 29418 12
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this /S'
day of January 2004.
PAUL KJE L;L ER, SIDENT
rJ191 ~U
MARSHA H. SMITH, COMMISSIONER
ATTEST:
fJfJJ
J(n D. Jewell Q C&nmission Secretary
bls/O:AVUE0307_sw
ORDER NO. 29418 13
THE LAW OFFICE OF
PAINE, HAMBLEN, COFFIN, BROOKE & MILLER LLP
717 WEST SPRAGUE AVENUE
SUITE 1200
SPOKANE, WASHINGTON 99201-3505
[phone]
FAX: [phone]
R Blair Strong www.painehamblerL.com S
Partner - ;—a

'- cit c;.
August 22, 2003
(-fl:
Ms. Jean Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
Boise, ID 83720-0074
Via Fedex
Re: Potlatch Corporation v. Avista Utilities
IPUC Docket No. AVU-E-02-08
Dear Ms. Jewell:
Enclosed please find an original plus seven (7) copies of Avista Corporation and Potlatch
Corporation's Joint Petition in the above-referenced matter.
Please acknowledge receipt by date-stamping the additional copy enclosed and return to me
in the self-addressed stamped envelope.
Should you have any questions regarding this filing, please do not hesitate to call me at
[phone]. Thank you in advance for your assistance.
Enclosures
cc: David Meyer (w/encl.)
Conley Ward (w/encl.)
Pamela Mull (w/encl.)
I:\Spodocs\l 1 150\03086\1tr00132887.WPD
Very truly yours,
PAINE, HAMBLEN, COFFIN,
BROOKE & MILLER LLP
R. Blair Blair Strong Li
A limited Liabiy Partnerthip
Paine Hamblen Spokane • Paine Hamblen Spokane Valley • Paine Hamblen Tn-Cities • Paine Hamblen Coeur d'Alene
David J. Meyer
Senior Vice President and General Counsel
Avista Corporation
1411 East Mission Avenue
P.O. Box 3727
Spokane, WA 99220
Telephone: [phone]
Facsimile: [phone]
R. Blair Strong
Paine, Hamblen, Coffin,
Brooke & Miller LLP
717 West Sprague Ave., Suite 1200
Spokane, WA 99201
Telephone: [phone]
Facsimile: [phone]
For Avista Corporation
Pamela Mull
Associate General Counsel
Potlatch Corporation
601 W. Riverside Ave., Suite 1100
Spokane, WA 99201
Telephone: [phone]
Facsimile: [phone]
Conley E. Ward
Givens Pursley LLP
277 N 6th Street, Suite 200
P.O. Box 2720
Boise, ID 83701
Telephone: [phone]
Facsimile: [phone]
For Potlatch Corporation
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT
PETITION OF AVISTA CORPORATION
AND POTLATCH CORPORATION FOR
APPROVAL OF POWER PURCHASE
AND SALE AGREEMENT
-
r
CASE No. AVLJ-E-02M8 7
JOINT PETITION Ln CD
Avista Corporation ("Avista") and Potlatch Corporation ("Potlatch") (Avista and
Potlatch are referred to collectively as the 'Parties") hereby petition the Idaho Public
Utilities Commission ("Commission" or "]PUC") for an order approving the Power
Purchase and Sale Agreement between Avista Corporation and Potlatch Corporation
dated July 22, 2003 ("Purchase and Sale Agreement") which is attached as Exhibit 1. In
support of this Petition, the Parties state as follows:
JOINT PETITION - I
1.Avista is a corporation created and organized under the laws of the State
of Washington with its principal office in Spokane, Washington. Avista is an investor-
owned utility principally engaged in the business of providing electric and natural gas
service in the states of Idaho and Washington, as well as natural gas service in the states
of Oregon and California.
2.Potlatch is a Delaware corporation that operates a wood pulp, paperboard,
tissue and wood products manufacturing facility in Lewiston, Idaho (hereinafter referred
to as the "Lewiston Plant").
3.Potlatch owns and operates four generators at the Lewiston Plant that are
capable of generating approximately 130 megawatts of energy. These generators are
Qualifying Facilities ("QF") pursuant to the Public Utility Regulatory Policies Act of
1978, Pub. L. No. 95-617, 92 Stat. 3117 (1978) ("PURPA") and 18 C.F.R. Part 292
(2003).
4.Avista (formerly known as The Washington Water Power Company) has
provided electric service to the Lewiston Plant for many years. Beginning on January 1,
1992, Avista purchased the Lewiston Plant generation output and provided electric
service to the Lewiston Plant pursuant to an Electric Service and Purchase Agreement
Between Potlatch Corporation and The Washington Water Power Company ("1992
Agreement"). The Commission approved the 1992 Agreement in IPUC Case No. WWP-
E-91-5, Order No. 23858 on August 16, 1991.
5.The 1992 Agreement had an expiration date of December 31, 2001 and
contained no provisions regarding rates, terms or conditions for service alter this
JOINT PETITION -2
expiration date. Accordingly, prior to the expiration of the 1992 Agreement, the Parties
met on a number of occasions to attempt to negotiate a successor agreement.
6.The Parties were not able to reach agreement on a successor agreement
and Potlatch filed a Petition with the Commission on March 23, 2001 for an order
determining the terms and conditions for Potlatch's purchase of electricity from Avista,
Case No. AVIJ-E-01-05. The Commission set Potlatch's Petition for public hearing.
7.On August 17, 2001, Potlatch and Avista filed a Joint Motion for an order
vacating the hearing in Case No. AVU-E-01-05. The Parties also agreed that following
the expiration of the 1992 Agreement, Avista would serve the Lewiston Plant load at
Schedule 25 rates without prejudice to either Party's right to propose, or the Commission
to order in future rate proceedings, that Avista's service to Potlatch should be priced at
rates other than Schedule 25.
Since the expiration of the 1992 Agreement on December 31, 2001,
Potlatch has used its Lewiston Plant generation to serve its Lewiston Plant load and
Avista has served the balance of the Lewiston Plant load at Schedule 25 rates.
9.On November 25, 2002, Potlatch filed a complaint in the United States
District Court for the District of Idaho, Case No. C1V02-0543-C-EJL, alleging that
Avista had violated certain terms of the 1992 Agreement.
10.On December 24, 2002, Potlatch filed a Compliant with the Commission
against Avista, Case No. AVU-E-02-08, alleging that Avista had refused to purchase the
cogeneration output of the generation facilities at the Lewiston Plant.
11.The Parties have now reached agreement on a power purchase and sale
agreement that settles the issues raised in the various pending IPUC proceedings and the
JOINT PETITION -3
litigation in Federal Court regarding electric service at Potlatch's Lewiston Plant. The
Purchase and Sale Agreement provides for both the purchase of the output of Potlatch's
generation at the Lewiston Plant and for the sale of energy to serve Potlatch's load at the
Lewiston Plant. In summary, the essential terms of the Agreement are as follows:
(a)The Purchase and Sale Agreement is for a ten-year term, beginning
July 1, 2003 and ending June 30, 2013.
(b)The Purchase and Sale Agreement is conditioned upon approval by
this Commission of: (i) approval of the Purchase and Sale Agreement as a settlement of
all known existing disputes between the Parties, without precedential value and without
prejudice to the Parties' positions on similar issues in the future; (ii) direct assignment of
all power purchase costs paid by Avista to Potlatch under the Purchase and Sale
Agreement to Avista's Idaho operations; and (iii) deferral and recovery of 100% of all
power purchase costs paid by Avista to Potlatch under the Purchase and Sale Agreement
to Avista's Idaho Power Cost Adjustment ("PCA") or otherwise recovered by Avista
through base rates.
(c)Avista will be the sole purchaser of Potlatch's generation and such
purchase is intended to satisfy Avista's obligations to purchase power from the Lewiston
Plant pursuant to PURPA. Avista will pay Potlatch $42.92 per megawatt-hour for up to a
maximum Base Generation Amount of 543,120 megawatt-hours (544,608 during a leap
year) generated by Potlatch during each July 1 through June 30 period ("Operating
Year") of the Agreement. This amount is equivalent to 62 average megawatts and is
referred to in the Agreement as the "Base Generation Amount." Amounts generated by
Potlatch in excess of the maximum Base Generation Amount each Operating Year
JOINT PETITION -4
("Excess Generation Amounts") will either be purchased by Avista at 85% of the
applicable Mid-Columbia index price, with a price-cap of $55 per megawatt-hour, or
used by Potlatch to reduce its load requirements from Avista. The purchase of Potlatch's
Excess Generation Amounts by Avista is limited to 43,800 megawatt-hours (5 average
megawatts) each Operating Year.
Additionally, Potlatch has the capacity to generate additional amounts
("Incremental Generation Amounts") under certain circumstances. The Purchase and
Sale Agreement provides for the purchase by Avista of Incremental Generation Amounts,
under the terms and conditions specified in the Agreement.
(d) Avista will serve Potlatch's load requirements at Potlatch's
Lewiston Plant under its Extra Large General Service Schedule 25 rates, including all
applicable rate adjustments, unless the Commission issues an order in the future
authorizing different billing rates.
WHEREFORE, Avista and Potlatch respectfully request that the Commission
issue an order approving the Purchase and Sale Agreement, including provisions:
(1)approving the Purchase and Sale Agreement as a settlement of all known
existing disputes between the Parties, including without limitation, Case No. AVU-E-01-
05 and Case No. AVU-E-02-08, without precedential value and without prejudice to the
Parties' positions on similar issues in the future;
(2)directly assigning all power purchase costs paid by Avista to Potlatch
under the Purchase and Sale Agreement to Avista's Idaho operations; and
JOINT PETITION -S
(3) allowing deferral and recovery of 100% of all power purchase costs paid
by Avista to Potlatch under the Purchase and Sale Agreement to Avista's Idaho Power
Cost Adjustment ("PCA") or otherwise recovered by Avista through base retail rates.
The Parties request that the petition be processed by modified procedure, if the
Commission deems it appropriate.
DATED this 22nd day of August, 2003.

Potlatch Corporation Paine Hamblen, Coffin,
Brooke & Miller LLP
By: _____

7P cia Mull R. Blair Strong
A ociate General Counsel Attorneys for Avista Corporation
JOINT PETITION -6
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 22nd day of August, 2003, I caused to be
served a true and correct copy of the foregoing by the method indicated below, and
addressed to the following:
Ms. Jean Jewell, Secretary Conley Ward
Idaho Public Utilities Commission Givens Pursley LLP
472 West Washington Street 277 North 6tb Street, Suite 200
Boise, Idaho 83720-0074 P.O. Box 2720
Boise, Idaho 83701
U.S. Mail XXXXX U.S. Mail
Hand Delivery Hand Delivery
Facsimile Facsimile
XXXXX Overnight Mail Overnight Mail
Electronic Mail XXXXX Electronic Mail
R. Blair Blair Strong
00128415
JOINT PETITION -7
EXHIBIT I
to
JOINT PETITION
POWER PURCHASE AND SALE AGREEMENT
BETWEEN
AVISTA CORPORATION
AND
POTLATCH CORPORATION
INDEX TO SECTIONS
Section Em
1. Definitions .................................................................................................................................. 2
2. Representations............................................................................................................................ 6
3. Term of Agreement..................................................................................................................... 7 4. Power Purchases (Power Deliveries to Avista) ........................................................................... 9
5. Power Sales (Power Deliveries to Potlatch)................................................................................ 12
6. Operation of Facility.................................................................................................................... 13
7. Scheduling ................................................................................................................................... 15
8. Billing and Payments ................................................................................................................... 15
9. Metering...................................................................................................................................... 18
10. Termination of Agreement ................................. . ......................................................................... 18 11. Forced Outage and Form Majeure .............................................................................................. 19
12. Indemnity..................................................................................................................................... 20
13. Limitation of Liability ................................................................................................................ 22
14. Insurance ..................................................................................................................................... 23 15 Assignment ................................................................................................................................. 25 16. No Unspecified Third Party Beneficiaries .................................. ..................... ............................ 25
17. No Transmission Rights .............................................................................................................. 25
18. Benefits for Renewable Fuels ...................................................................................................... 25
19. Default ..............................................................................................................................
...... .....
26
20. Release by Avista ...................................................................................................................... 27 21 . Release by Potlatch ..................... ................................................................................................. 27 22. Governmental Authority ............................................................................................................. 28 23. Several Obligations...................................................................................................................... 28
24. Implementation ........................................................................................................................... 28
25. Non-Waiver ................................................................................................................................ 28
26. Entire Agreement and Amendment ............................................................................................. 29
27. Venue, Attorneys Fees and Choice of Law.................................................................................. 29
28. Compliance with Laws ............................................................................................................... 29
29. Confidentiality .................................................................. . ........................................................... 30
30. Notices......................................................................................................................................... 32
31. Settlement of Litigation............................................................................................................... 33 32. Exhibits........................................................................................................................................ 33
POWER PURCHASE AND SALE AGREEMENT
BETWEEN
AVISTA CORPORATION
AND
POTLATCH CORPORATION
INDEX TO SECTIONS
Section
1. Definitions .................................................................................................................................. 2 2. Representations ......................................................................... . ................................................. 6 3. Term of Agreement ..................................................................................................................... 7 4. Power Purchases (Power Deliveries to Avista) ........................................................................... 9 S. Power Sales (Power Deliveries to Potlatch)................................................................................ 12 6. Operation of Facility ...................................................................................................... . ............. 13 7. Scheduling ................................................................................................................................... 15 8. Billing and Payments ..................................................................................... . ............................. 15 9. Metering...................................................................................................................................... 18 10. Termination of Agreement.......................................................................................................... 18 11 . Forced Outage and Force Majeure.............................................................................................. 19 12. Indemnity ............................
........
................................................................................................. 20 13. Limitation of Liability ............................................................................................................... 22 14. Insurance ..................................................................................................................................... 23 15 Assignment ................................................................................................................................. 25 16. No Unspecified Third Party Beneficiaries ................................................................................... .25 17. No Transmission Rights .............................................................................................................. .25 18. Benefits for Renewable Fuels...................................................................................................... 25 19. Default ......................................................................................................................................... 26 20. Release by Avista ....................................................................................................................... 27 21 . Release by potlatch ...................................................................................................................... 27 22. Governmental Authority ............................................................................................................. 28 23. Several Obligations ...................................................................................................................... 28 24. Implementation ........................................................................................................................... 28 25. Non-Waiver ................................................................................................................................ 28 26. Entire Agreement and Amendment ............................................................................................. 29 27. Venue, Attorneys Fees and Choice of Law .................................................................................. 29 28. Compliance with Laws ............................................................................................................... 29 29. Confidentiality ............................................................................................................................. 30 30. Notices ....................................................................................................................... .... ............... 32 31 . Settlement of Litigation............................................................................................................... 33 32. Exhibits ........................................................................................................................................ 33
This Power Purchase and Sale Agreement ("Agreement") is entered into as of this
22Dd day of July, 2003, by and between POTLATCH CORPORATION ('Potlatch"), a
corporation organized and existing under the laws of the State of Delaware, and AVISTA
CORPORATION ("Avista") of Spokane, Washington, a corporation organized and existing
under the laws of the State of Washington, hereinafter sometimes referred to collectively as
"Parties" and individually as "Party."
WITNESSETH:
WHEREAS, Potlatch owns and operates pulp, paperboard, tissue and wood products
manufacturing plants in Nez Perce County, Idaho, herein collectively referred to as the "Lewiston
Plant;"
WHEREAS, Avista is presently supplying electric power to Potlatch at the Lewiston
Plant;
WHEREAS, Potlatch owns and operates four thermal electric generating units located at
the Lewiston Plant;
WHEREAS, there is pending before the United States District Court for the District of
Idaho, Case No. CV02-543-C-EJL, a complaint by Potlatch against Avista;
WHEREAS, there is pending before the Idaho Public Utilities Commission, Case No.
AVLJ-E-02-08, a complaint by Potlatch against Avista;
WHEREAS, the Parties desire to settle all litigation pending between them, pursuant to
the terms of this Agreement;
WHEREAS, Potlatch desires to sell, and Avista desires to purchase, the Net Facility
Power pursuant to the terms of this Agreement; and
WHEREAS, the Parties intend that, except for self generation by Potlatch to serve its
own Load, Avista shall be the sole purchaser of Net Facility Power and the sole supplier for
Potlatch Load.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
hereinafter set forth, the Parties agree as follows:
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1. DEFINITIONS. In addition to words defined elsewhere in this Agreement as signified
by initial capitalization, whenever used in this Agreement, exhibits and attachments hereto, the
terms below shall have the following meanings:
(a)"Bankrupt" With respect to either Party, when such Party (i) files a petition or
otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause
of action under any bankruptcy, insolvency, reorganization or similar law, or has any such
petition filed or commenced against it and such petition is not dismissed within sixty (60) days
after it is filed, (ii) makes an assignment or any general arrangement for the benefit of creditors,
(iii) otherwise becomes bankrupt or insolvent (however evidenced), (iv) has a liquidator,
administrator, receiver, trustee, conservator or similar official appointed with respect to it or any
substantial portion of its property or assets, or (v) is generally unable to pay its debts as they fall
due.
(b)"Base Generation Amount(s)" That amount of Net Facility Power, expressed in
megawatt-hours, less any Incremental Generation Amount, for each hour and delivered by
Potlatch to Avista. The maximum Base Generation Amount for any July through June 30th
period (any such period referred to as the "Operating Year") shall be 543,120 megawatt-hours
during a normal year or 544,608 megawatt-hours during a leap year.
(c)"Base Period Demand" The average kVa supplied during the 30-minute period of
maximum electricity use during the portion of the billing period up to and including the point
where the maximum Base Generation Amount is reached. Demand shall be calculated using a
rolling 30-minute demand interval with 5-minute sub-intervals.
(d)"Billing Period" That period which begins at 0000 hours on the first day of any month
during the term of the Agreement and ends at 2400 hours on the last day of such month.
(e)"Effective Date" The date this Agreement becomes effective pursuant to Section 3(a) of
this Agreement.
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M "Excess Generation Amount(s)" That amount of Net Facility Power, expressed in
megawatt-hours, generated by the Facility, less any Incremental Generation Amount, for each
hour that is in excess of the maximum Base Generation Amount of 543,120 megawatt-hours for
any Operating Year during a normal year or 544,608 megawatt-hours during a leap year.
(g)"Excess Period Demand" The average kVa supplied during the 30-minute period of
maximum electricity use during the portion of the billing period after the point where the
maximum Base Generation Amount is reached. Demand shall be calculated using a rolling 30-
minute demand interval with 5-minute sub-intervals.
(h)"Facility" The electric generating facilities, including all equipment and structures
necessary to generate and supply power, more particularly described at Exhibit C (Description of
the Facility).
(i)"Facility Service Power" Electric power used by the Facility during its operation for
station service, including, but not necessarily limited to pumping, generator excitation and
cooling, as further defined in Exhibit A.
(j)"Forced Outage" Any outage that either fully or partially curtails the electrical output
of the Facility caused by mechanical or electrical equipment failure, plant related structural
failure, or, unscheduled maintenance required to be performed to prevent equipment failure.
(k)"Good Industry Practice(s)" Good industry practice as defined in the Interconnection
Agreement, which definition is adopted by reference for purposes of this Agreement as though
set forth in full herein.
(1) "Governmental Authority" Any federal, state or local government, political
subdivision thereof or other governmental, regulatory, quasi-governmental, judicial, public or
statutory instrumentality, authority, body, agency, department, bureau, or entity or any arbitrator
with authority to bind a Party at law.
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(m)"Governmental Rule(s)" Any law, rule, regulation, ordinance, order, code, permit,
judgment, or similar form of decision of any Governmental Authority having the effect of law or
regulation.
(n)"Heavy Load Hours" ("HLH") The hours ending 0700 through 2200 Pacific
Prevailing Time, Monday through Saturday inclusive, excluding NERC holidays.
(o)"Incremental Generation Amount(s)" The amount of Net Facility Power expressed in
megawatt-hours for each hour that is in excess of the Nominal Generation Amount.
(p)"Index" The daily price expressed in dollars per megawatt-hour for firm energy as
published by Dow Jones for the Mid-Columbia point of delivery for the applicable Heavy Load
Hours or Light Load Hours. If prices for any hour are not published for the Mid-Columbia point
of delivery, Avista may extrapolate such prices using reasonable commercial judgment; provided
that Avista shall notify Potlatch in writing of any such extrapolation and the basis thereof. In the
absence of this index, a comparable publication of firm energy prices at Mid-Columbia shall be
used as mutually agreed to by the Parties.
(q)"Interconnection Agreement" The Generation Interconnection Agreement between
Potlatch and Avista.
(r)"Light Load Hours" ("LLH") All hours other than Heavy Load Hours.
(s)"Load" The hourly energy, expressed in megawatt-hours, consumed at Potlatch's
Lewiston Plant excluding Facility Service Power and Losses.
(t)"Losses" Electric power used by the Facility during its operation to transform or
transmit electric power to Points of Delivery. Losses shall be deemed to be 200 kW.
(u)"Net Facility Power" Electric power generated by the Facility and measured at the point
of generation less Facility Service Power and less electric power used to compensate for Losses.
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If any adjustment to the meter readings is required hereunder to determine the Net Facility Power
actually delivered to the Points of Delivery, the electric power which the Parties agree is used by
the Facility in its operation and losses to the Points of Delivery is set forth in Exhibit A.
(v)"Nominal Generation Amount(s)" A calculation to be performed daily and shall be the
same for each hour of that day, but only used when the Parties execute a Power Purchase of
Incremental Generation Amounts, to be determined as follows: The amount of electric power
generated by the Facility, expressed in megawatts per hour, determined by averaging the hourly
Net Facility Power generation amounts less any Power Purchases of Incremental Generation
Amounts for each hour for the immediate past period counting backwards beginning two (2) days
prior to the current day and consisting of thirty (30) days, not necessarily contiguous, in which
the average Net Facility Power was greater than 720 megawatt-hours for each of these days (30
aMW). The Nominal Generation Amount shall be not less than fifty-five (55) megawatts per
hour. The Nominal Generation Amount shall be calculated as of the date of any transaction for a
Power Purchase of Incremental Generation Amounts and shall be the same amount for each hour
during the term of such transaction. If the Power Purchase transaction for an Incremental
Generation Amount is a prescheduled transaction, then the Nominal Generation Amount
calculation will serve to set the Base Generation Amount or Excess Generation Amount for the
duration of the Incremental Generation Transaction Period, and any Net Facility Power above
that amount shall be deemed the Incremental Generation Amount. The "Incremental Generation
Transaction Period" shall be all hours of each of the days specified for delivery of Incremental
Generation Amounts that are part of a single prescheduled transaction which is also the first such
transaction executed by the Parties for Incremental Generation Amount deliveries during those
same days. The Incremental Generation Amount shall be set equal to zero for the purpose of
calculating Base Generation Amounts (as defined in Subsection 1(b)), Excess Generation
Amounts (as defined in Subsection 1(t)), and Nominal Generation Amounts during those hours
in which no Incremental Generation Amount is purchased by Avista, in accordance with
Section 4.
(w)"Pacific Prevailing Time" The Pacific Time, either standard time or daylight savings
time, whichever is in effect at the relevant time.
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(x) "Points of Delivery" The locations where the Facility is electrically interconnected with
Avista's electrical system
(y)"Power Purchase(s)" Power transactions in which Avista purchases from Potlatch
electric power generated by the Facility.
(z)"Power Sale(s)" Power transactions in which Potlatch purchases electric power from
Avista.
(aa) "True-up Process" That process described in Section 3(1) for settling obligations
incurred under this Agreement in the event of termination.
(bb) "Week" The period of time beginning at 0000 hours on any Sunday during the term of
this Agreement and ending at 2400 hours on the immediately subsequent Saturday.
2. REPRESENTATIONS.
(a)Potlatch represents that it is the sole owner of the Facility, that all licenses or permits
required for the operation thereof have been or will be obtained in the name of, or assigned to
Potlatch, prior to the Effective Date and that the undersigned is authorized to execute this
Agreement in Potlatch's behalf. Potlatch also represents that each generating unit described at
Exhibit C (Description of the Facility) is a qualifying facility ("Qualifying Facility") pursuant to
law and the rules of the Federal Energy Regulatory Commission.
(b)Each Party represents and warrants to the other:
(1)subject to the provisions of Subsections 3(b) and 3(c), it has all authorizations
from Governmental Authority necessary for it to legally perform its obligations under this
Agreement or will obtain such authorizations in a timely manner prior to the time at which any
performance by it requiring such authorizations becomes due;
(2)the execution, delivery and performance of this Agreement are within its statutory
and corporate powers, have been duly authorized by all necessary action and do not violate any of
the terms or conditions in its governing documents, any material contract to which it is a party or
by which it or any of its properties may be affected or bound, or any Governmental Rule
applicable to it;
(3)this Agreement constitutes a legal, valid and binding obligation of the Party
enforceable against it in accordance with its terms, and the Party has all rights such that it can
and shall perform its obligations to the other Party in conformance with the terms and conditions
of this Agreement, subject to bankruptcy, insolvency, reorganization and other laws affecting
creditor's rights generally and general principles of equity;
(4)no Bankruptcy is pending against it, being contemplated by it, or to its knowledge
threatened against it; and
(5)subject to the provisions of Subsections 3(b) and 3(c) there are no suits,
proceedings, judgments, rulings or orders by or before any Governmental Authority that could
reasonably be expected to have a material adverse effect on its ability to perform this Agreement.
3. TERM OF AGREEMENT.
(a)Subject to the provisions of this Section 3, this Agreement shall be effective at 0000
hours on July 1, 2003. Power Purchases and Sales pursuant to this Agreement shall be deemed
to have commenced upon the Effective Date.
(b)Potlatch and Avista shall jointly petition the Idaho Public Utility Commission ("IPUC")
for an order approving this Agreement. This Agreement is conditioned upon approval by the
1PUC of the following provisions:
(1)approval of the Agreement as a settlement of all known existing disputes between
the Parties, without precedential value and without prejudice to the Parties' positions on similar
issues in the future;
(2)direct assignment of all Power Purchase costs paid by Avista to Potlatch under
this Agreement to Avista's Idaho operations; and
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(3) deferral and recovery of 100% of all Power Purchase .costs paid by Avista to
Potlatch under this Agreement to Avista's Idaho Power Cost Adjustment ("PCA") or otherwise
recovered by Avista through base rates.
In the event that the IPUC does not approve the Agreement or approves it upon
conditions that are unacceptable to Avista or Potlatch in their sole discretion, the Agreement
shall terminate upon the date of such order, subject to the True-Up Process described below.
After IPUC initial approval of this Agreement, should the IPUC revise regulatory
treatment of the Agreement in a manner unacceptable to Avista or Potlatch in their sole
discretion, the Agreement shall terminate upon the date of such order, without being subject to
the True-Up Process described below.
(c)This Agreement is conditioned upon the execution and filing with the Federal Energy
Regulatory Commission ("FERC") of the Interconnection Agreement between Avista and
Potlatch within sixty (60) days of the Effective Date of this Agreement. In the event that FERC
does not approve the Interconnection Agreement or approves it upon conditions that are
unacceptable to Avista or Potlatch in their sole discretion, this Agreement shall terminate upon
the date of such order, subject to the True-Up Process described below.
(d)In the event that any third person requests rehearing of an order of the IPUC that approves
the Agreement or appeals an order of the IPUC that approves this Agreement to a court of
competent jurisdiction, the Agreement shall terminate upon the date of an order on rehearing or
order on appeal that disapproves the Agreement or approves it upon conditions that are
unacceptable to Avista or Potlatch in their sole discretion, subject to the True-Up Process
described below.
(e)In the event this Agreement is not finally approved by December 31, 2003, neither Party
shall have any further obligations hereunder, and this Agreement shall terminate, subject to the
True-Up Process described below.
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(f)True-Up Process: In the event that this Agreement is terminated pursuant to
Subsections 3(b) through 3(e) except as otherwise provided, the Parties agree to refund amounts
paid and received hereunder that exceed amounts that would have been paid and received had
this Agreement not taken effect from the Effective Date to the date of termination ("Interim
Period"). Such refund amounts shall be calculated as the difference between the amounts paid
and received hereunder and the amounts that would have been paid and received if Potlatch had
utilized its Facility to generate electricity for its own Load at the Lewiston Plant during the
Interim Period and purchased its remaining electricity requirements at Schedule 25 rates. If the
amount of electricity generated by the Facility exceeds the Load at the Lewiston Plant during the
Interim Period, Avista shall be deemed to have purchased the amount in excess of the Load, and
such purchase shall be priced at the energy rates contained in Schedule 25, calculated for each
month of the Interim Period. Incremental Generation Amounts and prices paid therefor during
the Interim Period shall not be subject to this True-Up Process.
(g)This Agreement shall terminate at 2400 hours on June 30, 2013.
4. POWER PURCHASES (POWER DELIVERIES TO AVISTA).
(a)Potlatch shall sell and deliver and Avista shall purchase and accept delivery of Net
Facility Power in accordance with the terms and conditions of this Agreement. Such purchase by
Avista shall satisfy Avista's obligation to purchase power from the Facility pursuant to the Public
Utility Regulatory Policies Act for the term of this Agreement. All prices for Power Purchases
described in this Section 4 are all inclusive, and Avista shall not impose any charges or set-offs
for transmission, losses, ancillary services or other similar costs.
(b)Avista shall pay $42.92 per megawatt-hour for the Base Generation Amount generated by
the Facility each hour and delivered by Potlatch to Avista.
(c)Avista shall pay eighty-five percent (85%) of the applicable (}{LH or LLH) Index price
per megawatt-hour, up to a maximum price paid to Potlatch of $55 per megawatt-hour, for
WE
Excess Generation Amounts generated by the Facility each hour and delivered by Potlatch to
Avista. Potlatch may choose to not schedule and deliver Excess Generation Amounts to Avista
and instead supply electric power to the Load during any Week; provided, however, Potlatch
shall notify Avista of its election in accordance with Subsection 7(a) and such election shall be
binding for the Week. In the event Potlatch does not notify Avista of its election in accordance
with Subsection 7(a), Potlatch shall be deemed to have elected to supply the power to its Load
for the Week. Avista shall not pay Potlatch for such Excess Generation that is not scheduled and
delivered to Avista.
(d)The maximum Excess Generation Amount that Avista shall purchase for any Operating
Year shall be 43,800 megawatt-hours. Excess Generation Amounts in excess of the maximum
Excess Generation Amount shall be deemed used to serve Potlatch Load.
(e)Avista shall pay for Incremental Generation Amounts as set forth herein. Avista shall
make price offers for Incremental Generation Amounts to Potlatch, either upon its own initiative
or upon Potlatch's request, subject to Subsection 4(f) below. Prices offered by Avista shall
include all Avista costs, including but not limited to, unit contingency, transmission, losses,
ancillary services and other costs, but excluding third party transmission costs. Potlatch may
request a price offer from Avista on a prescheduled basis for Incremental Generation Amounts
consistent with Section 7. Unless the Parties otherwise agree, Avista using reasonable
commercial efforts, shall provide a price offer which shall be eighty-five percent (85%) of a unit
contingent sale price that Avista is able to execute with a third party for the Incremental
Generation Amount that Potlatch will make available to Avista on a prescheduled basis. If
Avista is unable, after using reasonable commercial efforts to execute a unit contingent sale, or is
unwilling, using reasonable commercial judgement to execute a unit contingent sale, then Avista
shall not be obligated to offer a prescheduled price to Potlatch. Any Avista purchases of firm,
rather than unit contingent, Incremental Generation Amounts shall be subject to separate
negotiation and mutual agreement at the time of such purchases.
If the Parties are unable to mutually agree upon a prescheduled price for Incremental
Generation Amounts and Potlatch desires to sell Incremental Generation Amounts to Avista,
Potlatch may request a real-time price offer for the hour from Avista consistent with Section 7.
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Subject to Subsection 4(f) below, if the Parties are unable to mutually agree on a real-time price
for such hour, then Potlatch may elect, consistent with Section 7, to receive a price based on
eighty percent (80%) of the weighted average price of Avista's real-time hourly sales and
purchases for the hour in which the Parties agree that Avista will purchase Incremental
Generation Amounts. if Avista has no real-time hourly purchases or sales for the hour in which
Potlatch elects to sell Incremental Generation Amounts to Avista, then eighty percent (80%) of
the hourly real-time market price internally recorded by Avista based on information which
Avista generally discovers through its participation in the market shall be used as the price for the
Incremental Generation Amount for such hour.
(1) Avista shall use the same degree of care and effort to purchase and, if necessary, to resell
Incremental Generation Amounts as it uses in selling electric power from Avista owned
generating resources. Notwithstanding anything in this Agreement, Avista reserves the right to
refuse to purchase Incremental Generation Amounts due to commercially reasonable internal
policy limitations prohibiting purchases for resale or Governmental Rules prohibiting purchases
for resale. Avista shall make reasonable efforts to notify Potlatch in advance of such internal
policy limitations or Governmental Rules.
(g) With regard to a prescheduled purchase of an Incremental Generation Amount, at the time
of execution of the transaction, Avista shall provide Potlatch with a facsimile copy of the
transaction confirmation that shall include the mutually agreed upon price and estimated
Incremental Generation Amount as provided by Potlatch. With regard to a real-time purchase of
an Incremental Generation Amount, at the time of execution of the transaction, Avista shall
provide Potlatch with a voice confirmation of either the price or Potlatch's election to take the
calculated price, in accordance with Subsection 4(e). Potlatch shall provide a voice confirmation
of the estimated Incremental Generation Amount. Potlatch may call Avista's real-time scheduler
in the hour following the hour of delivery of the Incremental Generation Amount and Avista
shall provide the real-time market price internally recorded in accordance with Subsection 4(e)
for Potlatch's information purposes only.
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(h) Multiple Incremental Generation Amount transactions within a single hour: Should
the Parties enter into more than one transaction for delivery in any hour of Incremental
Generation Amounts, then the actual Incremental Generation Amounts produced by Potlatch's
Facility will be first committed to the transaction entered into on the earliest date and time and
the remaining actual Incremental Generation Amounts will be committed to the remaining
transactions in the order in which the Parties entered into those transactions.
5. POWER SALES (POWER DELIVERIES TO POTLATCH).
(a) Avista shall sell and deliver and Potlatch shall purchase and accept delivery of electric
power and energy required for Potlatch's Load at the Lewiston Plant for the duration of the
Agreement in accordance with the terms and conditions of this Agreement, Avista's Rules and
Regulations in effect with the IPUC, applicable tariff schedules and orders of the IPUC in effect
at the time electric power is delivered hereunder, as they may be changed from time to time, and
any other requirements imposed by law, provided:
(1)Avista shall not be obligated to provide to Potlatch Facility Service Power or
Losses; and
(2)Any demand charge assessed to Potlatch for periods in which Power Purchases are
made shall be based on either:
(i)The coincident hourly sum of (1) Net Facility Power produced by the
Facility (expressed in kilowatts) and (2) electric power (expressed in kilowatts) that flows from
Avista's electric system to the Potlatch Load added vectonly to only the reactive power
("kVARs") that flows from Avjsta's electric system to the Potlatch Load during periods when
Avista purchases from Potlatch either Base Generation Amounts or Excess Generation Amounts,
or;
(ii)The coincident hourly sum of (1) Incremental Generation Amounts
produced by the Facility (expressed in kilowatts) and (2) electric power (expressed in kilowatts)
that flows from Avista's electric system to the Potlatch Load added vectorily to only the reactive
power ("kVARs") that flows from Avista's electric system to the Potlatch Load during periods
when Potlatch elects to use Excess Generation Amounts to serve its Load.
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Reactive power produced by the Facility as described in either of the cases under
Subsection 5(a)(2)(i) or 5(a)(2)(ii) above shall not be included in the demand calculation.
(3) Any demand charge assessed to Potlatch for periods in which no Power Purchases
are made shall be based only on kilowatts that flow from Avista's electric system to the Potlatch
Load added vectorily to only the reactive power that flows from Avista's electric system to the
Potlatch Load.
(b) Avista shall bill for all electric power delivered by Avista for Potlatch's Load at the rates
set forth in Avista's Extra Large General Service Schedule 25, including all adjustments thereto,
unless and until such time as the IPUC issues an order authorizing Avista to bill at a different
rate. Nothing shall prejudice any Party's right to propose, or the Commission to order, in future
proceedings that Potlatch's service should be priced at rates other than Schedule 25 rates. This
Agreement shall not be construed as restricting the right of either Party to petition the IPUC to
establish, disestablish, amend or alter Avista's Rules and Regulations in effect with the IPUC,
applicable tariff schedules and orders of the IPUC, including but not limited to Schedule 25.
6. OPERATION OF FACILITY.
(a)Potlatch shall construct, operate and maintain the Facility and associated electrical
equipment in compliance with Qualifying Facility status and in accordance with applicable laws
and regulations and in accordance with Good Industry Practice. Potlatch shall construct, operate
and maintain the Facility and other equipment associated with the Lewiston Plant at its own risk
and expense. Avista shall construct, operate and maintain its interconnection facilities, that
portion of its system that is interconnected to the Facility, and all equipment needed to receive
and transmit electric power in accordance with applicable laws and regulations and in accordance
with the Interconnection Agreement and Good Industry Practice.
(b)Interconnection of electrical systems under this Agreement shall be governed by the
Interconnection Agreement. Nothing herein is intended to amend or alter the Interconnection
Agreement as it may be amended or superceded. In the event that the Interconnection Agreement
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is superceded or amended as a consequence of a lawful order of the Federal Energy Regulatory
Commission, or other agency or court having jurisdiction thereof, the Parties agree to negotiate in
good faith such amendments to this Agreement as are necessary to preserve the intent of this
Agreement. Subject to Governmental Rules, in the event of a conflict between the terms of this
Agreement and the Interconnection Agreement, the terms of this Agreement shall take
precedence.
(c)Exhibit B (Communications), attached hereto, shall govern communications between
Potlatch and Avista for purposes of this Agreement.
(d)Potlatch shall provide Avista as much notice as is reasonably practicable under the
circumstances in the event of any planned increase to or reduction in its Load of more than
10,000 kilowatts. Potlatch shall also provide as much notice as is reasonably practicable under
the circumstances of any planned outages of the Facility and any planned increase or reduction of
generation from the Facility of more than 10,000 kilowatts. The notices shall specify the amount
and the expected duration of such outages, increases and reductions.
(e)Potlatch shall use its best efforts to maintain its Load on Avista's electric system (at the
Points of Delivery) at a power factor of 95% or higher throughout the term of this Agreement.
Avista shall not be liable for any loss or damage incurred by Potlatch resulting solely from
Potlatch's failure to maintain a power factor of 95% or higher.
(t) The Parties acknowledge that Avista's electric power system and delivery facilities, under
certain circumstances, may constrain power deliveries to Potlatch's Lewiston Plant. Potlatch
shall notify Avista of any intention to increase its energy and demand requirements at the
Lewiston Plant beyond the capacity of Avista's facilities. The Parties shall negotiate in good
faith the terms and conditions of a mutually acceptable separate agreement to install additional
facilities required to accommodate additional energy and demand requirements, subject to
approval by the IPUC and consistent with FERC rules and regulations.
(g) Potlatch agrees to adhere to IEEE 519 guidelines for power quality.
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7. SCHEDULING.
(a)General Scheduling: Potlatch shall submit to Avista pre-schedulers its estimated hourly
schedules for Base Generation Amounts, Excess Generation Amounts, and Load for each Week,
and shall make commercially reasonable efforts to deliver electric power as scheduled. Potlatch
shall also indicate, pursuant to Subsection 4(c), whether it will sell Excess Generation Amounts
to Avista or elects to instead supply Excess Generation Amounts to its Load for the Week.
Potlatch shall insure that such submission is received by Avista no later than 1700 hours Pacific
Prevailing Time of the second-to-the-last business day observed by both Parties of the Week
preceding the Week to be pre-scheduled by facsimile or other similar written form. Potlatch
shall also call Avista's real-time scheduler as soon as practical if there are material changes to
expected generation amounts or Load.
(b)Day-Ahead Incremental Generation Amount Scheduling Estimates: Potlatch shall
submit to Avista's pre-schedulers its best estimates of hourly Incremental Generation Amounts by
0600 hours Pacific Prevailing Time on the business day observed by both Parties immediately
preceding the day or days on which electric power is to be delivered, unless otherwise mutually
agreed by the Parties.
(c)Real-Time Incremental Generation Amount Schedules: Potlatch shall contact Avista
real-time schedulers no earlier than two hours and not later than one hour prior to the hour in
which power is to be delivered to communicate its best estimate of hourly Incremental
Generation Amounts and any material change in expected electric power deliveries or changes in
Load.
8. BILLING AND PAYMENTS.
(a) So long as there are Power Sales made and/or payments due hereunder, Avista shall
prepare monthly an itemized billing of the payment due, including the amounts of Power
Purchases, Power Sales, the appropriate rates, and any adjustments to the payment consistent
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with the provisions herein. Payments for amounts billed shall be received by the Party to be paid
on the due date, which shall be either the 20th day of the month following the Billing Period or
ten (10) days after receipt of the bill, whichever is later ("Due Date"). Payment shall be made at
the location designated by the Party to which payment is due. if the Due Date falls on a non-
business day of either Party, then the payment shall be due on the next following business day.
(b)Subject to Subsection (c) below, any payments by Avista to Potlatch or by Potlatch to
Avista, if not paid in full within the limitations set forth in Subsection (a), shall be late. In
addition to the other remedies for such an Event of Default pursuant to this Agreement, the late-
paying Party shall be assessed a charge for late payment equal to the lesser of one percent (1%)
per whole or partial month, or the maximum rate allowed by the laws of the State of Idaho per
whole or partial month multiplied by the overdue amount. Each Party shall have the right to
offset any amounts due it against any present payments owed to the other Party.
(c)If a Party in good faith disputes a bill prepared by the other Party, the disputing Party may
pay or withhold the amount in dispute. If a disputing Party elects to pay or withhold the amount
in dispute, it shall provide a written notice to the other Party at the same time that payment would
be normally due, which notice shall specifically set forth the basis of the dispute. The Parties
agree as soon as practicable to negotiate the dispute and failing negotiation, to otherwise resolve
the dispute in the most expeditious manner practicable. If the disputing Party elects to withhold
the disputed amount, and if the billing dispute is resolved in favor of the Party that prepared the
bill, the disputing Party shall pay to the billing Party the amount withheld with interest accrued at
the rate set forth in Subsection (b) above, multiplied by the withheld amount, prorated by months
and partial months from the original date that the amount should have been paid to the actual
date of payment. If the disputing Party elects to pay the disputed amount, and the billing dispute
is resolved in favor of the disputing Party, the Party that prepared the bill shall refund the
disputed amount to the disputing Party, with interest accrued at the rate set forth in Subsection
(b) above multiplied by the disputed amount, prorated by months and partial months from the
date that the amount was paid to the date of refund.
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(d)Potlatch may verify information used in preparing invoices by examining Avista
documents in its Spokane office for a period up to ninety (90) days after the billing date. All
information, records and reports related to Power Purchases or Power Sales under the terms of
this Agreement, and the calculation of prices therefor, will be open to inspection by Potlatch
upon reasonable notice and provided that Potlatch shall keep all such information confidential
and use it only for purposes of this Agreement, and further provided that in any enforcement
proceedings, Potlatch shall avail itself of procedures to protect the confidentiality of such
information under the applicable Governmental Rules.
(e)Avista shall prorate amounts billed to Potlatch for demand and other charges, in
accordance with the provisions of this Section, during the initial month of Power Purchases and
Power Sales under this Agreement if such purchases and sales commence on any day other than
the first day of the month, and during any Billing Period in which Potlatch elects to use Excess
Generation Amounts to serve the Load as permitted in Section 4(c). The Power Sales demand
quantities, expressed in kilovolt-amperes ("kVa") shall be prorated for the purposes of
calculating the demand charge for the applicable Billing Periods. For the applicable Billing
Periods, the prorated demand quantity components shall be calculated as follows: (1) Base
Period Demand, expressed in kVa, during that portion of the Billing Period in which Avista
made Power Purchases of Base Generation Amounts from Potlatch multiplied by the number of
days (rounded to the nearest whole day) in the Billing Period in which Avista made Power
Purchases of Base Generation Amounts from Potlatch and then divided by the total number of
days in the Billing Period; (2) Excess Period Demand, expressed in kVa, during that portion of
the billing period in which Avista made no Power Purchases other than Incremental Generation
Amounts from Potlatch multiplied by the number of days (rounded to the nearest whole day) in
the Billing Period in which Avista made no Power Purchases other than Incremental Generation
Amounts from Potlatch and then divided by the total number of days in the Billing Period; (3)
Excess Period Demand, expressed in kVa, during that portion of the Billing Period in which
Avista purchased Excess Generation Amounts from Potlatch multiplied by the number of days
(rounded to the nearest whole day) in the Billing Period in which Avista made Power Purchases
of Excess Generation Amounts from Potlatch and then divided by the total number of days in the
Billing Period. Prorated total demand quantity, expressed in kVa, is calculated from the
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arithmetic sum of (1), (2) and (3) above. The resultant total demand quantity shall be used for
calculation of the demand charge.
(1) Adjustments shall be made in billings for errors in a meter reading or in a billing
discovered within thirty-six (36) months of the error.
9. METERING.
(a)Metering shall be governed by the provisions of Exhibit A.
(b)Avista shall be responsible for any meter readings required by this Agreement.
10. TERMINATION OF AGREEMENT.
Subject to the Force Majeure provision of this Agreement, the Agreement may be terminated at
Avista's sole option, if any of the following conditions occur.
(a)Potlatch abandons the Facility or otherwise renders the Facility incapable of generating
electric power; or
(b)There have been no electric power deliveries to Avista from the Facility for a period of
twelve (12) consecutive months; or
(c)The electric power deliveries from the Facility to Avista fail to exceed 175,200 megawatt-
hours during any rolling period of twenty-four (24) consecutive months, which rolling period
commences any time after the first twelve (12) consecutive months following the Effective Date.
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11. FORCED OUTAGE AND FORCE MAJEURE.
(a) Neither Party shall be liable to the other Party for, or be considered to be in breach of or
default under this Agreement, on account of any delay in performance due to any of the following
events, which event or circumstance was not anticipated as of the Effective Date ("Force
Majeure"):
(1)Any cause or condition beyond such Party's reasonable control that such Party is
unable to overcome by the exercise of reasonable diligence, including but not limited to: fire,
flood, earthquake, volcanic activity, wind, drought and other acts of the elements; court order and
act of civil, military or governmental authority; strike, lockout and other labor dispute; riot,
insurrection, terrorism, sabotage or war; Governmental Rules; Forced Outage; breakdown of or
damage to facilities or equipment; electrical disturbance originating in or transmitted through
such Party's electric system or any electric system with which such Party's system is
interconnected; any interruption of transmission service required for the performance of this
Agreement that is excused by reason of force majeure or uncontrollable forces under a Party's
contract with a transmission service provider, and, any act or omission of any person or entity
other than such Party, and Party's contractors or suppliers of any tier or anyone acting on behalf
of such Party; or
(2)Any action taken by such Party which is, in the sole judgment of such Party,
necessary or prudent to protect the operation, performance, integrity, reliability or stability of
such Party's electric system or any electric system with which such Party's electric system is
interconnected, whether such actions occur automatically or manually.
(b) In the event of any Force Majeure occurrence, the time for performance thereby delayed
shall be extended by a period, of time reasonably necessary to compensate for such delay.
Nothing contained in this paragraph shall require any Party to settle any strike, lockout or other
labor dispute. In the event of a Force Majeure occurrence, which will affect performance under
this Agreement, the nonperforming Party shall provide the other Party written notice as soon as
practicable after the occurrence of the Force Majeure event. Such notice shall include the
particulars of the occurrence, assurances that suspension of performance is of no greater scope
and of no longer duration than is required by the Force Majeure and that best efforts are being
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used to remedy its inability to perform. The nonperforming Party shall remedy the Force
Majeure occurrence with all reasonable dispatch. The performing Party shall not be required to
perform or resume performance of its obligations to the nonperforming Party corresponding to
the obligations of the performing Party excused by the Force Majeure occurrence.
(c)Force Majeure does not include changes in the ownership, occupancy, or operation of the
Facility or Avista if such changes occur because of normal business occurrences which include
but are not limited to: changes in business economic cycles; recessions; bankruptcies; tax law
changes; sales of businesses; closure of businesses; changes in production levels; and, changes in
system operations.
(d)Force Majeure does not excuse any Party from making payments of money due under this
Agreement for power purchased prior to the Force Majeure event.
12. INDEMNITY.
(a) Potlatch's Duty to Indemnify. Potlatch shall indemnify, hold harmless and defend
Avista, and its officers, directors, employees, affiliates, managers, members, trustees,
shareholders, agents, contractors, subcontractors, affiliates' employees, invitees and successors,
from and against any and all third party claims, demands, suits, obligations, payments, liabilities,
costs, losses, judgments, damages and expenses (including the reasonable costs and expenses of
any and all actions, suits, proceedings, assessments, judgments, settlements, and compromises
relating thereto, reasonable attorneys' and expert fees and reasonable disbursements in connection
therewith) for damage to property, injury to any person or entity, or death of any individual,
including Avista's employees and affiliates' employees, Potlatch's employees, or any other third
parties, to the extent caused wholly or in part by any act or omission, negligent or otherwise, by
Potlatch or its officers, directors, employees, agents, contractors, subcontractors and invitees
arising out of or connected with Potlatch's performance or breach of this Agreement, or the
exercise by Potlatch of its rights hereunder; provided, however, that the provisions of this Section
shall not apply if any such injury, death or damage is held to have been caused by the sole
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negligence or intentional wrongdoing of Avista, its agents or employees. The foregoing
indemnification obligation shall not be limited in any way by workers' compensation laws or by
any limitation on the amount or type of damages, compensation or benefits payable by Potlatch
under applicable workers' compensation laws.
(b)Avista's Duty to Indemnify. Avista shall indemnify, hold harmless and defend Potlatch,
and its officers, directors, employees, affiliates, managers, members, trustees, shareholders,
agents, contractors, subcontractors, invitees and successors, from and against any and all third
party claims, demands, suits, obligations, payments, liabilities, costs, losses, judgments, damages
and expenses (including the reasonable costs and expenses of any and all actions, suits,
proceedings, assessments, judgments, settlements, and compromises relating thereto, reasonable
attorneys' and expert fees and reasonable disbursements in connection therewith) for damage to
property, injury to any entity or person, or death of any individual, including Potlatch's
employees and affiliates' employees, Avista's employees, or any other third parties, to the extent
caused wholly or in part by any act or omission, negligent or otherwise, by Avista or its officers,
directors, employees, agents, contractors, subcontractors and invitees arising out of or connected
with Avista's performance or breach of this Agreement, or the exercise by Avista of its rights
hereunder; provided, however, that the provisions of this Section shall not apply if any such
injury, death or damage is held to have been caused by the sole negligence or intentional
wrongdoing of Potlatch, its agents or employees. The foregoing indemnification obligation shall
not be limited in any way by workers' compensation laws or by any limitation on the amount or
type of damages, compensation or benefits payable by Avista under applicable workers'
compensation laws.
(c)Notice. A Party seeking indemnification under this Agreement ("First Party") shall give
the other Party ("Second Party") notice of the claim or action giving rise to a right of
indemnification as soon as practicable, but in any event on or before the thirtieth (30th) day after
the First Party's actual knowledge of such claim or action. The notice shall describe the claim or
action in reasonable detail, and shall indicate the amount (estimated if necessary) of the claim or
action. Any failure of the First Party to provide the notice required by this Section shall not
affect the First Party's rights to indemnification except to the extent the Second Party is actually
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and materially prejudiced as a result of such failure. Neither Party may settle or compromise any
claim for which indemnification is sought under this Agreement without the prior consent of the
other Party; provided, however, said consent shall not be unreasonably withheld or delayed.
Each Party's indemnification obligation shall survive expiration, cancellation or early termination
of this Agreement.
(d) Acknowledgment to Negotiation. POTLATCH AND AVISTA SPECIFICALLY
WARRANT THAT THE TERMS AND CONDITIONS OF THE FOREGOING
INDEMNITY PROVISIONS ARE THE SUBJECT OF MUTUAL NEGOTIATION BY
THE PARTIES, AND ARE SPECIFICALLY AND EXPRESSLY AGREED TO IN
CONSIDERATION OF THE MUTUAL BENEFITS DERIVED UNDER THE TERMS OF
THE AGREEMENT.
13. LIMITATION OF LIABILITY.
(a) Limitation of Liability. With respect to claims by and between the Parties under this
Agreement, the measure of damages at law or in equity in any action or proceeding shall be
limited to direct actual damages only. Such direct actual damages shall be the sole and exclusive
remedy and all other remedies or damages at law or in equity are waived and neither Party shall
be liable in statute, contract, in tort (including negligence), strict liability, warranty or under any
other legal theory or otherwise to the other Party, its agents, representatives, and/or assigns, for
any special, incidental, punitive, exemplary or consequential loss or damage whatsoever,
including, but not limited to, loss of profits or revenue for work not performed, for loss of use of
or under-utilization of the other Party's facilities, loss of use of revenues, attorneys' fees,
litigation costs, or loss of anticipated profits, resulting from either Party's performance or non-
performance of an obligation imposed on it by this Agreement, without regard to the cause or
causes related thereto, including the negligence of any Party. The Parties expressly acknowledge
and agree that this limitation shall not apply to any claims for indemnification under Section 12
of this Agreement. The provisions of this Section shall survive the termination or expiration of
this Agreement.
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(b) Limitation of Liability for WIS Parties. Notwithstanding the provisions of
Subsection (a) above, if both Avista and Potlatch are parties to the Western Interconnected
Systems Limitation of Liability ("WIS") Agreement, then the WIS Agreement shall control their
liabilities with respect to damages to the Facility, the interconnection facilities, or Avista's
electric system.
14. INSURANCE.
(a) General Liability. The Parties agree to maintain, at their own cost and expense, general
liability, workers' compensation, and other forms of insurance relating to their operations for the
life of this Agreement in the manner, and amounts, at a minimum, as set forth below.
(1)Workers' compensation insurance in accordance with all applicable state and
federal law, including Employer's Liability Insurance in the amount of $1,000,000 per
occurrence;
(2)Commercial General Liability Insurance, including Contractual Liability Coverage
for liabilities assumed under this Agreement, and Personal Injury Coverage in the minimum
amount of $5,000,000 per occurrence for bodily injury and property damage. Potlatch's policy
shall include Avista as an additional insured.
(3)Where a Party has more than $100 million in assets it may, at its option, self-
insure all or part of the insurance required in this Section 14; provided, however, the self-insuring
Party agrees that all other provisions of this Section 14, including, but not limited to, waiver of
subrogation, waiver of rights of recourse, and additional insured status, which provide or are
intended to provide protection for the other Party and its affiliated and associated companies
under this Agreement, shall remain enforceable. A Party's election to self-insure shall not impair,
limit, or in any manner result in a reduction of rights and/or benefits otherwise available to the
other Party and its affiliated and associated companies through formal insurance policies and
endorsements as specified in the above parts of this Section 14. The self-insuring Party agrees
that all amounts of self-insurance, retentions and/or deductibles are the responsibility of and shall
be borne by the self-insuring Party.
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(b) Certificates. Within fifteen (15) days of the Effective Date, and each anniversary of the
Effective Date, during the term of this Agreement, (including any extensions), each Party shall
provide to the other Party, properly executed and current certificates of insurance with respect to
all insurance policies required to be maintained by such Party under this Agreement. Certificates
of insurance shall provide the following information:
(1)Name of insurance company, policy number and expiration date;
(2)The coverage required and the limits on each, including the amount of deductibles
or self-insured retentions, which shall be for the account of the Party maintaining such policy;
(3)A statement indicating that the other Party shall receive at least thirty (30) days
prior written notice of cancellation or expiration of a policy, or reduction of liability limits with
respect to a policy; and
(4)A statement identifying and indicating that additional insureds have been named
as required by this Agreement.
(c) Policy Request. At a Party's request, in addition to the foregoing certifications, the other
Party shall deliver to the first Party a copy of applicable sections of each insurance policy.
(d) Inspection. Each Party shall have the right to inspect the original policies of insurance
applicable to this Agreement at the other Party's place of business during regular business hours.
(e) "Claims Made" Insurance. If any insurance is written on a "claims made" basis, the
respective Party shall maintain the coverage for a minimum of seven years after the termination
of this Agreement.
(1) Waiver of Subroaation. To the extent permitted by the insurer and commercially
reasonable, each Party shall obtain waivers of subrogation in favor of the other Party from any
insurer providing coverage that is required to be maintained under this Section 14. A Party shall
not be required to obtain a waiver of subrogation if the other Party is not able to obtain a waiver
of subrogation from its insurance carrier.
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15.ASSIGNMENT.
Neither Party shall voluntarily assign its rights or delegate its duties under this
Agreement, or any part of such rights or duties without the written consent of the other Party.
Such consent shall not unreasonably be withheld. Further, no assignment by either Party shall
relieve or release it to the extent of any of its obligations hereunder. Subject to the foregoing
restrictions on assignments, this Agreement shall be fully binding upon, inure to the benefit of
and be enforceable by the Parties and their respective successors, heirs and assigns.
16.NO UNSPECIFIED THIRD PARTY BENEFICIARIES.
Except as specifically provided in this Agreement, there are no third party beneficiaries of
this Agreement. Nothing contained in this Agreement is intended to confer any right or interest
on anyone other than the Parties, and their respective successors, heirs and assigns permitted
under Section 15.
17.NO TRANSMISSION RIGHTS.
Nothing in this Agreement shall be construed as granting Potlatch any right of access, or
any other rights, to Avista's transmission system.
18.BENEFITS FOR RENEWABLE FUELS.
Nothing in this Agreement shall affect Potlatch's rights to benefits attributable to
Potlatch's use of renewable fuels for generation. The Parties further agree to negotiate in good
faith should it be necessary at a later date, to develop a separate agreement in order to provide
Potlatch with those benefits.
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19. DEFAULT.
(a) An "Event of Default" shall mean, with respect to a Party (a "Defaulting Party"), the
occurrence of any of the following:
(1)the failure to make, when due, any payment required pursuant to this Agreement if
such failure is not remedied within three (3) business days after delivery of written notice;
(2)any representation or warranty made by such Party herein is false or misleading in
any material respects when made or when deemed made or repeated;
(3)the failure to perform any material covenant or obligation set forth in this
Agreement (except to the extent constituting a separate Event of Default) if such failure is not
remedied within thirty (30) business days after delivery of written notice;
(4)such Party becomes Bankrupt; or
(5)such Party consolidates or amalgamates with, or merges with or into, or transfers
all or substantially all of its assets to, another entity and, at the time of such consolidation,
amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all
the obligations of such Party under this Agreement to which it or its predecessor was a party by
operation of law or pursuant to an agreement reasonably satisfactory to the other Party.
(b) In the Event of Default, the following shall apply:
(1)The non-defaulting Party shall give written notice to the Defaulting Party of the
Event of Default in accordance with this Agreement.
(2)Except for an Event of Default that arises from failure to make money payments
or from a Party becoming bankrupt, if, after 30 days following receipt of such notice, the
Defaulting Party has not taken the steps necessary to cure the event of default, the non-defaulting
Party may, at its option, terminate this Agreement; provided, however, that except for the failure
to pay sums which are due and payable, if the defaulting Party, within such 30-day period,
commences and thereafter proceeds with all due diligence to cure such default, such 30-day
period shall be extended up to six (6) months after written notice to the defaulting Party, as may
be necessary to cure the event of default with all due diligence. For an Event of Default that
arises from the failure to make money payments, the non-defaulting Party may, at its option,
terminate this Agreement if the Defaulting Party shall have failed to cure the failure to pay within
IMM
three (3) business days following receipt of notice of such failure. For an Event of Default that
arises from a Party becoming bankrupt, the non-defaulting Party may, at its option, immediately
terminate this Agreement upon notice to the Defaulting Party.
(3) Upon the Event of Default and an expiration of any period to cure granted herein,
the non-defaulting Party may, but has no obligation, to terminate this Agreement effective upon
notice to the Defaulting Party and may exercise all other rights and remedies available to the non-
defaulting Party under applicable law. Whether or not the non-defaulting Party elects to
terminate this Agreement, it may, in addition to other remedies provided for herein, pursue such
remedies as are available at law or in equity including suspension of its performance so long as
the Event of Default is continuing and has not been cured.
(c) Any right or remedy afforded to either Party under any provision of this Agreement on
account of the breach or default by the other Party is in addition to, and not in lieu of, all other
rights or remedies afforded to such Party under any other provisions of this Agreement, by law or
otherwise on account of the breach or default.
20.RELEASE BY AVISTA.
Avista releases Potlatch from any and all claims, losses, harm, liabilities, damages, costs
and expenses to the extent resulting from any disconnection, interruption, suspension or
curtailment by Potlatch pursuant to terms of this Agreement.
21.RELEASE BY POTLATCH.
Potlatch releases Avista from any and all claims, losses, harm, liabilities, damages, costs
and expenses to the extent resulting from any disconnection, interruption, suspension or
curtailment by Avista pursuant to terms of this Agreement.
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22.GOVERNMENTAL AUTHORITY.
This Agreement is subject to the Governmental Rules now or hereafter in effect, of all
Governmental Authorities having jurisdiction over the Facility, this Agreement, the Parties or
either of them. All Governmental Rules that are required to be incorporated in agreements of this
character are by this reference incorporated in this Agreement.
23.SEVERAL OBLIGATIONS.
Except where specifically stated in this Agreement to be otherwise, the duties, obligations
and liabilities of the Parties are intended to be several not joint or collective. This Agreement
shall not be interpreted or construed to create an association, joint venture or partnership between
the Parties or to impose any partnership obligations or liability upon either Party. Each Party
shall be individually and severally liable for its own obligations under this Agreement. Further,
neither Party shall have any rights, power or authority to enter into any agreement or undertaking
for or on behalf of, to act as or to be an agent or representative of, or to otherwise bind the other
Party.
24.IMPLEMENTATION.
Each Party shall take such action (including, but not limited to, the execution,
acknowledgement and delivery of documents) as may reasonably be requested by the other Party
for the implementation or continuing performance of this Agreement.
25.NON-WAIVER.
The failure of either Party to insist upon or enforce strict performance by the other Party
of any provision of this Agreement or to exercise any right under this Agreement shall not be
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construed as a waiver or relinquishment to any extent of such Party's right to assert or rely upon
any such provision or right in that or any other instance; rather, the same shall be and remain in
full force and effect.
26.ENTIRE AGREEMENT AND AMENDMENT.
This Agreement together with its exhibits constitutes the entire agreement of the Parties
hereto and supersedes and replaces any prior agreements or understandings between said Parties,
entered into for the same or similar purposes, with the exception the Interconnection Agreement.
No change, amendment or modification of any provision of this Agreement shall be valid unless
set forth in a written amendment to this Agreement signed by both Parties.
27.VENUE, ATTORNEYS FEES AND CHOICE OF LAW.
Venue of any action filed to enforce or interpret the provisions of this Agreement shall be
exclusively in the United States District Court for the District of Idaho or the District Court of
the State of Idaho encompassing Nez Perce County and the Parties irrevocably submit to the
jurisdiction of any such court. In the event of litigation to enforce the provisions of this
Agreement, the prevailing Party shall be entitled to reasonable costs and attorney's fees in
addition to any other relief allowed. Notwithstanding conflict of law rules, the laws of the State
of Idaho shall apply to disputes arising under this Agreement.
28.COMPLIANCE WITH LAWS.
Both Parties shall comply with all applicable laws and regulations of Governmental
Authorities having jurisdiction over the Facility and the operations of the Parties.
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29. CONFIDENTIALITY.
(a) Definition. "Confidential Information" shall mean any confidential, proprietary or trade
secret information or a plan, specification, pattern, procedure, design, device, list concept, policy
or compilation relating to the present or planned business of a Party, which is designated in good
faith as confidential by the Party supplying the information, whether conveyed orally,
electronically, in writing, through inspection or otherwise, except that the real-time in-plant data,
shall be considered Confidential Information without the need for designation.
(b) General Obligations.
(1)Each Party shall hold in confidence any and all Confidential Information unless:
(i) compelled to disclose such information by Governmental Rules or as otherwise provided for
in this Agreement; or (ii) to meet obligations imposed by Governmental Authority or by
membership in NERC or WECC (including other transmission providers). Information required
to be disclosed under (i) or (ii) above, does not, by itself, cause any information provided by
Potlatch to Avista to lose its confidentiality. To the extent it is necessary for either Party to
release or disclose such information to a third party in order to perform that Party's obligations
herein, such Party shall advise said third party of the confidentiality provisions of this Agreement
and use its best efforts to require said third party to agree in writing to comply with such
provisions.
(2)During the term of this Agreement, and for a period of three (3) years after the
expiration or termination of this Agreement, except as otherwise provided in this Section 29,
each Party shall hold in confidence and shall not disclose to any person Confidential Information.
(3)Each Party shall use at least the same standard of care to protect Confidential
Information it receives as it uses to protect its own Confidential Information from unauthorized
disclosure, publication or dissemination.
(c) Excluded Information. Confidential Information shall not include information that the
receiving Party can demonstrate: (i) is generally available to the public other than as a result of
disclosure by the receiving Party; (ii) was in the lawful possession of the receiving Party on a
non-confidential basis prior to receiving it from the disclosing Party; (iii) was supplied to the
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receiving Party without restriction by a third party, who, to the knowledge of the receiving party,
after due inquiry was under no obligation to the disclosing party to keep such information
confidential; (iv) was independently developed by the receiving party without reference to
Confidential Information of the disclosing party; (v) is, or becomes, publicly known, through no
wrongful act or omission of the receiving Party or Breach of this Agreement; or (vi) is required,
in accordance with Subsection 29(d) of this Agreement, to be disclosed by any Governmental
Authority or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal
proceeding establishing rights and obligations under this Agreement. Information designated as
Confidential Information will no longer be deemed confidential if the Party that designated the
information as confidential notifies the other Party that it no longer is confidential.
(d)Subpoena. If a Governmental Authority or entity with the right, power, and apparent
authority to do so requests or requires either Party, by subpoena, oral deposition, interrogatories,
requests for production of documents, administrative order, or otherwise, to disclose Confidential
Information, that Party shall provide the other Party with prompt notice of such request(s) or
requirement(s) so that the other Party may seek an appropriate protective order or waive
compliance with the terms of this Agreement. The notifying Party shall have no obligation to
oppose or object to any attempt to obtain such production except to the extent requested to do so
by the disclosing Party and at the disclosing Party's expense. If either Party desires to object or
oppose such production, it must do so at its own expense. The disclosing Party may request a
protective order to prevent any Confidential Information from being made public.
Notwithstanding the absence of a protective order or waiver, the Party may disclose such
Confidential Information which, in the opinion of its counsel, the Party is legally compelled to
disclose. Each Party shall use reasonable efforts to obtain reliable assurance that confidential
treatment will be accorded any Confidential Information so furnished.
(e)Use in Arbitration. Each Party may utilize information or documentation furnished by
the disclosing Party in any dispute resolution proceeding or in an administrative agency or court
of competent jurisdiction addressing any dispute arising under this Agreement, subject to a
confidentiality agreement with all participants (including, if applicable, any arbitrator) or a
protective order.
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(f) Breach. The Parties agree that monetary damages by themselves will be inadequate to
compensate a Party for the other Party's Breach of its obligations under this Section 29. Each
Party accordingly agrees that the other Party is entitled to equitable relief, by way of injunction or
otherwise, if it breaches or threatens to breach its obligations under this Section 29.
30. NOTICES. All written legal notices required by this Agreement shall be mailed or
delivered as follows:
To Avista: Avista Corporation
Attention: Vice President, Energy Resources and Optimization
1411 East Mission
Spokane, WA 99202-2600
Mailing Address:
P.O. Box 3727
Spokane, WA 99220-3727
To Potlatch: Vice President, Pulp & Paperboard Division
Potlatch Corporation
805 Mill Road
P. 0. Box 1016
Lewiston, ID 83501
Fax: [phone]
Vice President and General Counsel
Potlatch Corporation
601 West Riverside Ave., Suite 1100
Spokane, WA 99201
Fax: [phone]
Changes in persons or addresses for submittal of written notices by a Party to this
Agreement shall be made in writing to the other Party and delivered in accordance with this
Section 30. Any verbal notice required hereby which affects the payments to be made hereunder
shall be confinned in writing as promptly as practicable after the verbal notice is given.
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31.SETTLEMENT OF LITIGATION.
Potlatch shall dismiss with prejudice its complaint in the United States District Court for
the District of Idaho, Case No. CV02-543-C-01, and its complaint before the Idaho Public
Utilities Commission, Docket No. AVU-E-02-08, upon entry of a final order of the IPUC or
court of competent jurisdiction approving the Agreement.
32.EXHIBITS.
This Power Purchase Agreement includes the following exhibits, which are attached and
incorporated by reference herein:
Exhibit A - Metering
Exhibit B - Communications
Exhibit C - Description of the Facility
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
executed by their duly authorized representatives as of the first date herein-above set forth:
POTLATCH CORPORATION AVISTA CORPORATION
By: Aft!::&
5citl X
Name: Harry D. Seamans
Title: Vice President, Pulp &
Paperboard Division
By:
Title: Chairman, Pre Lent and Chief
Executive Officer
Exhibit A
Metering Specifications. Points and Locations
Utility Tie #1 Utilit Tie #2
Puti f Put2
Qti Q,
Meter Meter
Meter (3 Meter - Meter Meter
GI G2 G3 G4

t t
GEN #1 GEN #2 GEN #3 GEN #4
Simplified Meterina Diagram
1.0 Definitions
Whenever used in this Exhibit the following terms shall have the following meanings:
1.1 "Net Facility Power" (G a). Expressed kW.

1.1.1 For the purposes of this Agreement, the Parties have agreed that
Facility Service Power is 125 kW per operating generating unit. Potlatch shall notify Avista
when substantial changes are made to the Facility that affect the amount of Facility Service
Power. Within a reasonable time the Parties shall select a mutually agreed upon third party
auditor and shall share equally the costs of such an audit of Facility Service Power. Unless
otherwise agreed, the value determined by such audit shall become the new amount for
Facility Service Power for the balance of the term of this Agreement.

1.1.2 For the purposes of this Agreement, the Parties have agreed that
Losses are 200 kW.
1.2 "Power Generated" (G, 02, 03, & (34). The electric power measured at each
operating unit expressed in kW.
1.3 "Energy Purchased" (E1,). The amount of energy that Avista purchases from
Potlatch generated by the Facility in kWh in each hour.
1.4 "Energy Sold" (Es). The amount of energy that Potlatch purchases from Avista,
in kWh in each hour.
1.5 "Utility Tie Active Power" (P.O. The total active power delivered to Potlatch,
measured at each of the two (2) Pointsof Delivery expressed in W.
1.6 "Utility Tie Reactive Power" (QJ. The total reactive power delivered to
Potlatch, measured at each of the two (2) Points of Delivery expressed in WAR.
17 "Base Generation Amount" (Gb). Expressed in W.
1.8 "Base Period Demand" (DkVa.base). Expressed in kVa.
1.9 "Excess Generation Amount" (Ge). Expressed in W.
1.10 "Excess Period Demand" (DkVa.excess). Expressed in kVa.
1.11 "Incremental Generation Amount" (G a). Expressed in kW.
1.12 "Nominal Generation Amount" (G,,). Expressed in kW.
2.0 General Metering Formulas:
2.1 P t = P11t1 + P (kW)
2.2 Q t = Qi +Qut2 (WAR) Delivered to Potlatch
2.3 G =01 + G2 +03+04— (125kW*(the number of operating generating units)) -
(Losses)
2.4 Gi = G - Gnom, where Gi >0
Otherwise Gi =0
A-2
3.0 Base Period Power Sales Formula (Time Period in which Base Generation Amount
has not been exceeded)
3.1 Energy Sold (E8) = (P + G) * Time (kWh)
3.2 Base Period Demand (kVa)
DkVa_b e 2-- + G )2 + (Q )2
4.0 Excess Period Power Sales Formula (Time Period After The Base Generation
Amount Is Exceeded) When The Maximum Excess Generation Amount Is Exceeded
Or When Potlatch Uses Excess Generation Amounts To Serve Load And Avista
Does Not Purchase Incremental Generation Amounts
4.1 Energy Sold (Es) = (P)* Time (kWh)
4.2 Excess Period Demand (kVa)
Dkya_cess = 4(—P17+ + (Q, )2
5.0 Excess Period Power Sales Formula (Time Period After The Base Generation
Amount Is Exceeded) When The Maximum Excess Generation Amount Is Exceeded
Or When Potlatch Uses Excess Generation Amounts To Serve Load And Avista
Purchases Incremental Generation Amounts
5.1 Energy Sold (Es) = (P11t+G)* Time (kWh)
5.2 Excess Period Demand (kVa)
DkVaS =4(I +G1 )2 +(Q.,)2
6.0 Excess Period Power Sales Formula (Time Period After The Base Generation
Amount Is Exceeded) When Avista Purchases Excess Generation Amounts from
Potlatch And Avista Does Not Purchase Incremental Generation Amounts
6.1 Energy Sold (Es) = (P+ G)* Time (kWh)
A-3
6.2 Excess Period Demand (kVa)
DtVa..eXCeSS = + G )2 + (Q,)2
7.0 Excess Period Power Sales Formula (Time Period After The Base Generation
Amount Is Exceeded) When Avista Purchases Excess Generation Amounts from
Potlatch And Avista Purchases Incremental Generation Amounts
7.1 Energy Sold (E s) = (P+ G)* Time (kWh)
7.2 Excess Period Demand (kVa)
=
8.0 Base Period Power Purchase Formula
8.1 Base Generation Purchased (Gb) = G. * Time (kWh) where G1 =0 or
Gb = Gnom* Time (kWh) where (3 >0
8.2 Incremental Generation Purchased (G1) = G. - Gnom * Time (kWh) where Gi >0
otherwise Gi =0
9.0 Excess Period Power Purchase Formula
9.1 Excess Generation Purchased (Ge) = Time (kWh) where G1 =0
or Ge = G where G 1 >0
or G. =0 where Potlatch uses Excess Generation Amounts to serve Load
9.2 Incremental Generation Purchased (G1) = G - Guom * Time (kWh) where Gi >0
otherwise Gi = 0
A-4
Exhibit B
Communications
1. Verbal Communications
(a) Verbal communications relating to electric power scheduling, generation or load level
changes between Potlatch and Avista shall be between the following personnel:
(1)Pre-Schedule (5:30 a.m. to approximately 1:30 p.m. on normal business days):
Avista Pre-Scheduler [phone]
Alternate Phone Number: [phone]
Potlatch Utility Supervisor [phone]
Alternate Phone Number: [phone]
(2)Real-Time Schedule (available 24 hours per day):
Avista Real-Time Scheduler [phone]
Potlatch Utility Supervisor [phone]
Alternate Phone Number: [phone]
(b) During normal business hours, all verbal communications relating to interruptions and outages:
Avista System Operator [phone]
Alternate Phone Number: [phone]
Potlatch Utility Operator [phone]
Alternate Phone Number: [phone]
(c) Outside of normal business hours (nights, weekends, and holidays), all verbal communications
relating to interruptions and outages shall take place between the following personnel:
Avista System Operator [phone]
Alternate Phone Number: [phone]
Potlatch Utility Operator [phone]
Alternate Phone Number [phone]
Either Party may provide written notice to the other Party setting forth different contact numbers.
Exhibit C
Description of the Facility
1. Unit Number One DeScrrntlofl
(a)The unit number one turbine, General Electric serial number 197741, is a nine stage, 3600 RPM,
600 PSIG steam turbine.
(b)The unit number one generator, General Electric serial number 316X188, is nameplate rated at
12,500 kVA.
2. Unit Number Two Description
(a)The unit number two turbine, General Electric serial number 83530, is a six stage, 3600 RPM,
600 PSIG steam turbine.
(b)The unit number two generator, General Electric serial number 6784689, is nameplate rated at
11,188 kVA.
3. Unit Number Three Description
(a)The unit number three turbine, General Electric serial number 197836, is a twelve stage, 3600
RPM, 1250 PSIG steam turbine.
(b)The unit number three generator, General Electric serial number 316X374, is nameplate rated at
41,600 kVA @ 30 PSIG H2.
4. Unit Number Four Description
(a)The unit number four turbine, from ABB order number MO275226, is a 3600 RPM steam turbine.
(b)The unit number four generator, ABB serial number HM300516, is nameplate rated at 66,916
kVA
c-i
CASE NO. GNR-E-1 1-03
PETITION FOR RECONSIDERATION
OF J.R. SIMPLOT COMPANY AND CLEARWATER PAPER
CORPORATION
ATTACHMENT 4
Office of the Secretary
Service Date
April 27, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF A PETITION FILED BY )
IDAHO POWER COMPANY FOR AN ORDER ) CASE NO. IPC-E-04-2
DETERMINING OWNERSHIP OF THE )
ENVIRONMENTAL ATTRIBUTES ASSOCIATED)
WITH A QUALIFYING FACILITY UPON )
PURCHASE BY A UTILITY OF THE ENERGY ) ORDER NO. 29480 PRODUCED BY A QUALIFYING FACILITY. )
On February 5, 2004, Idaho Power Company (Idaho Power; Company) filed a
Petition with the Idaho Public Utilities Commission (Commission) requesting a Declaratory
Order determining ownership of the marketable "environmental attributes" associated with a
PURPA qualifying facility (QF) when Idaho Power enters into a long-term, fixed rate contract to
purchase the energy produced by that QF. Reference IDAPA 31.01.01.101; Section 210 of the
Public Utilities Regulatory Policies Act of 1978 (PURPA). The Commission in this Order
declines to grant Idaho Power's Petition for a Declaratory Order.
Background
In June 2003, the Federal Energy Regulatory Commission (FERC) received a
Petition for Declaratory Order from PURPA QFs seeking FERC interpretation of its avoided cost
rules under Section 210 of PURPA. Specifically, Petitioners sought an Order declaring that
avoided cost contracts entered into pursuant to PURPA, absent express provisions to the
contrary, do not inherently convey to the purchasing utility any renewable energy credits (RECs)
or similar tradable certificates. It was the contention of Petitioners that the power purchase price
that the utility pays under such a contract compensates a QF only for the energy and capacity
produced by that facility and not for any environmental attributes associated with the facility.
Reference American Ref-Fuel Company et a!, FERC Docket EL03-133-000.
In an Order issued on October 1, 2003 (105 FERC ¶ 61,004), FERC granted the
Petitioners request for a declaratory order, to the extent that the petition asked the Commission to
declare that the Commission's avoided cost regulations did not contemplate the existence of
RECs and that the avoided cost rates for capacity and energy sold under contracts entered into
ORDER NO. 29480 1
pursuant to PIJRPA do not convey the RECs, in the absence of an expressed contractual
provision. FERC's Order made the following specific findings:
19.Section 210(a) of PURPA requires the Commission to prescribe rules
imposing on electric utilities the obligation to offer to purchase electric
energy from QFs. Under Section 210(b) of PURPA, such purchases must
be at rates that are: (1) just and reasonable to electric consumers and in
the public interest; (2) not discriminatory against QFs; and (3) not in
excess of the incremental cost to the electric utility of alternative electric
energy. Section 210(d) of PURPA, in turn, defines "incremental costs of
alternative electric energy" as "the cost to the electric utility of the
electric energy of which, but for the purchases from [the QF], such utility
would generate or purchase from another source."
20.The Commission implemented the purchase obligations set forth in
PURPA in Section 292.303 of its regulations, 18 CFR § 292.303(a)
(2003), which provides:
Each electric utility shall purchase in accordance with Section 292.3 04,
any energy and capacity which is made available from a qualifying
facility.
Section 292.304, in turn, requires that rates for purchases shall: (1) be just
and reasonable to the electric customer of the electric utility and in the
public interest; and (2) not discriminate against qualifying cogeneration
and small power production facilities. 18 CFR § 292.304(a)(1) (2003).
The regulation further provides that nothing in the regulation requires any
electric utility to pay more than the avoided costs for purchases. 18 CFR
§ 292.304(a)(2) (2003). "Avoided costs" are defined as the "incremental
costs to an electric utility of electric energy or capacity or both which, but
for the purchase from the qualifying facility or qualifying facilities, such
utility would generate itself or purchase from another source." 18 CFR §
292.101 (b)(6) (2003).
21.Section 292.304 sets forth what factors are to be considered in
determining avoided costs. See 18 CFR § 292.304(e) (2003). The
factors to be considered include:
(1)The utility's system cost data;
(2)The availability of capacity or energy from a QF during the
system daily and season peak periods;
(3)The relationship between the availability of energy or capacity
from the QF to the ability of the electric utility to avoid costs; and
ORDER NO. 29480 2
(4) The costs or savings resulting from variations in line losses from
those that would have existed in the absence of purchases from
the QF.
22.Significantly, what factor is not mentioned in the Commission's
regulations is the environmental attributes of the QF selling to the utility.
This is because avoided costs were intended to put the utility into the
same position when purchasing QF capacity and energy as if the utility
generated the energy itself or purchased the energy from another source.
In this regard, the avoided costs that a utility pays a QF does not depend
on the type of QF, i.e., whether it is a fossil-fuel-cogeneration facility or a
renewable-energy small power production facility. The avoided costs
rates, in short, are not intended to compensate the QF for more than
capacity and energy.
23.As noted above, RECs are relative recent creations of the states. Seven
states have adopted renewable portfolio standards that use unbundled
RECs. What is relevant here is that the RECs are created by the states.
They exist outside the confines of PURPA. PTJRPA thus does not
address the ownership of RECs. The contracts for sales of QF capacity
and energy, entered into pursuant to PURPA, likewise do not control the
ownership of the RECs (absent an express provision in the contract).
States, in creating RECs, have the power to determine who owns the REC
in the initial instance, and how they may be sold and traded; it is not an
issue controlled by PURPA.
24.We thus grant Petitioners' Petition for Declaratory Order, to the extent
that they ask the Commission to declare that contracts for the sale of QF
capacity and energy entered into pursuant to PURPA do not convey
RECs to the purchasing utility (absent an express provision in a contract
to the contrary). While a state may decide that a sale of power at
wholesale automatically transfers ownership of the state-created RECs,
that requirement must find its authority in state law, not PURPA.
Petition for Declaratory Ruling
Regional organizations, Idaho Power contends, exist to facilitate green energy
transactions from resources that have been certified as green energy compliant by those
organizations e.g., Bonneville Environmental Foundation (BEF). These entities issue tradable
"green tags" to certified renewable energy producers. Green tags are also known as green
certificates, renewable energy credits (REC5) and tradable renewable certificates (TRCs). A
green tag represents the environmental and other non-power attributes associated with 1
megawatt hour (MWh) of electricity generated from a renewable resource. Some of the QFs
ORDER NO. 29480 3
from whom Idaho Power anticipates making purchases in the future, the Company contends,
have indicated an intention to obtain marketable green tags as a result of entering into contracts
with Idaho Power. Green tags avoid the need to package the electricity with its environmental
attributes. The tags provide a way in which to "unbundle" the environmental attributes from the
electricity and permit the sale of the environmental attributes of renewable generation separately
from the electricity generated. In effect, the Company states that green tags are a currency that
can be traded to individuals and entities wishing to support "green" energy. Example: Idaho
Power Schedule 62 - Green Energy Purchase Program (Case No. IPC-E-00-18, Order
No. 28655).
Referencing the foregoing FERC Order, 105 FERC 161,004, Idaho Power states that
FERC suggested that individual states may decide ownership of the green tags. As a result, the
Company seeks guidance from the Commission as to ownership of potentially marketable
certificates in Idaho.
Idaho Power contends that in Idaho, a utility and its customers confer additional
value on QFs by virtue of the long-term, levelized, fixed rate contracts that the utility enters into
with the QFs. That value, it asserts, is in addition to the avoided costs paid to the QFs for the
energy produced. Vesting the utility with some ownership interest in the green tags, it states,
would remunerate the utility for the additional value conferred to the QFs. The QF position, the
Company represents, is that QF ownership of the green tags provides the incentive they need to
invest in the production of energy from a renewable resource. They assert that the sale of the
green tags associated with the generation of green power compensates the QF for the facility's
environmental attributes and the additional risks associated with the investment in and the design
and operation of a renewable energy resource plant.
Idaho Power Company, in this Petition, requests a declaratory order from the
Commission clarifying ownership of these green tags. The "respective arguments" of the
Company and QFs are presented in the Company's Petition.
Despite Idaho Power's interest in owning the green tags, the Company acknowledges
that retention of those tags by the QF developers may encourage the development of additional
green energy resources in Idaho without the need to increase energy purchase prices. Given the
heightened public interest in the development of new renewable resources, Idaho Power
respectfully recommends that the Commission determine that the developers of such generation
ORDER NO. 29480 4
facilities receive full ownership rights in any green tags issued to them conditioned upon the
requirement that the QF developers who qualify for green tags and from whom Idaho Power
purchases energy grant the Company a "right of first refusal" to purchase those tags.
On February 20, 2004, the Commission issued Notices of Petition and Modified
Procedure in Case No. IPC-E-04-2. The deadline for filing written comments was March 19,
2004. Timely comments were filed by PacifiCorp, Avista, Bonneville Environmental
Foundation (BEF), Exergy Corporation, the Northwest Energy Coalition and Advocates for the
West, Bob Lewandowski and Mark Schroeder, and Commission Staff. The Company was
provided the opportunity to file Reply Comments and declined to do so. The comments and
recommendations of the parties can be summarized as follows:
PacflCorp
PacifiCorp notes that it has 13 long-term fixed rate contracts with QFs in Idaho,
ranging from 80 Kw to 6 MW. None of the QF contracts are levelized. PacifiCorp requests that
the Commission deny Idaho Power's request for a "right for first refusal" and instead issue an
Order declaring that, pursuant to obligations imposed by PURPA, ownership of all renewable
credits associated with energy produced and delivered by a QF pass to the utility that purchases
that output of the QF.
Renewable energy credits (RECs) identify generation as having come from a
renewable resource. Historically, PacifiCorp contends, QF developers have effectively sold the
entire output of their QFs to the purchasing utilities under PURPA-mandated contracts. This
bundled output, PaciflCorp contends, includes those characteristics that are now separately
identified as renewable energy credits. PacifiCorp characterizes Idaho Power's request as an
unbundling of RECs from the overall output of the facilities and the transfer of ownership to the
QF without compensation to the purchasing utility. This, it states, is not the intent of the PURPA
requirement. Ratepayers and utilities continue to bear the risks, the utility contends, not QFs. To
grant ownership of the renewable energy credits to QFs, PacifiCorp maintains, would result in a
windfall to QF developers at the expense of ratepayers.
PacifiCorp maintains that any entity that relies on a mandated purchase at a price that
is protected from market forces, such as the QFs, is by definition unlikely to be competitive
economically. Otherwise, it argues, the project would stand on its own without PURPA
ORDER NO. 29480 5
protection. To transfer the right to RECs from the purchasing utility to the QF developer,
PaciflCorp contends, would exacerbate this perverse incentive.
PacifiCorp contends that utilities and their ratepayers bear the risks associated with
QF generation and should receive the benefits arising therefrom. QFs come into existence, it
maintains, by choosing not to participate in the market, but rather trigger PURPA, which requires
utilities to enter into contracts with them at the utility's avoided costs.
Over the past few years, PaciflCorp notes that a secondary market has developed in
the identifying feature of the electricity as having come from the QF as a renewable resource.
This new market, it contends, has not created anything that was not there before, i.e., a certificate
that shows that renewable power was generated and delivered to the grid; rather, it just permits
an owner of a renewable resource to sell the certificate generated by that resource into a nascent
market that accords positive financial values to the certificate, which until now has always gone
with that power. The Commission in this case, PaciflCorp contends, is being asked to permit
QFs to withhold from the purchasing utility the very essence of what, under PUIRPA, requires the
utility to purchase the power from the QF in the first place. Renewable energy credits should not
be given to the QF to separately sell, PaciflCorp contends, unless the QFs right to require
ratepayers to pay avoided costs for the power is also taken.
Traditional regulatory principles, PacifiCorp contends, dictate that rewards should
follow risks, or that the bearer of risks and costs should likewise obtain the benefits. Ratepayers
have consistently borne the risk of PURPA-mandated contracts, PacifiCorp argues, and should
therefore retain the benefits of those contracts. Ratepayers should not be deprived of a benefit
they have always gotten for the past quarter-century under PURPA, simply because a secondary
market has developed for that portion of the power that identifies it as having qualified under
PURPA in the first place. Any other determination, PacifiCorp contends, would result in double-
billing the ratepayer and a windfall for the QF.
PacifiCorp notes that utilities do not voluntarily enter into QF contracts. The price
for QF energy is based on avoided costs, not market costs, which PaciflCorp contends Congress
has determined adequately compensates QFs that would otherwise be unable to compete in the
market. Requiring a utility's ratepayers to pay avoided costs as well as the market rate for
renewable energy credits, PacifiCorp contends, would result in increased energy costs.
ORDER NO. 29480 6
While acknowledging that Idaho does not currently have a renewable portfolio
standard (RPS) program that issues green tags, PaciflCorp notes that such programs are intended
to promote renewable energy in the market place by attracting the most efficient renewable
energy competitors. Resources must compete against each other rather than against a set level of
avoided costs. The approach of PURPA, PaciflCorp contends, is inherently less efficient since it
does not require competition among similar resources. For load serving entities, one of the
potential future benefits of QF contracts, PacifiCorp contends, is that they can help meet future
RPS goals, whether at the national or state level. Typically, load serving entities are required to
purchase renewables up to a mandated percentage of total load served.
PacifiCorp contends that QFs have voluntarily withdrawn from the market, and
utilities bear the risk of that decision. Idaho Power's requested Order, it states, would be a direct
detriment to ratepayers. The benefits should follow risks, and the approach proposed by Idaho
Power would set in motion a process whereby QFs can set aside non-power features with
positive market value for sale, leaving the ratepayers with generic power equivalent to power
generated from a non-renewable resource against the intent of PURPA for utilities to buy cleaner
power. Further, PacifiCorp contends that granting RECs to QFs can reduce the effectiveness of
future national and/or state renewable programs that intend, in part, to encourage more plant
investment for local economic development.
Absent the renewable energy credit, PacifiCorp maintains that power generated by
QFs is undifferentiated from other power a utility utilizes to meet its obligation to serve and,
therefore, the facility that produces this undifferentiated power should no longer be considered a
QF. The REC is an essential aspect of a generation facility's output that resulted in the facility
being designated a QF under PURPA in the first place.
A vista
Avista expresses concern that any Order issued by the Commission in Idaho Power's
docket will be precedent with respect to other companies. Avista recommends that the
Commission's Order be limited in effect to Idaho Power and expressly not apply to Avista
Corporation. Alternatively, Avista recommends that the Commission declare that ownership of
renewable energy credits associated with QF renewable resources be vested or conveyed to the
purchasing utility as a condition of a QF receiving a contract.
ORDER NO. 29480 7
QFs located in Idaho, Avista contends, receive a benefit and incentive when they
contract to sell to a utility at a long-term, fixed rate contract. The QF developers, it states,
receive the benefit of the utility's credit standing, and the likely certainty of a steady continued
cash flow over a long period of time. Avista submits that ownership of RECs should remain
with the purchasing utility company when the utility is compelled to purchase power from the
QF.
Avista contends that the fundamental principle of PURPA is that the power a utility
purchases at avoided cost rates from QF projects is Intended to displace power from resources
that the utility otherwise would have had to construct or purchase. The utility and its customers,
Avista contends, should incur no more costs, and receive no less economic benefit from a QF
purchase, than a utility-owned generating unit operated for its customers. A purchasing utility,
Avista contends, normally expects to acquire all of the attributes and value of the output that it
purchases from a QF pursuant to a published avoided cost rate. If the utility does not acquire all
of the value of the QF output then, Avista contends, there is not an equivalence of value between
a QF project and a comparably sized utility owned resource. Utility customers will receive less
value from QF purchases, it maintains, if the monetary benefit of RECs is assigned to the project
developer instead of flowing with the power to the benefit of utility customers. It is consistent
with the principles of PURPA, Avista argues, that the monetized value of QF renewable resource
development be retained by the utility customers in the same manner that the customers would
benefit from monetized value of RECs associated with utility generation.
QF development, Avista contends, would not be significantly deterred if renewable
energy credits are retained by utilities that purchase power from QFs at published avoided cost
rates. QFs are not precluded from taking their electricity output and RECs to the wholesale
markets, if they perceive that the wholesale markets offer greater rewards then they will receive
at Commission determined avoided cost rates.
The monetary value of RECs, Avista contends, are not preserved to the utility and its
customers, if the QF developer retains ownership of the renewable energy credits, even if the QF
developer assigns a "right of first refusal" to the utility. The utility and its customers, Avista
contends, should be able to benefit from any increase in the value over time of RECs,
irrespective of whether the renewable energy credits are associated with utility owned
generation, or are acquired by purchase from a QF at published avoided cost rates.
ORDER NO. 29480 8
Bonneville Environmental Foundation (BEF)
BEF is a non-profit business that markets green tags representing the environmental
attributes of the output of certain renewable power generating facilities. BEF supports and
encourages the Commission to adopt the general proposition that the environmental attributes or
green tags associated with the output of renewable power facilities are and remain the property
of the owner of that facility until and unless the owner consents to a transfer of those green tags
to another party. Similar to federal or state tax credits or other incentives employed by the owner
to develop its facility, BEF contends that unless otherwise specified, these incentives are
intended by the public bodies that established them to be employed in aggregate by a developer
of a renewable facility, in recognition that often the economic disincentives act in aggregate to
discourage such developments. Thus, the federal government does not demand custody of the
green tags from a project that takes advantage of federal tax credits and decelerated depreciation.
Thus, a cogeneration facility that uses fossil fuels and may have no green tags to sell is not
disqualified from exercising its QF rights under PURPA.
BEF applauds Idaho Power's recognition of the compelling value to the State of
Idaho of incenting prospective facility developers to proceed with their renewable projects.
Oregon, Washington and other states in which renewable facilities are being actively developed,
BEF notes, do not challenge the owners' green tag rights.
BEF parts company with Idaho Power on the narrower question of whether Idaho
Power should obtain a "right of first refusal" for the green tags from the facilities in question.
BEF understands the Company's reasoning in seeking to protect its customer access to the tags
but believes that the market will meet this concern. A right of first refusal, BEF contends,
effectively diminishes the market value of the tags to the owners by discouraging a third party
from expending the effort and paying the opportunity cost of negotiating to purchase such tags,
only to have Idaho Power exercise its right of first refusal. As a marketer, if BEF has an
equivalent opportunity to acquire tags from another seller not constrained by such a right of first
refusal, BEF will out of necessity prefer the unencumbered tags and seller.
Northwest Energy Coalition and Advocates for the West
The Northwest Energy Coalition is a multi-state association of energy efficiency,
clean energy, environmental and other public interest organizations engaged in promoting a
clean, reliable and economic energy future for the Pacific Northwest. Advocates for the West is
ORDER NO. 29480 9
a non-profit conservation law and advocacy center, which supports renewable energy resources
and energy efficiency improvements. The commenters concur with the comments of Bonneville
Environmental Foundation. BEF's comments, they contend, deserve careful consideration in no
small part because BEF markets and sells green tags in Idaho for Idaho Power's green power
program.
The commenters appreciate and agree with the general position taken by Idaho Power
Company that green tag ownership should stay with project owners. Commenters base their
argument on the utility's obligation to price QF power at the utility's avoided cost and the
monopsonist power of Idaho Power. The commenters also note that green tags are just one
collateral value that PURPA QFs can have, apart from the production of electrons. Methane
digesters installed at dairies can improve overall waste management. Canal-drop hydro systems
can have independent value to their owners for channel maintenance, water flow management or
other reasons. These values are real and separate from the production of electricity at QFs, but a
utility could not possibly claim ownership of them.
Regarding Idaho Power's request for "right of first refusal" to purchase green tags
from QFs, commenters support BEF's position. Quite simply, they do not believe the Company
has presented any legal or other compelling basis to obtain such a right. The Northwest Energy
Coalition and the Advocates for the West recommend that the Commission confirm that QF
developers own the environmental attributes associated with their projects, free from rights of
first refusal.
Exergy Corporation
Exergy Corporation contends that the October 1, 2003, ruling by FERC (Docket No.
EL03- 133- 00) clearly indicates where and under what circumstances state authority for
ascertaining ownership of environmental attributes embedded in renewable programs exists.
Under the tenets incorporated into PURPA, whereby the utility is required to purchase energy
and capacity only, the environmental attributes are not part of the protocol. Furthermore, Exergy
Corporation argues that no Idaho enabling statute exists for a decision on the question of
ownership of an environmental attribute by the Idaho Public Utilities Commission.
Exergy Corporation contends that without a specific legislative, regulatory, or legal
provision in the Idaho Code or in the Idaho Administrative Rules, there appears to be no legal
mechanism to authorize the Commission to create new law. Absent those provisions, without an
ORDER NO. 29480 10
existing statute to interpret, a directive from the state legislature or a federal mandate, Exergy
contends that the Commission cannot implement a decision deleterious to either the generator,
the utility, or contrary to FERC and PURPA. Where no state initiated mandatory guidelines are
evident, Exergy contends that the environmental attribute remains with the generator.
But the question of whether law exists, Exergy contends, should be moot regardless.
Such a law is inappropriate based on the single fact that the QF bears the risk of compliance;
therefore, the QF should also have the benefit of environmental attributes. The QF is solely
responsible to mitigate pollution consequences, not the customer or utility, and all the liabilities
or attributes of that generation lie with the QF.
The inception of the tradable renewable certificates or green tags derived from the
environmental attributes, Exergy Corporation contends, was designed towards proliferation of
renewable generation sources. The rationale was to provide to the generator, it states, an
additional source of income from the potential offset of fossil-fuel emissions and other
environmentally sensitive generators. Because renewable generation carries a disproportionately
larger installed cost with no ability to pass through fuel risk, any additional inducement results in
expanded opportunities to increase the amount of renewable resources.
Exergy Corporation notes that the decision behind the avoided cost rate for a QF in
Idaho is based on a natural gas-fired generator. There is no environmental attribute associated
with this baseline generator, only capacity and energy. They alone are the basis for the avoided
cost rate mandated by the Commission for QFs. No environmental attribute is associated with
this mandate. Equally as important, it states, not all QFs are necessarily renewable energy based
resources. Therefore, not all QFs in the less than 10 MW category can even demonstrate an
environmental attribute.
But there is a more germane argument to be voiced under the concept of Integrated
Resource Planning, Exergy Corporation states. Even if the environmental attribute is "stripped"
from the renewable resource generation, there still is no rational nexus which purports the
generating source to be anything other than nonpolluting. A renewable resource generator
stripped of the environmental attribute, is still a nonpolluting generator resource and displacing
fueled or hydro generation. No paper commodity will modify the evolution of the electrons
produced. Given this transparency, Exergy Corporation contends that the environmental
attribute need not be part and parcel of any societal generation mix. The generator is
ORDER NO. 29480 11
nonpolluting and the potential to offset existing facilities, new emission or social-impact
generation is tangible.
An environmental attribute, whether monetized or not, Exergy Corporation contends,
is separate from the energy and capacity of generation source. Until such time as the State of
Idaho decides to enact legislation essentially (1) forcing PURPA projects to relinquish the
environmental attribute to the ratepayer or utility, (2) creating a renewable portfolio standard or
(3) implementing another such mandate for renewable resource generation requirements into the
IRP of the utilities serving the Idaho customer (and the energy sales price reflects this
requirement), the irrefutable answer to the question posed by Idaho Power, Exergy Corporation
contends, is that the environmental attribute remains with the QF, unless otherwise mutually
agreed upon between QF and purchasing utility.
Bob Lewandowski and Mark Schroeder
Mr. Lewandowski is the current owner of Idaho's first commercial wind power
generating facility located south of Interstate 84 between Boise and Mountain Home. Mr.
Schroeder currently owns and farms several 1,000 acres contained within the Bell Rapids
Irrigation District. Given the cost of electric power to irrigate his farm and its location in a
desirable wind resource area, Mr. Schroeder is currently actively planning to construct a large
(under 10 MW) wind facility.
Commenters suggest that the Commission should reject Idaho Power's Petition for
"right of first refusal" to purchase green tags from QFs. Idaho Power, they contend, has no
interest in, or right to, green tags created by QFs.
Commenters dispute the Company's contention that QF developers receive value
from Idaho Power for the electricity the QFs generate beyond the purchase price of the energy.
The Company's avoided cost rates, they state, are totally unrelated to a QF's internal finances.
Avoided cost rates are determined based on the utility's cost of bringing on a new resource. The
Company's assertion that QFs receive additional value over and above the avoided cost rates by
virtue of 20-year contracts, they contend, is simply wrong. Contract length, they state, is not at
all relevant to the question of whether or not the Company should be bestowed with the right of
first refusal. The commenters point out that 20-year contracts are not required in surrounding
states. Commenters state that it is worth noting that every single state that is adjacent to Idaho
has multiple tax incentives, including outright monetary grants to encourage the development of
ORDER NO. 29480 12
renewable energy projects. The State of Idaho has no such incentives. If the assertions
contained in the Company's Petition relative to QFs in Idaho being over compensated remain in
the record, the commenters contend that Modified Procedure is inappropriate and request a full
evidentiary hearing.
The commenters contend that the Idaho Commission has only limited authority and
has no authority to rule on the ownership of green tags. The Commission's jurisdiction, they
state, is limited and must be found entirely in its enabling statutes. It is clear, they state, that the
Idaho Courts view the Commission's jurisdiction relative to QFs as stemming solely from
PURPA and FERC's implementing regulations. It is also clear, they state, that this Commission
has no authority other than that conferred upon it by Idaho law or through its role as a state
agency regulating utilities under PURPA. What then, they query, are the FERC's PURPA
regulations this Commission is charged with implementing that deal with ownership of
(including rights of first refusal to) green tags. Simply put, they state that there are none. In fact,
they note that FERC has ruled that in order for a state regulatory commission to exercise any
authority over green tag ownership there must be a state law bestowing that authority upon the
Commission. FERC has made it clear that there is nothing in PURPA or FERC's regulations
granting the Commission authority to. adjudicate ownership of green tags. FERC has declared
that because states created RECs they may regulate how those credits are traded. Idaho has not
created RECs, therefore, commenters suggest that there is nothing for the state to regulate. A
REC or green tag, the commenters state, is private property owned and created by the QF. It is
no different, they argue, from any other ancillary benefit that might accrue to a QF as a result of
building a renewable energy resource. Idaho Power's request for right of first refusal, they
maintain, is different only in degree from asking for outright ownership. Commenters
recommend that Idaho Power's Petition be denied.
Commission Staff
Staff recommends that the Company's Petition for Declaratory Order be denied.
Alternatively, should the Commission determine that it has jurisdiction, Staff recommends that
the Commission issue a declaratory order stating that mandatory purchases from QFs wider
PURPA do not convey ownership of any marketable environmental attributes. Accordingly, any
environmental attributes associated with QF generation remain with the QF. Staff further
recommends that the Commission deny the Company's proposal to require that QF developers
I
ORDER NO. 29480 13
from whom Idaho Power purchases energy grant Idaho Power a "right of first refusal" to
purchase the environmental attributes associated with the QF facility.
Staff contends that the initial question before the Commission is one of jurisdiction.
Does the Commission have the statutory authority and jurisdiction to determine who owns the
"environmental attributes" associated with a QF project that requests a PURPA contract and
proposes to sell capacity and energy to a regulated utility? If PURPA and FERC rules do not
address and do not require a QF developer to sell "environmental attributes" to the purchasing
utility, can the Commission in its implementation of PURPA restrict their sale to other parties?
If the Commission has the authority under PURPA, should it restrict their sale? Can the
Commission require as a PURPA contract condition that a QF grant a purchasing utility a "right
of first refusal" to purchase the "green tags" associated with a QF facility?
It is well settled, Staff states, that the Idaho Commission is a creature of statute and
derives its general authority vis-a-vis electric utilities from Title 61, Idaho Code. Under State
Law, the Commission has authority over retail electric service. Wholesale power transactions
are regulated by the Federal Energy Regulatory Commission. All QF sales to an electric utility
are wholesale transactions. FERC, in the Order cited by Idaho Power in its Petition (105 FERC
¶ 61,004), states that the contract sale of QF capacity and energy entered into pursuant to
PURPA does not convey renewable energy credits to the purchasing utility (absent an express
provision in the contract to the contrary). FERC notes that RECs are relatively recent creations
of the States and suggested that states, in creating RECs, have the power to determine who owns
the credit in the initial instance, and how they may be sold and traded. "It is not," FERC states,
"an issue controlled by PURPA." Staff notes that Idaho is not a state that has established a
renewable energy portfolio standard for electric utilities. Nor is it a state that has by legislation
created green certificates, green tags, renewable energy credits or tradable renewable certificates
or established a market for same. Nor is Idaho a state that has provided tax incentives or credits
for the development of renewable energy. In short, Staff contends, there appears to be no hook
that gives the Commission jurisdiction over "environmental attributes," not under PURPA or
federal law (including the Energy Policies Act of 1992), and not under Title 61 of the Idaho
Code.
In the context of PURPA wholesale transactions, Staff notes that FERC has barred
state commissions from establishing different wholesale prices for otherwise qualified
ORDER NO. 29480 14
cogeneration or small power production facilities. 18 C.F.R. § 292.3 04(a)(ii). Accordingly,
contracts for renewable resources cannot be at a higher price than for non-renewable resources,
nor can the requirements of contract be different. Discrimination either directly or indirectly is
not permitted.
Arguably, what Idaho Power proposes, Staff contends, is an impermissible "taking"
of property. The Fifth Amendment of the U. S. Constitution states "nor shall private property be
taken for public use without just compensation." Idaho Power requests a Commission Order
granting the utility by regulatory fiat a "right of first refusal." It proposes no compensation to the
QF for the right. Electric utility purchases of energy and capacity from PURPA QFs are
mandatory. 18 C.F.R. § 292.303(a). The environmental attributes associated with renewable QF
projects, Staff contends, are currently separate from the capacity and energy sold to Idaho
utilities. They are not, Staff contends, bundled together as a matter of law. Nor is the cost to
purchase environmental attributes included in an Idaho utility's avoided cost To the extent
those attributes have value and provide additional developer incentive, Staff believes they should
remain with the developer. At this time, Staff contends that no argument has been advanced nor
authority cited to justify or require placing any regulatory restriction by this Commission on their
ownership.
COMMISSION FINDINGS
The Commission has reviewed the filings of record in Case No. IPC-E-04-2. We
have reviewed the comments of PacifiCorp and Avista, the comments and recommendations of
the Commission Staff, and the comments of other interested parties. Based on our review, we
continue to find it reasonable to process this case pursuant to Modified Procedure. JDAPA
31.01.01.204.
Idaho Power in this case requests a Declaratory Order regarding the ownership of the
marketable "environmental attributes" or green tags associated with PURPA qualifying facility
(QF) projects when Idaho Power enters into a long-term, fixed rate contract to purchase the
renewable energy produced by that QF. It is the Company's recommendation that the ownership
of green tags be confirmed in the QF and as a condition of contract that the utility be granted a
"right-of-first refusal" to purchase the tags. Other parties recommend a variant, expansion or
denial of the Company's requested relief.
ORDER NO. 29480 15
All commenters recommend for different reasons that the ultimate relief requested by
Idaho Power, i.e., that the Company be provided a "right of first refusal" to purchase the
environmental attributes or green tags associated with required QF purchases, be denied.
PaciflCorp and Avista maintain that the environmental attributes or green tags associated with
renewable resources are the property of the purchasing utility. The Bonneville Environmental
Foundation, Northwest Energy Coalition and Advocates for the West recommend that the
Commission confirm that QF developers own the environmental attributes associated with their
projects, free from rights of first refusal. Exergy Corporation, Bob Lewandowski and Mark
Schroeder and Commission Staff contend that the Commission has no jurisdiction or authority
stemming from either PURPA, FERC implementing regulations or Idaho state law to grant the
requested relief. Should the Commission decide not to dismiss Idaho Power's Petition, Mr.
Lewandowski and Schroeder contend that the Company's Petition is not appropriate for
Modified Procedure and request that the Commission schedule an evidentiary hearing.
We find that the issue presented by Idaho Power in its Petition does not present an
actual or justiciable controversy in Idaho and is not ripe for a declaratory judgment by this
Commission. Declaratory rulings are appropriate regarding the applicability of any statutory
provision or of any rule or order of this Commission. See IDAPA 31.01.01.101; Uniform
Declaratory Judgment Act, Idaho Code 10-1201 et seq. A declaratory ruling contemplates the
resolution of prospective problems. The rights sought to be protected by a declaratory judgment
may invoke either remedial or preventive relief; it may relate to a right that is only yet in dispute
or a status undisturbed but threatened or endangered; but in either event it must involve actual
and existing facts. Idaho Code Supreme Court in Harris v. Cassia County, 106 Idaho 513, 516-
517, 618 P.2d 988 (1984). We find that none of the predicates are present in this case. In
making this finding, the Commission notes that FERC on April 15, 2004 (Docket EL03-133-001,
107 FERC 161,016) denied rehearing of its earlier October 1, 2003 Order (105 FERC ¶ 61,004).
We note also that the State of Idaho has not created a green tag program, has not established a
trading market for green tags, nor does it require a renewable resource portfolio standard.
While this Commission will not permit the Company in its contracting practice to
condition QF contracts on inclusion of such a right-of-first refusal term, neither do we preclude
the parties from voluntarily negotiating the sale and purchase of such a green tag should it be
perceived to have value. The price of same we find, however, is not a PURPA cost and is not
ORDER NO. 29480 16
recoverable as such by the Company. Recovery of those expenses will be reviewed as are all
other non-PURPA costs.
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 (PURPA).
The Commission has authority under PURPA 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 and as more particularly described above, IT IS
HEREBY ORDERED and the Commission does hereby decline to grant Idaho Power's Petition
for a Declaratory Order. IDAPA 31.01.01.101.
IT IS FURTHER ORDERED and the Commission does hereby deny any and all
other relief requested by the commenting parties as may be related to the "environmental
attributes" associated with QF renewable energy.
ORDER NO. 29480 17
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) may petition for reconsideration within twenty-one (21) days of the
service date of this Order with regard to any matter decided in 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 27
day of April 2004. aKJEL:4LANI~R, PRF-,SIDENT
N" ]I 2k~~
MARSHA H. SMITH, COMMISSIONER
ATTEST:
/144
JeH D. Jewell fl
Co'thmission Secretary
vIdJ0:IPCE0402_sw
ORDER NO. 29480 18
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 8 th day of January, 2013, a true and correct copy of the
within and foregoing PETITON OF RECONSIDERATION OF J.R. SIMPLOT COMPANY
AND THE CLEARWATER PAPER CORPORATION was served as shown to:
.X... Hand Delivery
- U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington
Boise, Idaho 83702
[e-mail]
Kris Sasser
Idaho Public Utilities Commission
472 West Washington
Boise, Idaho 83702
krisine.sasser(Duc.idaho.gov
Donovan E. Walker
Jason B. Williams
Idaho Power Company
P0 Box 70
Boise, ID 83707-0070
[e-mail]
[e-mail]
Michael G. Andrea
Avista Corporation
P.O. Box 3727
Spokane, WA 99220
michael.andreaavistacorp.com
Daniel Solander
PacifiCorp/dba Rocky Mountain Power
201 S Main St Ste 2300
Salt Lake City, UT 84111
[e-mail]
Dean J. Miller
Chas. F. McDevitt
McDevitt & Miller, LLP
420 W. Bannock St.
Boise, ID 83702
j [e-mail]
- Hand Delivery
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Facsimile
X Electronic Mail
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_U.S. Mail, postage pre-paid
Facsimile
X Electronic Mail
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Facsimile
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_U.S. Mail, postage pre-paid
Facsimile
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Facsimile
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John R. Lowe - Hand Delivery
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Renewable Energy Coalition - Facsimile
12050 SW Tremont St X Electronic Mail
Portland, OR 97225
[e-mail]
R. Greg Ferney - Hand Delivery
Mimura Law Offices PLLC _U.S. Mail, postage pre-paid
Interconnect Solar Development, LLC - Facsimile
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Meridian, ID 83642
greg(mimuralaw.com
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1303 E. Carter - Facsimile
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[e-mail]
Ronald L. Williams - Hand Delivery
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Wade Thomas - Hand Delivery
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15690 Vista Circle - Facsimile
Desert Hot Springs, CA 92241 X Electronic Mail
robertapaul08(gmail.com
CERTIFICATE OF SERVICE - GNR-E-1 1-03
Page 2
James Carkulis Hand Delivery
Exergy Development Group of Idaho, LLC _U.S. Mail, postage pre-paid
802 W. Bannock, Ste 1200 - Facsimile
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j carkulisexergvdeveloiment.com
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10660 South 540 East - Facsimile
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blueribbonenergy(gmail.com
Ted Diehl Hand Delivery
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[e-mail]
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Idaho Windfarms, LLC - Facsimile
6762 Blair Avenue X Electronic Mail
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& L~ _
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