20130125Tamarack Energy Comments.pdf

._.rJ Michael C. Creamer [ISB No. 40301
C GIVENS PURSLEY LLP
601 West Bannock Street
P.O. Box 2720 'flh1 t: 12 rnt .3 (.0 Boise, Idaho 83701-2720 DHC) PUELL
ryl~
Office: [phone] T1IT COMMSSJ:
Fax: [phone] CD mcc@@givenspursley.com
Attorneys for Tamarack Energy Partnership
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF TARIFF ADVICE NO. Case No.: IPC-E-12-28
12-13 OF IDAHO POWER COMPANY FOR
AUTHORITY TO UPDATE SCHEDULE 89. COMMENTS OF TAMARACK
ENERGY PARTNERSHIP
Tamarack Energy Partnership ("Tamarack"), by and through its attorneys of record,
Givens Pursley LLP, and pursuant to Commission Order No. 32708, submits the following
comments in the above-captioned matter.
INTRODUCTION
The issue before the Commission is whether the effective date of Idaho Power
Company's ("Idaho Power") Schedule 89 tariff should beJune 1, 2010 or January 1, 2012. The
unit avoided energy cost contained in Schedule 89 is used to calculate the monthly payments
made by Idaho Power under certain vintage power sales agreements ("PSA"), including a PSA
entered into between Idaho Power and Tamarack in 1981. A copy of the Tamarack PSA is
attached hereto as Exhibit 1.1 Idaho Power has proposed a January 1, 2012 effective date for the
revised Schedule 89 because that was the effective date of its last general rate case in IPC-E- 11-
08 (the "2011 GRC").
1 The Tamarack PSA was subsequently amended but not with respect to any of the issues raised in this
proceeding. The amendment therefore is not included with Exhibit 1.
For the reasons discussed below, Tamarack's position is that the effective date should be
June 1, 2010 to coincide with the effective date of Commission Order 31093 approving an
increase in certain of Idaho Power's base rates, including the base level of its net power supply
expense ("NPSE"), in the context of a power cost adjustment ("PCA") proceeding. IPC-E- 10-12
(the "2010 PCA").
Certain early Commission orders have indicated that the level of payments to qualifying
facilities ("QF") under vintage PSAs such as Tamarack's are to be adjusted when Idaho Power's
variable energy costs are determined in a GRC. Tamarack believes, however, that the intent of
the Tamarack PSA and the policy of the Commission as reflected in its orders implementing
PURPA are to provide for payments to QFs reflecting Idaho Power's actual avoided costs at the
point in time when those avoided costs are known and determined regardless of whether they are
determined in a GRC. Here, that determination occurred in the context of the 2010 PCA and not
the subsequent 2011 GRC.
It also is significant that but for negotiations between Idaho Power, its customers and
Commission staff in the fall of 2009 that led to a stipulated rate case moratorium, Idaho Power
would have filed a GRC in 2009, which would have put new rates—including the current base
level for NP SE—in place effective June 1, 2010. Instead, the stipulated moratorium had the
effect of postponing the filing of a GRC to 2011. Despite the moratorium, however, the parties
agreed to, and the Commission approved prospectively, an increase in Idaho Power's base level
for NPSE to be used in the 2010 PCA and next GRC.
Tamarack has been provided what Idaho Power characterizes as its "unaudited"
calculations of what the power purchase payments to Tamarack should have been from January
to December of 2012 under the revised Schedule 89, and what they would total for the period
from June 1, 2010 to December 31,2011 if the Commission agrees that June 1, 2010 should be
the effective date for Schedule 89. Tamarack does not disagree with those calculations. A
Page 2 of 13
spreadsheet setting out these calculations, including actual payments to Tamarack made by Idaho
Power during this period, and reflecting what the payments would have been had the energy
payment component been revised to reflect the increased base level NPSE approved by the
Commission effective as of June 1, 2010 is attached to these Comments as Exhibit 2.
BACKGROUND
1. The Commission's Treatment of Avoided Costs
Commission orders from the early 1980s reflect the frustration that initial implementation
of PURPA's mandatory requirements generated for the Commission, utilities and QFs.
Following hearings in the summer of 1980, the Commission issued Order 15746, Case No. P-
300-12, summarizing its analysis for rulemaking with respect to cogeneration and small power
producers ("CSPP") under PURPA. A central focus of the Commission's analysis was the issue
of avoided costs. After first noting that PURPA provided that state commissions "may" require a
utility to pay its own avoided cost when purchasing power from CSPPs, the Commission
endorsed "the policy of having each utility pay its full avoided cost when purchasing power from
cogenerators and small power producers." Order 15746 at 4.
For CSPPs like Tamarack, who contracted to deliver energy on a firm basis, the capacity
component of the utility's avoided costs (and its power purchase payments) was fixed for the life
of the PSA, but the utility's variable costs, including fuel and variable operation and maintenance
costs, were to fluctuate during the contract term to reflect changes in those variable costs when
and to the extent they occurred. This approach was intended to minimize potential overpayments
and underpayments to CSPPs, particularly those contracting with Idaho Power, whose avoided
energy costs fluctuate more than other Idaho electric utilities due to its limited hydro storage
capacity.
Idaho Power appears particularly sensitive to fluctuations in avoided
energy costs. Allowing energy payments derived from annual estimation
of avoided costs may obligate the Company to payments in excess of the
Page of 13
actual avoided costs. Conversely, annual estimates of avoided energy
costs may also allow the QF too little. Underpayments are likely to occur
from this scheme during poor water years or during nearly every year for
those facilities whose production coincides with the months of high
avoided energy costs. In the long run, a policy based on Idaho Power's
estimated avoided costs at delivery time reduces the financial risk to both
the utility and the QF.
Order 15746 at 18-19.
Thus, at the conclusion of the initial phase of its review in Case No. P-300-12 the
Commission had concluded that utilities would be required to pay their full avoided costs for
energy purchased from CSPPs and the payments would be based on the utility's estimated
avoided costs at the time of energy delivery to reduce financial risk to both the utility and the
CSPP.
With the foregoing policy in place, four months later the Commission took up the
remaining issues surrounding approval of the several utilities' rates, tariffs and standard contracts
for CSPPs in Order 16025, Case No. P-300-12. The Commission determined that a base load
coal plant was the typical unit which Idaho Power could defer as a result of generation supplied
by CSPPs, and it designated Valmy Unit No. 2 to be the surrogate unit for determining Idaho
Power's avoided costs. Order 16025 at 6. After noting that it had not yet chosen a methodology
for updating the energy component of avoided costs for those CSPPs receiving both capacity and
energy payments, the Commission set out that methodology for both firm and as-available
contracts in an attached appendix to Order 16025. There the Commission determined that while
the capacity cost paid to the CSPP would be fixed over the contract life, "the energy rate will be
periodically adjusted to reflect current coal costs." Table B to the appendix sets out the 1981
unit avoided energy costs for both Idaho Power and Washington Water Power, and provided that
"These cost figures will be updated annually to reflect the current price of coal." Order 16025 at
A-4.
Page 4 of 13
The 1981 Tamarack PSA was developed and executed by the parties with these principles
in mind.
In 1983, Idaho Power applied to the Commission for approval of revised rates and tariffs
for purchase of power from CSPPs. These rates were derived from a proposed new methodology
that Idaho Power intended would replace the one established in Case No. P-300-12 and described
above. See Order 18190, Case No. U-1006-200. A key difference in the methodology was the
proposed use of Idaho Power's weighted average construction costs for a mix of hydro and
thermal resources in lieu of costs associated with a single thermal unit.
The Commission determined to use average system production costs for existing plant
rather than average construction costs for projected plant. It also held that variable energy costs
"will be updated at the end of each general rate case," with the proviso that "this change in
method of calculation of variable energy costs will be prospective only. It will not apply to
contracts already signed under previous Orders' methods."2 Order 18190 at 13.
Order 18190 also stated that a separate variable cost update would be required for
contracts signed under the previous orders' methods and would be based on the running costs of
Valmy I, "again as contained in general rate cases under recognized normalization methods." Id.
Presumably it is this statement on which Mr. Walker, counsel for Idaho Power, bases the premise
that "[b]ased on previous Commission orders, the pricing under Schedule 89 is to be adjusted as
a result of an Idaho Power general rate case ("GRC") proceeding where net power supply
expenses change." November 28, 2012 transmittal letter from Donovan Walker to Jean Jewell
Re: Tariff Advice No. 12-13, Case No. IPC-E-1 1-08, Compliance Filing Schedule 89.
2. The Tamarack PSA and Payments Received.
2 Commission has made various changes and refinements to the treatment of avoided costs and
calculation of payments in PSAs over the years, but they have not affected the calculation of payments under the
limited number of PSAs of the Tamarack vintage.
Page 5 of 13
Tamarack's predecessor in interest, Evergreen Energy, Inc., entered into a 35-year PSA
with Idaho Power on September 16, 1981, electing to deliver energy under "Option 4—Firm
Energy and Dispatchable resource Capacity." As such, the methodology for determining the
payments for energy by reference to the Valmy coal unit applied to this PSA, and Tamarack's
monthly payment from Idaho Power includes a fixed capacity component and a variable energy
component. Appendix A, Table 2 to the Tamarack PSA sets out the levelized avoided capacity
costs based on the operation date and contract term. The unit avoided energy costs are "as
specified in [Idaho Power's] Tariff Schedule 89 on file with the Idaho Public Utilities
Commission."
The Tamarack PSA defines "Unit Avoided Energy Cost" as "[t]he sum of variable costs
associated with the specific generating unit or project designated by the Idaho Public Utilities
Commission as the basis for determination of avoided Capacity cost. Variable costs include fuel
costs and operation and maintenance expenses which vary with the designated unit's or project's
generation." Tamarack PSA at 4. The Tamarack PSA did not contemplate that the Unit Avoided
Energy Cost component of payments was necessarily dependent on determination in a GRC.3
Payments to Tamarack for energy delivered have been periodically adjusted to reflect
changes to Idaho Power's variable energy costs for the Valmy unit as determined by the
Commission from time to time in GRCs. In the instant case, however, the adjustment in base
level NPSE to account for increased energy costs, including increased coal costs for the Valmy
unit, occurred through the 2010 PCA. No corresponding adjustment was made to payments to
Tamarack under its PSA, however. Indeed, it apparently was not until well after the 2011 GRC
had been concluded that it occurred to anyone that Idaho Power's Schedule 89 needed to be
revised, giving rise to the issue of what effective date should apply.
By comparison, the Tamarack PSA defines "Current Capacity Cost" as the "$/kw Capacity cost from the
most recent schedule of Capacity costs being published by [Idaho Power] and on file with the Idaho Public Utilities
Commission." Tamarack PSA at 2.
Page 6 of 13
The energy component of payments Tamarack actually received between June 1, 2010
and December 31, 2012 are set out under the heading "Energy Payment" in the attached Exhibit
2. The energy component of payments Tamarack would have received based on the unit avoided
energy cost reflected in the pending Schedule 89 also are set out in Exhibit 2 under the heading
"Total Revised Energy Payment." Idaho Power and Tamarack agree that based on the
calculations and numbers shown in Exhibit 2, Idaho Power has underpaid Tamarack $183,185.41
for the period from January 1, 2012 to December 31, 2012. Tamarack urges that Schedule 89
should be revised to be effective as of June 1, 2010. As a consequence, and in addition to the
$183,185.41, Tamarack is also owed $274,245.82, consisting of $106,591.93 for the period from
June 1, 2010 to December 31, 2010 and $167,653.89 for the year 2011.
3. Circumstances Surrounding the Establishment of Idaho Power's NPSE in the
2010 PCA
When the Commission first addressed rates for energy purchased from CSPPs in the early
1980s and for some time thereafter, Idaho Power GRCs were routine. One Idaho Power
executive has characterized the company's rate case activity/regulatory agenda during this period
as "considerable" and "active." See Case No. IPC-E-09-30, Direct Testimony of John R. Gale,
Idaho Power Company, pp. 7, 8 ("Gale Testimony"). Except for more recent instances (i.e.,
1995 and 2009)4 , GRCs continued to be routinely filed by Idaho Power. In the early 1980s there
also was no established PCA mechanism.5 The annual PCA mechanism was developed to better
account for the dramatic fluctuations in Idaho Power's energy costs year-to-year. See IPC-E-92-
25, Order 24086 at 2.
4 Tamarack understands that a rate case "moratorium" first appeared in the mid-1990s by stipulation of
parties. Order 26216, Case No. IPC-E-95-1 1. A rate moratorium approach was taken again in 2009 as discussed
below.
The PCA mechanism was first adopted by the Commission in Order 24806, Case No. IPC-E-92-25.
Page 7 of 13
a.The Contemplated 2009 GRC and Stipulated Settlement
In August of 2009, Idaho Power filed a notice of intent to file a GRC by the end of
October 2009. In subsequent meetings among Idaho Power, Commission Staff and
representatives of Idaho Power customers a stipulation was reached by which, among other
things, Idaho Power would seek Commission approval to accelerate amortization of its
accumulated deferred investment tax credits ("ADITC") to help the company achieve an actual
9.5% return on equity. In addition, the parties stipulated that Idaho Power would request
Commission approval of a change to the base level for NPSE to be used prospectively for both
its base rates and PCA calculations in the impending 2010 PCA. This component of the
stipulation was intended to accommodate Idaho Power's asserted need for "some additional
general rate relief," by addressing the "largest single element of [Idaho Power's] unmitigated
revenue requirement." See Case No. IPC-E-09-30, Gale Testimony, pp. 10, 13. The parties also
agreed that Idaho Power and its customers would share in any PCA rate reduction according to
an agreed-upon formula. See Application of Idaho Power Company, Case No. IPC-E-09-30.
In return, Idaho Power agreed not to file its contemplated GRC. Had the stipulation not
been reached and ultimately approved by the Commission, Idaho Power's intended GRC would
have been filed, and absent unforeseen circumstances, Idaho Power expected the new general
rates would have been in effect by June 1, 2010. See Case No. IPC-E-09-30, Gale Testimony, p.
10.
b.Approval of the Stipulation and Proposed Base Level NPSE Increase
The Commission approved the stipulation on January 13, 2010 in Order 30978. The
following week Idaho Power filed its application seeking approval of an increase in its base level
of NPSE by $78.4 million.6 IPC-E-10-01. A base level NPSE of approximately $147 million
had previously been authorized in Idaho Power's 2008 GRC, IPC-E-08-10. Idaho Power
Page 8 of 13
contended that the increased NPSE was in part the result of increased coal costs, which
accounted for approximately 43% of the proposed base level NPSE increase. According to
Idaho Power witness Scott Wright, since the 2008 GRC "[t]he cost of coal burned at the Valmy
plant has increased, thereby increasing the fuel cost portion of power from the plant from $24.12
per MWh to $30.44 per MWh." Case No. IPC-E-10-01, Direct Testimony of Scott L. Wright,
Idaho Power Company, p. 8.
The Commission accepted the $63,701,694 increase in base level NPSE outside of a
GRC as a "working number" for the upcoming 2010 PCA filing. The final calculation and
determination was deferred to the 2010 PCA to allow for further consideration of Idaho Power's
coal costs associated with its Bridger plant. Order 31042 at 8.
c. The 2O1OPCA
When the 2010 PCA case was filed in April 2010, as Case No. IPC-E-10-12, Idaho
Power requested an order approving its proposed quantification of the 2010 PCA and approving
an increase in base rates per the stipulation, including the $63,701,694 increase in base level
NPSE approved in Case No. IPC-E-09-30. One effect of the two proposed rate adjustments
would be a decrease in revenue requirement to be recovered from customer rates (i.e., a net
customer rate reduction) of approximately $58 million to be reflected in revised customer class
schedules. Case No. IPC-E-10-12, Application at 1; Direct Testimony of Timothy B. Tatum,
Idaho Power Company, April 15, 2010, p.12, and Exh. Nos. 2, 3.
After reviewing additional information and comments filed by the parties concerning
Idaho Power's Bridger coal costs, the Commission re-affirmed the $63,701,694 increase in base
level NPSE that had been conditionally approved in Case No. IPC-E-09-30. Order 31093 at 14.
The Commission further directed that Idaho Power file updated tariffs so that the rate decrease
from the PCA and the increase in base rates would take effect on the same date (i.e., June 1,
6 Subsequently agreed to be reduced to $63,701,694.
Page 9 of 13
2010). Id. at 16 and Attachment A. Significantly, pursuant to the approved stipulation, Idaho
Power and its customers each shared in the approximately $147 million of PCA revenue
reduction, allowing approximately $58 million to be credited to reducing customer rates by 6.5%
and $88 million ($64 million of which were attributable to increased energy costs) to be put into
Idaho Power's base rates.
d. The 2O11GRC
In June of 2011 Idaho Power initiated its most recent GRC proposing an increase in base
rates by 9.9% and asking its rate increase to become effective on January 1, 2012. IPC-E-1 1-08.
The base levels for power supply expenses requested and ultimately approved in the 2011 GRC
were unchanged from the 2010 level approved by Orders 31042 and 31093, which again, took
effect as of June 1, 2010.
As far as Tamarack is aware, the 2010 PCA is the only proceeding in which the
Commission has adjusted Idaho Power's base rates outside of a GRC. The reason this was done
was to facilitate settlement and "establish a new normalized net power supply expense level for
both the Power Cost Adjustment and base rates." Idaho Power believed this level of rate relief
was necessary to allow it to agree to a GRC moratorium. Case No. IPC-E-09-30, Gale
Testimony, pp. 6-17.
STATEMENT OF POSITION
The 1981 Tamarack PSA was drafted to comport with the Commission's directives that
utilities purchasing energy from CSPPs were required to pay their full avoided cost, and that a
CSPP opting to enter into a firm energy contract was to receive levelized capacity payments and
variable energy payments for energy delivered. The Commission concluded that "in the long
7 See Case No. IPC-E-1 1-08, Direct Testimony of Timothy E. Tatum, Idaho Power Company, June 1, 2011
p. 4 ("Second, Mr. Said instructed me to hold normalized total power supply expenses and other Power Cost
Adjustment ("PCA") accounts to 2010 levels approved by Order No. 31042 with adjustments to recognize revenues
from Hoku Materials, Inc. ("Hoku") and projected demand response incentive payments." (Emphasis added).
Page 10 of 13
run, a policy based on Idaho Power's estimated avoided costs at delivery time reduces the
financial risk to both the utility and the QF" due to the significant fluctuations in Idaho Power's
energy costs both seasonally and year-to-year. Order 15746 at 19. As such, the Commission,
Tamarack, Idaho Power and the Tamarack PSA all contemplated that energy payments to
Tamarack would be adjusted to coincide as nearly as possible with Idaho Power's actual avoided
energy costs as and when they were periodically determined by the Commission.
In 1981 the mechanism by which those fluctuating energy costs could be routinely
accounted for and incorporated into computations of payments to be made to CSPPs by Idaho
Power was the GRC. Since then, the annual PCA mechanism has developed, and as was
demonstrated in 2010, the annual PCA also can also be a mechanism by which Idaho Power's
base level NPSE (and avoided energy costs) are identified and adjusted. Here that occurred by
stipulation of parties and approval by the Commission.
If effect is to be given to the Commission's policies governing the Tamarack PSA and to
the parties' understanding in entering into a PSA developed pursuant to those policies, then
payments to Tamarack are to be adjusted as and to the extent that Idaho Power's actual avoided
costs are identified and determined in a rate proceeding. Whether that occurs in a GRC or PCA
makes no difference.
Here, Idaho Power's base level NP SE was adjusted upward in the 2010 PCA, in large part
to reflect the significant increase in coal costs at its Valmy, Bridger and Boardman coal
generating plants. The new rate was approved by the Commission effective as of June 1, 2010
and has remained the effective base level rate ever since. The stipulation and order that
permitted this base rate adjustment outside of a GRC allowed Idaho Power customers and Idaho
Power to share in a $147 million PCA rate reduction effective as of June 1, 2010. In this light it
is difficult to contemplate why Tamarack would not also be afforded the benefit under its
Page 11 of 13
contract of the adjusted base level NPSE, which reflected Idaho Power's actual avoided costs as
of June 1, 2010.
The $274,245.828 at issue for Tamarack here is relatively small compared with the $147
million Idaho Power and its customers shared through the 2010 PCA. As a percentage of the $58
million returned to Idaho Power customers through resulting rate adjustments, it might be
compared to hardly more than a rounding error. But it is significant to Tamarack. Of course,
Tamarack should receive payments under its PSA reflecting Idaho Power's increased unit
avoided energy costs as of June 1, 2010, not because the amount is relatively small, or simply
because it would seem fair to allow Tamarack to benefit from the same circumstances that
permitted Idaho Power and its customers to avoid a GRC in 2010. Tamarack should receive
payments under its PSA reflecting Idaho Power's increased unit avoided energy costs as of June
1, 2010 because the Tamarack PSA and prior Commission orders require Idaho Power to
purchase energy at its full avoided cost as and when those costs are determined and incorporated
into Idaho Power's own rates.
CONCLUSION
For the reasons stated above, Tamarack urges the Commission to direct Idaho Power to
revise and file its Schedule 89 tariff to be effective as of June 1, 2012, and to remit to Tamarack
$457,431.23 reflecting the additional amount Tamarack is owed under its PSA for the period
from June 1, 2010 through December 31, 2012, of which $274,245.82 is for the period from June
1, 2010 through December 31, 2011.
Respectfully submitted this 25th day of January, 2013.
GIVENS RS
By
Michael C. Creamer
8 Not including the $183,185.41 underpayment that is not in dispute.
Page 12 of 13
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 25th day of January, 2013, the foregoing was filed,
served, and copied as follows:
DOCUMENT FILED:
Jean D. Jewell, Commission Secretary U. S. Mail
Idaho Public Utilities Commission 0 Hand Delivered
472 West Washington Street Overnight Mail
Boise, ID 83702- 0074 Facsimile
Facsimile: 208-334-3762 E-mail
SERVICE COPIES TO:
Donovan Walker E U. S. Mail
Idaho Power Company LI Hand Delivered
P0 Box 70 El Overnight Mail
Boise, ID 83707---70 fl Facsimile
[e-mail] E-mail
Michael C. Creamer
Page 13 of 13
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-12-28
TAMARACK ENERGY PARTNERSHIP
EXHIBIT NO. 1
EXHiBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 1 of 41
IDAHO POWER COMPANY
POWER SALES AGREEMENT
TABLE OF CONTENTS
ARTICLE
NO DESCRIPTION __

I Definitions

II Term

II) Sale of Power
IV Purchase Price irid Method of Payment
V Facility, Interconnection end Metering
Requirements
VI Oaration Protection and MaThthninC

VII Liability and Usurnnce

\'flI Land Rights
IX Force Mn3eure

X Liebility, Diieetion

Xi Sev*rI ObIi;.iioas
XII Waiver

XIII Choice of Laws
XIV Govcrnmantl Jurisdjton and
Authorization
XV Disputes
XVI Successors and Astons
XV1 I Modification

XVIII Notices
XIX Additional Terms and Conditions
APPENDIX A
APPENDIX A TABLE 1
APPENDIX A - TABLE 2
APPENDIX 8
APPIINDIX C
APPENDIX D
I
PAGE
4
5
6
9
12
14
15
16
16
17
17
•17
17
18
19
19
19
ExHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 2 of 41
IPCo Facility M______
POWER SALES AGREEMENT
BETWEEN
EN ENERGY INg
AND
IDANO POWER COMPANY
THIS AGREEMENT, Entered into on this 16th day of September,
1981, is between ever Inc a(n) itsbc çporatIon.,
hereinafter refereed to as "Seller", and Idaho Power Company, e corpora-
tion, hereinafter referred to as 'Idaho".
W I T N E S S E T I
WHEREAS, $ulk,r owns or will own and operate a Cogeneration
Facility or Small Power Production Facility with generating capacity of
not more than 10,000 kilowatts and
WHEREAS Seller wishes to sell, and Idaho wishes to purchase,
electric power from the Facility,
THEREFORE, in consideration of the mutual covenants and agt'ee-
mts here1aftcr set forth, the Parties agree as follows:
ARTICLE 1: DFrNlrloNS
As used in this Aroenion* and the appendices and schedules attached
hereto, the following terms shall have the following meanings:
p1y - The AtAlity of the facility to deliver electric
power, eprcssod In kilowatts ("kw'), to the point of delivery.

"Contra pacjy" - That Capacity Identified In Article Ill of
this Aaroament except as otherwise changed as provided herein.
ExmBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 3 of 41
-2-
pJj, The price in S/kw-year set forth In
Article 1V( B) of thi A9recrnent,
Termination" The early termination of this 4greement.
"Current jncit Cost" - The6/kw-year Capacity cost from the
most recent schedule of Capacity costs being published by Idaho and on file
with the Idaho Public Utilities C*ncn.
C!ti!.i - A reduction in the amount of Capacity
provided or to be provided tinder this Agreemont
listch FaaHj,> -, Idaho's local dispatching center.
For purposes of this A9reemnt,The wJt_cL%
tocatodirjajj,çinho Is the i>ainated Dispatch Facility ror the
Seller.
Oispa - That condition of the Facility whereby, through
engineering design, Installed equipment, and operating conditions and proce-
dures, the Facility may be callud upon by Idaho to provide the Contract
Capacity at any time other than periods of Scheduled Maintenance or Forced
FiHty That generation facility described In Article Ill of
this Agreement.
- ,\imy outayo caused by mechanical or electrical
equipment failure that either fully or partially curtails the electrical
output of the Facility,.
fAt " iketric enc"gy, expressed in kilowatt hours
(kwh"), guaranteed to be delivered Liy Seller to Idaho In the quantities and
at the times specified In this Agreement.
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 4 of 41
.3..
lnterconnaction Facilities" All facilities required to be
Installed solely to interconnect and deliver power from Sellers generation
to Idaho's system, including, but not limited to, connection, transforina-
tior, switching, metering, relaying communications and safety equipment,
"Non-Firm norgy" - Electric energy, expressed in kwh to be
delivered by Soller to Idaho on a when, as, and if available basis.
"Point(s ) or ,eiity" - The location(s) specified in Appendix B,
whore Idaho's and Seller's electrical facilities are interconnected. Upon
mutual agreement more than one Point of Delivery may be established.
rj Do" The day commencing at 0001 hours, following the
day during which all features and equipment of the Facility and the Inter-
connection Facilities htvc reiichej a degree of completion and reliability,
such that they are capable of operating simultaneously to delivery power
continuously into Idaho's system; provided that the Operation Date may occur
only after such degree of completion and reliability has been demonstrated
to Idaho's satisfaction which must be confirmed by Idaho in writing. Seller
shall have the duty to obtain the confirmation from Idaho; however, such
confirmation shall not be unreaonnbIy withheld by Idaho.
Piactices" - Those practices, methods and
equipment that are cornmnnly ustd in prudent electrical engineering and
opeintons to operate electric equipment lawfully and with safety, dependabi-
lity, efficiency and economy.
JILd tdMaint*nce" - The periods of time during which the
Facility is shut down for routine maintenance operations with the advance
approval of Idaho, as provided in Article VI(J) hereof.
EXHIBIT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 5 of 41
-4,
SBISILI Fi1it Interconnection Facilities furnished and
owned by Idaho at Seller's request or because such facilities are necessary
additions and/or modifications to idahos system, including eqipmafl re-
quired to protect Idaho's system.
som Avoided Ener9y ço - The incremental variable coat of
electric onery on Idaho's system. Variable costs include ful' costs and
operating and maintenante coats which vary with output of thermal plants,
firm power purchases and spot mnrkct purchases.
"UnitLed Ln1kMy Cost" - The sum of the v t'Ible costs associ-
ated with the specific genarating unit or project designated by the Idaho
Public Utilities Commission as the basis for the determination of avoided
Capacity cost, Variable costs inciuJc fuel costs and operation and mainte-
nance expenses which very with the designated unit's or project's generation.
ARTICLE ll TERM
This Agreement shall become effective on the data first above
written, and shall continue in full force and effect for a period of
thi rty-flve(3)oars. from the, Operation Date s ending on May 31, 2018.
ARTICLE 1W SALE OF POWER
(A) Seller areoi to deliver and sell and Idaho agrees to accept
and purchase the eqerpy or energy and Capacity from Seller's Facility, In
accordance with Appontihc A snd the Option specified below (Seller to
initial Option 1. 2, 3 or 1..)
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 6 of 41
4'
-5-
Qn 1 - Non-Firm Energy - estimated avoided energy cost;
- 2 - Non-Firm Energy - Avoided energy cost at time of delivery;
- Q 3 - Firm Energy and non-Dispatchable resource Capacity;
X Optjpn Firm Energy and Dispfltchbe resource Capacity.
By selecting Option 4, Seller agrees to provide energy in an
amount estimated to be 139,748 kilowatt-hours per year, The Con- -
tract Capacity $hell be ,,4,942kl$w1L s.
(B)Seller's Facility is described aa. Make ,-Electric Machinery
Modal Serial No .J1440, fuel or energy source Biomass
having a nameplate ouLput rating of 9Q kw (kvs), and 2400/4160
volts, _oo phase, GO hertz,
(C)Seller's rocmity is ltc'd at the Pro-
duct;, Inc. facility in, rack Idaho , and the scheduled Operation Date
of the Facility is June 1, 1083,
ARTICLE IV: PURCHASE PRICE AND METHOD OF PAYMENT
(A),ncj,gy. Idaho shil pay Seller monthly for energy delivered
and accepted at the Avoided lncrgy Cost rota specified in for the Option
selected.
(B)jpjJjy. if Sullur elects to supply Capacity. Seller shall
be paid for Capacity , made evnil.ible to Idaho in Accordance with Appendix A
for the Option selectd. The appt1ceIIq Contract Capacity Price for pur-
poses of computing Capacity payments is $3 1 0 per kIlowatt-year, except as
may be adjusted as providod in Appendix A or Appendix C. The Contract
Capacity Price i* derivod from Table 24 Appendix A. Idaho's obligation to
pay Seller for Capacity furnished to Idaho shell commence as of the Oper-
ation Date.
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 7 of 41
4 'I
Payments For the Capacity provkied in the contract year will be
made in twelve (I2) equal monthly amounts based on the Contract Capacity
Price set forth in this Agrcamt'nt multiplied by the Contract Capacity.
ARTICLE V: FACILITY, INTERCONNECTION AND
MTEfUNG REtJIREMENTS
(A)ScIlar shall design, construct, install, own, operate and
maintain the Facility. Seller agrees to meet reasonable Idaho requirements
for those portions of the Sliers Facility and equipment generating or
transmitting electrical power and for any other equipment which directly
affects Idaho's system. To aid in'determination of Compliance with Idaho's
requirements, Seller ahll stibmit its Facility and equipment specifications
to Idaho for review, Soltor shall not be Interconnected withIdaho's system
unless Sailer receives Idaho's written acceptance of all Facility specifica-
tions. All changes in spocifications, Including new or additions) equipment,
shall similarly be subject to Idaho's acceptance, Idaho's acceptance of
Seller's specifications shall not be construed as confirming or endorsing
the design, or as a warranty of safety, durability, or reliability of the
Facility. Idaho shall not, by reason of any review, acceptance, or failure
to i'oview, be responsitie for the Facility, Including but not limited to the
strength, details of design, adequacy or Capelty thereof, nor shall Idaho's
acceptarCC be deemed to be an endorsement of any Facility.
(B)Seller sl*Il construct, Install, own and rnehttsln lntercon-
noction Facilities as required (or Idaho to receive energy on energy and
Capacity from Seller's Facility, Seller's ln'tsrconnectiofl Facilities shall
ExmrnT No.!
CASE No. IPC-E-12-2$
COMMENTS, Tt1c&i.&cK
Page 8 of 41
be of a size to accoinodate the delivery of the energy or energy and capa-
city designated in Pt'agrophs 111(A) and VI(F) of this Agreement. Setter
shalt allow Idaho to review the adequacy of all protective devices and to
establish requirements for settings and periodic maintenance end testing of
protective devices. At Seller's request, ideho will construct, install,
own and maintain the !torc0nnect1on Faculties as Special Facilities. If
Seller requests Idaho to Install Special Facilities or if Idaho determines
that It Is necessary to install Spciel Facilities, Seller shall reimburse
Idaho for its costs relating to those Spacial Facilities In accordance with
the terms and conditions of Appendix B--"Spcil Facilities and Point(s) of
Delivery and Metering"
(C) Idaho shil provide, Install and maintain motors to be lo-
cated at a mutually agreed upon location to record and measure power flows
to Idaho. If required by Idaho, motoring will also Include measurement of
kilovar-hours and secondary meters at locations within Seller's Facility,
agreed to by both parties. All motor equipment, installation, ownership and
administration costs, therefore shall be horns by Seller, Including costs
incurred by Idaho for Inspecting and testing such equipment at Idaho's
actual cost of providing this eulpineat and services, Appendix 0--
"Standards for Interconnection and Metering" describes the metering son-
figurations Idaho will utilize.
(0) Except as otherwise agreed by the parties, metering will be
provided for recording net output of the Facility and will be separate
from metering of Seller's load. Idoho'n sates to Seller shell continue to
be metered in accordance with the terms of the service agreement, If any,
existing between the pirttes, end/or otherwise in accordance with tariffs
filed and approved by the regulatory authority having jurisdiction.
ExHmrr No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 9 of 41
(E)The point of metering for energy or energy and Capacity to
Idaho's system shaH be at the location described in Appendix B.
(F)All meters used to determine the billing hereunder shall be
sealed and the seals shall be broken only upon occasions when the meters are
to be inspected, tasted or adjusted.
Idaho shall, at Salters expense, inspect and test all meters upon
their Installation and nt least once every two years theroaftor. If requested
to do to by Seller, Idaho shall inspect or test a meter more freiventIy than
every two years, but the expanse of such inspection or test shall be paid by
Seller unless upon being Inspected or tested the meter Is found to register
inaccurately by more than two percent of full scale. Each Party shall give
reasonable notice of th flino WhUn any Inspection or test shall take place
to the other Party, and that Party may have representatives present at the
test or Inspection. If a motor is found to be inaccurate or defective, It
shell be adjusted, repaired, or replaced, at Idaho's expanse, 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 from the measurement
madeby the standard meter used in the tat, adjustment shall be made correc-
ting all measurements Tncdc by the Inaccurate motor for:
(1) the actual period during which inaccurate measurements were made,
If the parlqd can be determinad or if not
( the period Immediately preceding the test of the meter euaI to
one-half the time from the date of the last previous t*t of the
meter; provided, that the period covered by the correction shall
not exceed ab months.
EXHIBIT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 10 of 41
Each Party, tifter reasonable notice to (he other Party, shall have
the right of access to all meie*'lng and related records.
VI: OPERATION. PROTECTION AND MAINTENANCE
(A) Seller shall operate and maintain the Facility and Seller
furnished interconnection Facilities in accordance with Appendix D--Stan-
dards for Interconnection and hiolaring, Prudent Electrical Practices, the
National Electric Safety Code as modified from time to, time, and any other
applicable local, State and Federal codes. If, in the opinion of Idaho,
Setter's oparetion of the Facility or Interconnection Facilities is unsafe
or may otherwise edvercly effect Idaho's equipment or personnel, or those
of other Setters or tdnh0' othor customers. Idaho may physically Interrupt
the flow of energy from the Facility or take such other stops as Idaho deems
appropriate.
(13) Idaho shell, at all tunas, and under all conditions, control
the intertie between Seller's Facility and Idaho'* system. This control
will be accomplished by the Seller's installation of lnterconnetlon Fad'
HUes which will purmit Idaho to remotely control the operation of the
Intertie, These Interconnection Facilities and their operation are more
particularly described in Appendix B.
(C)Solier shall provide and maintain adequate protective eqUip-
inent sufficient to prevent damage to the Facility.
(D)Seller' shall use Its best efforts to minimize voltage swings
and to maintain voltage lvols acceptable to Idaho. Idaho may, upon one
hundred eighty (ICO) days' notice to Seller, change Its nominal operating
voltage level by more then ten percent (lOt) at the Point(s) of Delivery,
EXHIBIT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 11 of 41
in which ease Seller shall modify, at Idaho's expense, Snllers equipment
as necessary to accommodate the modified nominal operating voltage level.
(E)Seller ag'ces that in the event of and during a period of a
shortage of energy or energy and Capacity on Idaho's system as declared
by Idaho in Its solo discretion, Seiler thall, at Idaho's request and
within the limits of roortabIa safety requirements as determined by Seller,
use its best efforts to provide requested energy or energy and Capacity,
and shall, if necessary, delay any scheduled shutdown of the Facility. In
the event ldai,* requests a delay of a scheduled shutdown and as a result of
complying with this request, Seller incurs unavoidable liabilities for
scheduled maintenance services to be provided by third parties, Idaho agrees
to reimburse Seller for its Payment of such liabilities.
(F)Seller shall limit both kilowatt and reactive kilovolt-
ampere flows through this Point of Delivery so that the vector sum of such
flows shall not at any one time exceed not aplicabIe
kilovolt amperes. Additionally, Seller shall maintain a power factor at
the Point of Delivery of not icas than ninety-five percent (90) lagging.
In the event that Seller shall fail to limit real and reactive flows or to
maintain the required power factor as herein provided, Idaho may, In addition
to any other remedy available at law or In equity, require the Seller to
compensate Idaho for vors supplied by Idaho, install adequate oapaeltars or,
if required for safety, or system stability, physically interrupt all service
and interconnections without prior, notice and without liability therefor.
(G)Seller shall report monthly to the Designated Dispatch Facility
the times, by hour and minute, of opening and closing his generator breaker
and the corresponding kwh motor reading at the time of opening as wall as
ciosinl the breaker.
EXHIBIT No.1
CASE No. IPC-E-12-28
CoMMENTs, TAMARACK
Page 12 of 41
on
Idaho and Seller shell maintain appropriate operating communica-
tions through Idaho's Designated Dispatch Facility. These conmunicstkns
are described in Appendix D.
(H)Idaho shall not be obligated to accept, and Idaho may re-
quire Salter to curtail, interrupt or reduce deliveries of energy or energy
and Capacity if Idaho determines that curtailment, interruption or reduc-
tion is necessary because of line construction or maintenance requirements,
emergencies, operating conditions on Its system, or as otherwise required
by by Prudent Electrical Practices.
Except in the event of force mejeure, if the requires, pursuant
to this prevision, a curtailment, interruption or reduction of energy
deliveries that c,co'ds twnty Jays froin the twontyfirst day of such
interruption, curtailment or reduction until Idaho notifies Seller that. it
Is ready to accept full energy deliveries, Seller will be deemed, for
purposes of determining the monthly energy payment, to be delivering energy
at the same average rate as Seller was delivering energy for the 30 day
period immediately preceding the curtailment, interruption or reduction.
(I)In the event Idaho is required by the Idaho Public Utilities
Commission to institute curtailment of energy deliveries to its customers,
Idaho may require Seller or Seller's fuel supplier, ivcrgreon Forest Pro-
ducts, Inc. to curtail its consumption of electricity in the some manner
and to the same deyrcmo as other customers within the same customer class
who do not own facilities for generating etectricty.
U) If Seller elects to deliver energy and Capacity. Seller may
shut down the Facility for Scheduled Maintenance of a total period not to
exceed thirty (30) days during each contract year. Seller shall submit its
EXHJBJT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 13 of 41
proposed maintenance maintenance schedule for each calendar year by the proceeding
February 1, and Idaho shell Inform Seller of the acceptability or unaccept-
ability of the proposed date(s). To the extent reasonably, posslbIe
Seller will attempt to perform Its chedulcd maintenance during Idaho's
off-peak months, (March, April, October and November). Seller and Idaho
will coordinate, insofar as possible, Seller's periods of Scheduled Main-
tenance with any line Construction or maintenance by Idaho that would
require a curtailment, interruption or reduction of deliveries of energy
under Paragraph (H).
AR-Elcu! VII: UAUILITV AND INSURANCE
(A)Each Party shall indemnify the other Party, its officers,
agents, 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 shell, or th uthr Party's request, defend any suit asserting a
claim covered by this indmn1ty. The Indemnifying Party shall pay all
costs that may be incurred by the other Party in enforcing this indemnity.
(B)Prior to Interconnection of Seller's Facility with Idaho's
system, Seller shall, secure aftc.1 itiuousy cerry Insurance coverue as
indicated below,
LIABILLTj The covarajio provided must include or be equivalent
to comprehensive liability insurance policies for both bodily Injury
and property damage liability In the following amount**
EXUIBIT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 14 of 41
in
(a)For Facilities up to 5,000 14lowatt S1 ,000000
combined single limit.
(b)For Facilities 5,0OO kilowatts and larger, 85,000,000 cam-
bird single limit.
Such insurance, shall include an endorsement naming Idaho as
an additional Insured insofar as work performed under this 'Agreement
Is concerned; a r'oviskmn that such liability pollee shall not be
cancelled or their limits of liability reduced without thirty (30)
days' written notice to Idaho. 5oller, shall furnish'Idaho, prior to
commencing performance hereof, but not less than thirty (30) day*
before the scheduled Operation nato, certificates of insurance, to'
other with the andors'mrnts required therein. Idaho shall have the
right to inspect the original policies of such lnsurcince,
(C) Seller agrees to obtain insurance acceptable to Idaho cov-
ering property damage or destruction of the Facility and Seller-owned Inter-
connection Facilities (insured property) in an amount not less than the
cost of replacement of the insured property. Idaho shall be a named Ions
payee on all such Insurance pIlcies. Seller' shall promptly notify Idaho
of any loss or damage to the insured property. Idaho may make proof of
loss if Seller fails to do so within fifteen (I) days of the casualty.
Unless the 'parties agree otherwise, Seiler shall repair or replace the
Insured property. Procoeds from said casualty insurance policies shell be
paid into an escrow account with disbursements from that account to be used
solely for rnptilring or replacing the insured Property, In the event the
parties agree the Insured property cannot be eonomically repaired or
replaced, Seller shall pay, to Idaho, from said escrow account, the amount
EXImsIT No.1
CASE No. IPC-E-12-28
COMMENTS, Ttit&itci
Page 15 of 41
-14-
owing under the refund Obligation of seller to Idaho as. set forth In the
terms and conditions of Appendix C. The balance In the escrow account, In
the event the insured property Is not repaired or replaced, shall become
the property of the Seller.
ARTICLE V)11;,LAND RIGHTS
Seller hereby grants to Idtho for the term of this Agreement all
necessary rights-of-way rind eiscnicnts to instli, operate, maintain, re-
place, and remove Idaho's metering and ether facilities necessary or useful
to this Agreement, including adequate and continuing access rights on
property of Seller. Seller agrees to execute such other grants, deeds or
document as Idaho may require to enable it to record such rights-of-way
and easements, If any part of the Interconnection Facilities must be
Installed on property owned by other than Idaho or Seller, Seller shall, If
Idaho is unable to do so without cost to Idaho, procure from the owners
thereof all necessary rights-of-way and easements for the construction,
operation, maintenance, ond replacement of the Interconnection Facilities
upon such property In a form satisfactory to Idaho. At Sailor's request,
Idaho shall, to the Oxtent it is legally Able, acquire such .'iphts-of-way
at Seller's CoSt,
ARTICLE IX: FORCE MAJIJR
As used in this Agreement, "Force Majeure" means unforeseeable
causes beyond the reasonable control of and without the fault or negllgcnc*
of the party claiming Force Majeuru, Including, but not limited to govern-
mental action, and specifically excludes strikes, walkouts, lookouts or
ExHIBIT No.1
CASE No. IPC-E-12-28
COMMINTS, TAMIL&cIc
Page 16 of 41
other labor disputes In which Idaho, Seller, Evergreen Forest Products
Inc, or their, respective employees participate. if either party is rendered
wholly or partly unable to perform its obligations under this Agreement
because of Force Majeure, both parties shall be excused from whatever
performance is affected by the Force Majeure to the extent so effected,
provided that
(A) The non-porforniiiig party shall, as soon as is reasonably
possible after the occu renco of the Force Majaurn, give the other party
written notice describing the particulars of the occurrence;
(13) The suspension of performance be of no greater scope and of
no longer- duration than Js required by the Force Majeuro;
(C) No ohligAtous of either party which arose before the occur-
rence causing the suspension of performance shell be excused as a result of
the occurrence; and
(0) The non-performing party shall use its best efforts to
remedy its Inability to perform. This subparagraphs shall not require the
settlement of any strike, walkout, lookout or other labor dispute on terms
which, In the sole ,iudRrnent of the party Involved In the dispute, are
contrary to to its Interest. It is understood and agreed that the settlement
of strikes, walkouts, loukouts or ether labor disputes shall be entirely
within the discretion of the perty having the difficulty; provided that, In
the event of a strike nffcting Seller's Facility, Seller shell use Is
best efforts to operate the Facility with management personnel,
ARTICLE X: LIABILITY; DEDICATION
Nothing in this Agreement ,thntl be construed to create any duty
to, any standard of care with reference to, or any liability to any parson
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 17 of 41
-16-
not a Party to this Agreomont. 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, nor affect the status of Idaho as an Independent public utility
orporation or Seller as an lndrendont individual or entity.
ARTICLE Xi: SEVERAL OBLIGATIONS
Except where specifically steted in this Agreement to be otharwis,,
the duties.. obligations and liabilities of the Parties are intended to be
several and not joint or collective. Nothing contained in this Agreement
sh*li ever be construed to create an association, trust, partnership, or
Joint venture or lmpus a trust or partnership duty, obligation or liability
ót or with regard to either Party. each Party shall be Individually and
severally liable for its own obligations under this Agreement.
ARTICLE Xli: WAIVER
Any waiver at any tinie by either Party of its rights With respect
to a default under this Arcement, or with respect to any other matters
arising in connection with this Agreement, shall net be deemed a waiver
with respect to any subsrquviii default or other matter.
ARTICLE XItl; CHOICE OF LAWS
Tills A9reemant shall be construed and interpreted in accordance
with the laws of the State of Idaho,
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 18 of4l
-11-
AfTICLE XIV: GOVERNMENTAL JURISDI,CTION AND AUTHORIZATION
This Agreement is subject to the jurisdiction of those govern'
mental agencies having control over either Party or this Agreement. This
Agreement shall not become effective until all required governmental authorl-
zations and permits are first obtained and copies thereof are submitted to
Idaho: provided that this Agrement shall not become effective'Unless it,
and all provisions thereof, are authorized and permitted by such govern-
mental agencies without change or condition.
If after this Agreement becomes effective any governmental agency
having jurisdiction over the Seller requires any change In this Agreement,
or imposes any condition or obligation on the Seller for which Seller can
show good cause that the condition or obligation renders this Agreement
unreasonably burdensome, the Seller may terminate this Agreement,
ARTICLE '(V; DISPUTES
The Parties hereto recognize and agree that:
(A)The Public Utilities Regulatory Policies Act of 1978 (PURPA)
conferred on the Idaho Public Utilities Commission (Commission) the obliga-
tion and authority to require Idaho to purchase energy or energy in capacity
from qualifying cogenaratlen and small power productionFacilities: and
(B)Pursuant to that authority and to promote uniformity among
the various electric companies within its jurisdiction, the Commission con-
ducted Investigations and held hearings regarding cogeneration - small
power production, i3esod on those hearings, the Commission Issud Orders No
15746 and 16026, which Orders, In addition to ostblishing the rates to
paid Seller for energy or energy and Capacity, specified the lottn and terms
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 19 of 41
-18-
and conditions of standard contracts, including this Agreement and required
Idaho to offer this Agreement to Seller and any other owners or owners and
operators of Qualifying cogeneration small power production Facilities.
(C) in light of these facts the Parties agree that if tha Com-
mission determines that any term or conditions of this Agreement or the
standard contracts It has required Idaho to offer to Seller and others Is
contrary to the public interest, the Commission may modify those terms or
conditions and such modifications will be binding on the Parties.
It Is further understood and agreed that this Article XV, is not
to be construed as permitting Idaho to inquire Into the operation of Seller's
Facility or other business, nor attempt to bring Seller under the commission's
regulation.
ARTICLE XVh SUCCESSORS AND ASSIGNS
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, save that no assignment hereof by Seller
shell become effective without the written consent of Idaho being first
obtained. This Article shall not prevent a financing entity with recorded
or secured tights from exorcising all rights and remedies available to It
under law or contract. Idaho shall have the right to be notified by The
financing entity that It is exercising such rights or remedies.
ARTICLE XVII: MODIFICATION
No modification to this Agreement shall be valid unless it Is In
writing and signed by both Parties hereto.
EXIHBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 20 of4l
ARTICLE XVW: NOTICES
All written notices under this Agreement shall be directed as
follows, and shall be considered delivered when deposited in the U S Mall,
first-class Postage prepad, as follows
To Seller; Evergreen ne'gy, Inc
Dcx H
New Meadows, Idaho 83654
To Idaho: Vice President, Power Operations
Idaho Power Company
1220 Idaho Street
Boise, Idaho 83707
ARTICLE XIX: ADDITIONAL TERMS AND CONDITIONS
This Agreement includes Appendices A, B6 C and 0 which are
attached hereto and included by reference.
Appendix A - Schedule of Power Purchase Rates
Appendix B - Special Facilities and Point(s) of Delivery and
Metering
Appendix C - Adjustment of Capacity Payments in the Event of
Termination or Reduction
Appendix 0 - Standards for Interconnection and Metering
IN WITNESS WHEREOF, The Parties hereto have caused this Agree-
ment to be oxecuted In this respective names as of the data first above
written,
ExmBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 21 of 41
EVERGREEN ENERGY INC
IDAHO POWER COMPANY
By f
Praiident
By
Vice Pres tent
im
EXHIBIT No. 1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 22 of 41
APPENDIX A
COGENERATION AND SMALL POWER PRODUCTION
SCHEDULE OF POWER PURCHASE PRICES
A-i f2ENERALROV1StOWS
This schedule of purchase prices shall be the basis UPOfl which
Idaho will make Payments to Seller for energy or energy and Capacity de-
liveries from Seller's lacilitics under Options 1 2. 3 and 4.
(A) Option 1- Non-Firilt Fnery___
Under this Option Idaho will pay Seller for energy delivered and accepted at
a rate equal to Idaho's estimated average monthly System Avoided Energy
Cost. The System Avoided Energy Cost is the incremental variable coat of
electric energy on ldhos system. Variable cots include fuel costs and
operating and maintenance expenses which vary with output of thermal plants,
firm power prchsses and spot mr at purchases. The System Avoided En&'gy
Cost will be estimated for each men h of the year, will be updated annually,
and will be filed with the icltho p tjic Utilities Commission. Tha attached
Table I shows the ostitimted annue Systom Avoided Energy Cost schedule.
The seller will be provided an up ate of Table 1 each year. The amount
shown on Table i, includes on aggregate capacity payment of 3 mills per kwh,
(8) Qjgn
Under this Option ld.,ho will pay Seller for energy delivered and
accepted at a rate equal to Idaho's System Avoided Enegy Cost for each
month of the year. The System Avoided Energy Cost is the incremental
variable cost of electric energy on Idaho's system. Vaj'inbi* costs include
APPENDIX A
Page 1 of i
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 23 of 41
average fuel cost and operating and maintenance expenses which vary with
output of thermal Plants, firm power purchnses and spot market purchases.
The System Avoided Energy Cost will be døtormined at the end of each calen-
dar month and will be on file with the Idaho Public Utilities Commission.
Payments for the month will be made on the bask of that months filed
(C) 9n3*Firm Enry and gt eicj.
Payments under this Option will equal the sum of the Energy Component and
Capacity Component described bolow. Tho amount of each component is deter-
mined by reference to the attached Table 2.
(1)y Corn onpnt, The energy component will be calculated
by multiplying the kwh of energy delivered and accepted by the esti-
mated annual Unit Avoided energy Cost specified in Table 2. The Unit
Avoided Energy Cost is the sum of the variable costs associated with
the specific generating unit or project designated by the Idaho Public
Utilities Commission as The basis for the determination of avoided
Capacity cost. Variable costs include fuel costs and operating and
maintenance expenses which vary with the designated unit's or Project's
generation, The Idaho Public Utilities Commission may, by Order,
modify the Unit Avoided Enargy Costs. Idaho will file with the Idaho
Public Utilities Commission a tariff specifying the affective Unit
Avoided Energy Cost.
(2)The Contract Capacity payment to Seller
of a non-blaptachable resource will be based on the Facility's projected
long-term average annual energy production in kwh as agred upon by
the Parties. That amount will be divided by the product of 8780 hours
per year multiplied by 75, thereby producing the Contract Capacity.
APPENDIX A
Page 2 of 5
ExWIT No.!
CASE No. VC-E-12-28
COMMENTS, TAMARACK
Page 24 of 41
In order to qualify for a Capacity Payment under this Option 3,
the following provisions must be mat:
(a)The Contract Capacity must be available for the term of
the agreement,
(b)Contract Capacity must be available for a minimum of
one (1) year.
(3) The Contract CapacIty may be adjusted in the ent there Is
a change In any of the factors used In calculating the Facility's
long-term average annual energy production. Such adjustment mayIn-
elude a Capacity Sale Reduction or Contract Termination in accordance
with Appendix C.
()) Option 4 flrm Eriargy and 01spatchable esource Capcji. Pay-
ments under this Option will equal the sum of the energy component and the
Capacity Component described below, The amount of each component is deter-
mined by reference to the attached Table 2.
('I) Eneravoipnent. The energy component will be calculated by
multiplying the kwh of energy delivered and accepted by the estimated
annual Unit Avoided energy Cost specified In Table 2. The Unit
Avoided Energy Coat Is the sum of variable cost associated with the
specific generating unit or project designated by the Idaho Public
Utilities Commission as the basis for the determination of avoided
capacity cost. Variable costs include fuel costa and operating and
maintenance epxnses which vary with the designated unit's Or project's
generation, The Idaho Public Utilities Commission may, by Order,
modify the Unit Avoided energy Cost. Idaho will file with the Idaho
Public Utilities Commission, a tariff specifying the effective Unit
Avoided Energy Cost.
APPENDIX A
Page 3 of 8
ExmBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 25 of 41
(2) Capacity Cornpq. The Contract Capacity payment to a
Seller of a Disioatchable Resource will be based on the generating
capacity of the Facility as specified by Seller; however, in order to
qualify for a Capacity payment under this Option 4, the following
provisions must be met
(a)The Contract Capacity must be available or actually
delivered to Idaho such th,t the energy made available in iily twelve
(12) month period or actuliy delivered in such period to Idaho di-
vided by 8760 hours in such period Is no less than sixty-five percent
(85) of the Contract Capacity to allow for Forced Outages and Scheduled
Maintenance,
(b)Contract Capacity must be available for a minimum of
one (1) year.
(3) Seller may increase the Contract Capacity with the written
approval of Idaho, and subsequent payments for the additional capacity
will be in accordance with the Current Capacity Cost Schedule contained
In Appendix A, Table 2.
(4) Idaho may derate tile Contract Capacity as a result of appro-
priate tests, studies or prior performance. If such dersting occurs
after the facility is In operation, it will constitute a Capacity Sale
Reduction and will be subject to Appendix C.
A-2 ADJ USTMENT TO WNIfkAC CAPACIT Y P .IC
The Contract Capacity Price will be adjusted upward to the Cur-
rent Capacity Cost as of the Operation Date if the scheduled Operation Date
specified In Article 111(C) is nwt. The Current Capacity Cost Schedule, If
higher, shall 'be attached to this Agreement and shill supersede Table 2 of
APPENDIX A
Page 4 of 5
EXHIBIT No.!
CASE No. !PC-E-12-28
COMMENTS, TAMARACK
Page 26 of 41
this Appendix. If the scheduled Operation Osta is not met, the C4ntr3ct
Capacity Price specified In Artlo IV will opply.
APPENDIX A
Page 5 of 5
ExHIBiT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 27 of 41
o
00
&r,plwIx *
TABLE I
14 S1rn&TEG AVOIDED EMIflGY COSTS BY 4O1tftS
CENTS/Mt -
.urnuly 2.20
rebrary
ArH 2.33 Ray 2.26 June 2 96
July LBS
41
.
16 As#906t September 3 M October L93 tcvcer 2.5? December
(tote: The pflces SEaLad ebOc eswa rkot ?Me total a*i*rE at enerBy purchased by de ?oIco Capany
from QVaHlyfn FacitWas does net axeBod 50
average aøgaVeLts. At such as Idaho Pwet Company's purchases from qualitylve Iac;Utics. 50 ova rage ecgewatI.s., men prices vr il be adjusted appropriately.)
gI 1 i -4
N
1.

N 9 4 C' 1-fli

N N a .. fl
-4 N 0 C'
.4
Owl
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTs, TAMARAcK
Page 29 of 41
APPENDIX "B
SPECIAL FACILITIES AND POINT(S)
OF DELIVERY AND METERING
Point
The Point of Delivery of anergy from the Seller to Idaho wiLl be the
conductor terminations on th6 deadand structure of Idaho's 69 kV line
adjacent to the Seller's facility. The Seller shell deliver the
energy from the generator, through the transformer, and through a 69
kV oil circuit breaker to the Point of Delivery. The transformer will
be 2,400 Volts to 60,000 Volts. The transformer and oil circuit
breaker will be owned and niiintain*d by the Seller.
8-2 Meteripg
The metering equipment will be on the 2,400 Volt side of the transfor
,

mar, and will consist of meters, recorder, Instrument transformers,
associated wiring, and a building. The mater readings will be adjusted
to compensate for energy losses through the transformer.
0-3 Seciel Fc1fltJes
The construction of approximately 1.000 feet of 6$ kV transmission
line, including air break switches, to the deadend structure at the
Seller's facility will be provided and owned by Idaho as Special
Facilities.
B4 hIngctrol
A communications circuit will be installed between the generating
facility and the Designated Dispatch Facility which will allow the
Seller to close the oil circuit breaker only after the Idaho 41s
APPENDIX a
Page 1 of 2
ExmBrr No.!
CASE NO. LPC-E-12-28
COMMENTS, TAMARACK
Page 30 of 41
patcher has qivc6 permission by operating a control relay. The oil
circuit breaker will be so controlled that it can not be closed unless
the Idaho dispatcher operates the control relay. All such communica
tkn circuits will be provided and maintained by the Seller.
B-5 Costs
Installation costs of tile.metering equipment is $5,980. lnstaliation
and Construction costs of Special Facilities is $22,00. Total amount
to be paid to Idaho by the Seller is $28,480. This amount will be
paid to Idaho at least 30 days prior to the scheduled commencement of
Construction or Installation of the facilities and equipment. In
addition to the Installation nnd construction charges specified above,
Seller will pay Idaho an operation and maintenance charge of 0.7% per
month times the total amount specified above.
S-B
No later than sixty (GO) days after the Contract Termination data, or
the expiration date of this agreement, Idaho will prepare and forward
to Seller an estimate of the remai ning value of those Special Facili-
ties described In -1 of this Appendix, less the cost of removal and
transfer to Idaho's nearest warehouse, if the Special Facilities will
be removed. Idaho may then be invoiced by Seller for the net salvage
value estimated by Idaho for the Special Facilities and shall pay such
amount to Seller within thirty (30) days after receit of said invoice.
Seller shall )love the j,jqjjt to offset the invoice amount •gainst any
present or future payments due Idaho.
APPENDIX B
Page 2 of 2
ExififfiT No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 31 of41
APPENDIX "C"
ADJUSTMENT OF CAPACITY PAYMENTS IN THE
EVENT OF TERMINATION OR REDUCTION
C1 GENERAL PROVISIONS
(A) This Appendix shall be applicable in the event there Is a
Contract Termination of a Cnpcity Sale Reduction and Seller is receiving
Capacity payments,
(8) The Parties agree that the amonnt of the payment which Idaho
is to make to Seller for Capacity is based on, the agreed value to Idaho of
Sellers performance of his obligation to provide Capacity during the full
period of the Term OF Agreement, The Parties further agree that In the
event Idaho does not receive such full performance by reason of a Contract
Termination or a Capacity Sale Reduction, (1) Idaho shall be deemed damaged
by reason thereof, (2) it would be impracticable or extremely difficult to
fix the actual damages to Idaho resulting therefrom, (3) the reductions,
offsets and refund payments as provided In this Appendix, as applicable,
are In the nature of adjustments in Capacity prices and liquidated damages,
and not a penalty, and are fair and reasonable, and (4) such reductions,
offsets and refund payments represent a reasonable endeavor by the Parties
to estimate a fair compensation for the reasonable losses that would result
from such termination or reduction.
(C) Seller shall be invoiced by Idaho for all refund payments
due under This Appendix and shall pay such amounts to Idaho within thirty
(30) days after the invoice date,
APPENDIX
Page 1 of 3
ExmBrr No.!
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 32 of 41
(0) Idaho shall have the right to offset any amounts due it
against any present or future payments due. Seller.
C-2 WAMINATION OR ION DUE TO SELLEIVS FAILURE
Except in the event of Force Majeure as defined in Article IX of
the Agreement, in the event the Seller fails to provide all or part of the
Contract Capacity, such failure shall be grounds for Contract Tenintio
or a Capacity Sale Reduction in accordance with the following:
(A) Idaho may immediately suspend or reduce the Capacity pay-
ments to Seller for a probationary period not to exceed twelve (12) months.
(1)if Seller meets or satisfies Idaho that it can meet its
minimum Capacity requirements during the probationary period, Idaho
shall make a retroactive Capacity paynrnnt for the probationary period
and reinstate regular Capacity payments in subsequent years.
(2)II Sailor fails to meet its minimum requirements during
the probationary period, Idaho may permanently derete the Contract
Capacity appropriately or terminate the Capacity purchases,
() in the event Idaho terminates Cascity purchases, pursuant
to this Section C-2, the following will apply:
('I) If the Contract Capacity Is more than one megawatt,
Seller shall refund to Idaho an amount equal to fifty percent (50%) of
the difference between the Capacity Payments already paid by Idaho
(based on the original term of the Agreement) and the total Capacity
Payments which Would have been paid if the Contract Capacity Price had
been based on the period from the Operation Date to the actual date of
Termination,
APPENDIX C
Page 2 of 3
ExHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 33 of 41
(2) If the Contract Capacity Is less than one megawatt,
Seller shall refund to Idaho an amount equal to ten percent (10 06) of
the difference between the Capacity Payments already paid by Idaho
(based on the original term of the Agreement) and the total capacity
Payments which would have been paid if the Contract Capacity Price had
been based on the period from the Operation Data to the actual data of
Termination.
(c)
If, as a result of a strike, walk-out, lockout or other labor
dispute, Sailer will be unable to meet its obligation to provide the Con-
tract Capacity, Seller will notify Idaho and Idaho may purchase power from
another source to replace the power Seller had agreed to provide. Such
replacement power will, for purposes of satisfying Seller's Contract Capacity
oblIgation, be deemed to have been delivered by Seller. The Seller will
reimburse Idaho for the difference, if any, between the amount which Idaho
would have paid to the Seller and the actual cast of the replacement power,
including losses, wheeling and load factoring. Idaho will bill Salle,'
monthly for the reimbursq,npnt amount. Unless otherwise agreed, Idaho will
not be obligated to attempt to procure replacement power for a period
longer than six months. In no event will Idaho pay Seller for Capacity not
actually provided by Seller.
(D) The foregoing rctilodles are not exclusive and Idaho reserves
all rights it may have against Seller as a result of SeIlr's failure to
perform under this Agreement.
APPENDIX C
Page 3 of 3
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 34 of 41
Standards for Interconnection and Metering
D-1 GENERAL PROVISIONS
It is the policy of Idaho Power Company to permit any owner or operator
(Seller) of a qualifying facility to operate his generating equipment In parallel
with the Idaho Power Company (Company) electric system, whenever this can be
done without adverse affect to the Company equipment or personnel or to our
other customers or other Sellers,
These guidelines contain the minimum metering, Interconnection, pro-
tection, operation, and communications requirements for the safe and effective
parallel operation of the Seiler with tile Company system. Although these guide-
lines are established to provide a uniform approach for evaluating Sellers
generation projects, each lnlarconnc(jon must be examined by the Company Indi-
vidually. The Company and the Seller or Sellers engineers will be guided by
this document (which is a pert of the appropriate Power or Energy Sales Agree-
ment) in planning an interconnection between the Company system and the Seller.
The Company may provide limited technical assistance for Sellers, but
will not perform any eninoer2ng, construction or repair work on power pro-
duction equipment.
0-2 GENERAL DESIGN CONSIDERATIONS
All Seller generators lorger than 20 #<VA shell be three-phase genera-
tors connected to three-phase circuits unless otherwise approved by the Company.
Generators 20 KVA and smaller may be either single-phase or three-phase.
Except In certain instances to be determined by tile Company, all
Seller's generators shall be Isolated from the Company's system by a transformer.
ExmBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 35of4l
-2- APPENDIX D
The Seller may be required to limit the fault current contribution to the
Company system by generator impedenOc, neutral grounding or other means.
The Company will not assume any responsibility for protection of the
Seller's generator or of any other portion of the Sellers electrical equipment.
The Seller is fully responsible for protecting his equipment from faults or
disturbances on the Company system.
Sellers are hereby notified that certain conditions on the Company's
system may cause negative seucnee currents to flow in the Seller's generator.
It Is the sole responsibility of the Seller to protect his equipment from ox-
cessive negative sequenco currents reverse power flow, and single phasing.
Sellers are hereby notified that single or three-phase automatic re-
closing devices may be installed on the distribution system. Seller must install
a protective device capable of isolating his generation from the line prior to
reclosure
A check Interlock for synchronizing of the Seller's generator Is
required,
When required for safety Or system reliability, the Company may requIre
that a control circuit be installed at Seller expense.
D-3 METERING REQUIREMENTS
Unless otherwise agree.I by the Parties, metering will be provided for
recording net output of the Facility and will be separate from any metering of
Sifter's load. MOterIfl9 required will be determined by the Company on a case-
by-case basis, but will generally follow the guidelines below
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 36 of 41
APPENDIX 0
(A) Capacity Under 730 KVA
A kilowatt-hour demand meter will be installed.
() Capacity of 750 KVA and Above
Four meters will be installed. These will measure KWi. KW demand, and
reactive pover flow to and from the generator. These meters will have
pulse outputs to a solid state recorder in order to determine poweP factor
and demand.
D4 RELAYING AND PROTECTION
Certain protective devices (relay, circuit b'eaketa, etc) are required
by the Company and must be installed at any location where the Sailer desires to
operate generation in parallel with the Company. The purpose of these devices
is to promptly remove the Seller's 2enerCtIon whenever a system disturbance
occurs so as to protect the 9eneIal public and the Company facilities and per-
sonnel from damage or injury due to the energy produced by the Seller's generator.
All facilities will require automatic over-current relay protection in
addition to that protection rouired by this appendix, section b-5, 0-6, or O-7
as appropriate to the instøllntion. The following stipulations regarding this
protective equipment will apply,
(A) All protective devkes installed to protect the Company system from
Seiler' generation will be approved by the Company
() The check out of these devices must be supervised by the Company and
subject to the Company's approval.
(C) All relay settings on the Interconnection will be approved by the
Company.
EXHIBIT No.!
CASE NO. IPC-E-12-28
COMMENTS, TAMARACK
Page 37 of 41
-4.. APPENDIX I)
(D) The Seller has full responsibility for the maintenance of his genera-
tin and protection equipment. Adequate maintenance records must be main-
tamed by the Seller and be available for review by the Company. The
Company reserves the right to inspect on demand all protective equipment.
Inspection may include tripping of the power circuit breaker by protective
relays, if, in the opinion of the Company, the Seller has failed to provide
proper maintenance and this failure could adversely impact the Company or
other Company customers, the C*pany can require the Seller to cease parallel
operation.
0-'5 SYNCHRONOUS GENERATORS
On synchronous generators, over and under voltage and over and under
frequency relays are required to trip the unit when significant differences
exist between loads and oanoration,
Synchronous generators must be operated with governors. Governor
characteristics may be adjusted to at toast 5L droop, Governors are to be
operated unrestrained to allow automatic reduction of generation in the event of
excessive system frequency.
D-6 INDUCTION GENERATORS
Overvoltage can become a serious problem when an induction generator
is isolated to a portion of a transmission or distribution system. Overvoltage
relays shall be provided that will open the generator breaker in the event that
the voltage reaches predetermined limits consistent with the overvoltage capa-
bUtty of the generator and the system. Underyoltege protection may also be
required. On larger upits, undsrfr*quency and overfrequeny relaying may be
required,
EXHIBIT No.1
CASE NO. IPC-E-12-28
COMMENTS, TAMARACK
Page 38 of 41
-5- APPENDIX 0
(
Vars for excitation of the induction generator will need to be supplied
from the power system or from capacitors as a component of a static Var source.
The Power Sales Agreement provides for compensation to the Company for Vats
supplied.
0-7 Dc TO AC CONVERTERS
Direct current generators may be operated in parallel with the Company
system through a synchronous inverter. The inverter installation will be designed
such that a utility system interruption will result in the immediate removal of
the inverter power flow to the utility,'Harmonics and/or spurious frequencies
,generated by the Sellers generator-Inverter combinations must be limited to
avoid causing any reduction In quality of electric service tuother Sellers or
the Company's other customers.
D-B SWITCHING REQUIREMENTS
(A) The closure of any breaker or other disconnecting device which
connects the Facility to deliver power to Idaho's system s, shall be con-
trolled by equipment installed by the Seller as a part of its lnterconec-
tlon Facilities which will perform the following
(1)automatically monitor the status of the electrical system on
Idaho's side of the disconnecting device as to voltage, frequency and
phase rotation, and;
(2)prohibit closure or reconnection until voltage, frequency and
phase rot5tion have been within approved limits for a Continuous period
of not less Than five () minutes. and;
(3)operate so that if Idaho's system is de-energised within ten (10)
seconds after the initial closure of the Seller's disconnecting de-
vice. Seller's disconnecting dyjø will Immediately open and not
ExmBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 39 of 41
APPENDIX D
close again until Sotlor has contacted thd Designated Dispatch Faci-
lity and received permission to raclose;
Disconnection control systems with characteristics varying from those
described above may be a ceptabic to Idaho provided that in ldand' judg-
ment, they provide sciequate protection consistent with Prudent Utility
Practices,
(B)All automatic and other disconnection control equipment must be
reviewed and approved by Idaho.
(C)The Company reserves the right to open and secure by look any
disconnecting device without prior notice to Seller for any of the following
reasons:
C
(1)System emergency.
(2)IMpaction of the Seller's protective equipment reveals a
hazardous condition or lack of maintenance, -
(3)Seller's generating equipment interferes with ether customers,
other Sellers, or with the Compauys system.
(0) Seller shalt maintain a written record of all operating (opening
and closing) of the Seller's interconnection with the Company. Each oper-
ation will be recorded by the date, hour end minute,, and will include the
generator kilowatt hour reading at the time of the operation. This record
will be maintained on a monthly basis and tI'e original will be mailed to
the Company on the first business day of the following month. The Company
will provide the forms necosisry for filing this monthly switching report.
(E) Consistent with Prudent Utility Practice. Idaho may require the
Seller to Install commttncations circuits which will allow Idaho to remotely
control the closIng of the Seller's disconnecting . equipment or require other
EXHIBIT No. 1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 40 of 41
* 0 •
*
7.. APPENDIX D
arrangements limiting the Seller's ability to close its disconnecting
equipment without first receiving Idaho's consent.
D-9 GENERATION SCHEDULING AND REPORTING
(A) For installations under 750 KVA, the Seller shall read his generator
kilowatt-hour motor within the 24 hour period following 1200 noon on the
last day of each month and he shall, within the period, notify the Desig-
nated Dispatch Facility of that meter reading. That kilowatt-hour meter
reading shall also be recorded on the monthly switching report that Is
mailed to the Company,
(8) For installations of 750 I(VA and above, before 1000 A Meach day, the
Seller shall provide the Designated Dispatch Facility with an estimate of
what the Seller will generate on the following day or days as may be required.
In order to maintain a continuous record of energy actually generated and
delivered, the Seller shall; by a moans acceptable to the Company, obtain
the kilowatt-hour reading at midnight of each clay and shall notify the
Designated Dispteh Facility, the following day, of that meter reading
Additionally, the kilowatt-hour meter reading, corresponding to midnight at
the and of the last day of each month, shall also be recorded on the monthly
switching report that is mailed to the Company.
The written record of the end-of-the-month meter reading on the monthly
switching report will be the basis of payment for energy purchased by the Company
from the Seller.
EXHIBIT No.1
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 41 of41
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-12-28
TAMARACK ENERGY PARTNERSHIP
EXHIBIT NO. 2
ExmBrr No.2
CASE No. IPC-E-12-28
COMMENTS, TAMARACK
Page 1 of!
Strictly Confidential -Attorney Client Privileged
Re-calculation of Updated Rates for Tamarack CSPP
Rates As Paid
70% 20% 10%
Fixed Variable Total Fixed Variable Total Fixed Variable Total Wt Ave Variable
Jan 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0344 0.00863 0.04303 0.02274 22.74
Feb 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0344 0.00863 0.04303 0.02274 22.74
Mar 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.02586 0.00634 0.0322 0.02182 21.82
Apr 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.02586 0.00634 0.0322 0.02182 21.82
May 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.02586 0.00634 0.0322 0.02182 21.82
Jun 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0413 0.01036 0.05166 0.02291 22.91
Jul 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0413 0.01036 0.05166 0.02291 22.91
Aug 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0413 0.01036 0.05166 0.02291 22.91
Sep 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.0413 0.01036 0.05166 0.02222 22.22
Oct 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.0344 0.00863 0.04303 0.02205 22.05
Nov 0 0.02829 0.02829 0.0465 0.00690 0.05340 0.0344 0.00863 0.04303 0.02205 22.05
Dec 0 0.02829 0.02829 0.0698 0.01036 0.08016 0.0344 0.00863 0.04303 0.02274 22.74
Revised Rates at 6/1/2010
70% 22.38% 20% 200 rates 10% 248 Rates
Fixed Variable Total Fixed Variable Total Fixed Variable Total Wt Ave Variable
Jun-10 0 0c03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Jul-10 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Aug-10 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Sep-10 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0413 0.01314 0.05444 0.0273 27.30
Oct-10 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Nov-10 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Dec-10 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Jan-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Feb-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Mar-11 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
Apr-11 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
May-l1 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
Jun-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Jul-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Aug-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Sep-i1 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0413 0.01314 0.05444 0.0273 27.30
Oct-I1 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Nov-11 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Dec-11 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Jan-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Feb-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96
Mar-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
Apr-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
May-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.02586 0.00805 0.03391 0.02679 26.79
Jun-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Jul-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Aug-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0413 0.01314 0.05444 0.02818 28.18
Sep-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0413 0.01314 0.05444 0.0273 27.30
Oct-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Nov-12 0 0.03462 0.03462 0.0465 0.00876 0.05526 0.0344 0.01095 0.04535 0.02708 27.08
Dec-12 0 0.03462 0.03462 0.0698 0.01314 0.08294 0.0344 0.01095 0.04535 0.02796 27.96