LONG TERM AGREEMENT
BETWEEN
SIERRA PACIFIC POWER COMPANY
AND
FAR WEST CAPITAL, INC.
STEAMBOAT II
LONG TERM AGREEMENT
BETWEEN
SIERRA PACIFIC POWER COMPANY
AND
FAR WEST CAPITAL, INC.
STEAMBOAT II
Section Title Page
------- ----- ----
1. Recitals.................................................... 1
2. Definitions................................................. 2
3. Exhibits.................................................... 4
4. Term and Termination........................................ 5
5. Remedies.................................................... 5
6. Sale of Capacity and Energy................................. 6
7. Determination of Commercial Operation Date.................. 9
8. Rate........................................................ 11
9. Project Schedule............................................ 11
10. Metering.................................................... 12
11. Guarantees.................................................. 13
12. Seller's Purchase of Capacity and Energy.................... 13
13. Payment..................................................... 14
14. Maintenance................................................. 15
15. Continuity of Deliveries and Economic Dispatch.............. 15
16. Project Design, Construction, and Operation................. 16
17. Interconnection............................................. 19
18. Conditions.................................................. 21
19. Liability and Indemnification............................... 21
20. Insurance................................................... 22
21. Permits, Licenses, and Authorizations....................... 23
22. Option to Purchase ......................................... 24
23. Right of First Offer........................................ 25
24. Notices..................................................... 26
25. Force Majeure............................................... 27
26. Successors in Interest...................................... 28
27. Assignment.................................................. 28
28. Collateral Assignments...................................... 29
29. Entire Agreement............................................ 29
30. Governing Law............................................... 29
31. PSCN Approval............................................... 29
32. Dispute Resolution.......................................... 30
33. Multiple Originals.......................................... 31
LONG TERM AGREEMENT
FOR THE PURCHASE AND SALE
OF ELECTRICITY
THIS AGREEMENT, for the purchase and sale of electricity, is entered into
as of the date of its execution by and between SIERRA PACIFIC POWER COMPANY, a
Nevada Corporation ("Sierra"), and FAR WEST CAPITAL, INC., a Utah Corporation
("Seller"). Seller and Sierra hereinafter are sometimes referred to individually
as "Party" and collectively as "Parties".
1. Recitals. This Agreement is based upon the following facts:
(a) Sierra is a public utility engaged in the purchase, production,
transmission, distribution, and sale of electric energy.
(b) Sierra issued a Request for Proposals dated November 1989 from any
entities which could provide long term capacity and energy to meet Sierra's
needs through 1997. All proposals received were evaluated on both price and
non-price factors to determine those proposals that were the best value to
Sierra and its customers. The proposal from Seller was selected as one of the
proposals providing the best value supply to fill a portion of Sierra's long
term additional power needs.
(c) The Seller presented a proposal for up to 48,000 kilowatt annual
average geothermal generating capacity to be installed in 12,000 kilowatt
increments to be located on the Steamboat Springs Known Geothermal Resource Area
in Washoe County in Sierra's Nevada service territory. Sierra has elected to
purchase the capacity and energy from one 12,000 kilowatt Average Peak Period
Capacity project under this Agreement.
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(d) Seller desires to sell the electric capacity and energy produced by
Seller's 12,000 kilowatt Average Peak Period Capacity generating facility to
Sierra pursuant to the provisions of a long term agreement.
In consideration of the premises and the mutual covenants and conditions
contained herein, the Parties agree as follows:
2. Definitions. When used with initial capitalizations, whether in the singular
or in the plural, the following terms as used in this Agreement shall have the
following meanings:
(a) "Adjusted Net Metered Output" shall mean Net Metered Output, as
adjusted for system transmission losses, if any, pursuant to Section 8(a).
(b) "Agreement" shall mean this Long-Term Agreement for the Purchase and
Sale of Electricity.
(c) "Commercial Operation Date" shall mean 2400 hours on the date upon
which Seller's Project meets the criteria set forth in Section 7.
(d) "Contract Year" shall mean each one (1) year period commencing on
either the Commercial Operation Date or each anniversary of such date, and
ending on the next anniversary of the Commercial Operation Date.
(e) "Firm Capacity" shall mean power producing capacity of the Project
that shall be available to serve Sierra's Peak Period load during the Term of
this Agreement.
(f) "Firm Energy" shall mean energy of the Project that shall be available
to serve Sierra's load during the Term of this Agreement.
(g) "Interconnection Equipment" shall mean the equipment and facilities
required to effect an electrical interface between Sierra's electrical system
and Seller's Project including, but not limited to, electric lines, protective
equipment, metering and communication equipment.
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(h) "Net Metered Output" shall mean all electric capacity and energy
produced by Seller's Project less Seller's Project Station Use and
transformation and transmission losses, if any, between the meter and the Point
of Delivery.
(i) "Peak Period" shall mean the total on-peak and mid-peak hours in a
billing period as determined in Section 5 of Exhibit D.
(j) "Peak Period Capacity" shall mean the average capacity delivered to
Sierra over the Peak Period for any billing period, excluding any hours during
which Seller reduced deliveries in response to Sierra's exercise of its rights
under Sections 15(a) and 15(b) of this Agreement. Peak Period Capacity will be
calculated as (total KWH of Adjusted Net Metered Output delivered during the
Peak Period) / (number of hours in the Peak Period).
(k) "Point of Delivery" shall mean the point where Seller's electrical
conductors contact Sierra's system as it shall exist whenever the deliveries
are being made.
(l) "Prudent Electrical Practice(s)" shall mean those practices, methods,
and equipment, as changed from time to time, that are commonly used in prudent
electrical engineering and operations to design and operate electric equipment.
(m) "Qualifying Facility" shall mean a cogeneration or small power
production facility which meets the criteria as defined in Title 18, Code of
Federal Regulations, Section 292.201 through 292.207.
(n) "Scheduled Maintenance Periods" shall mean those times during which
Seller's Project is shut down for routine scheduled maintenance.
(o) "Seller's Project" or "Project" shall mean a 12,000 kilowatt Average
Peak Period Capacity geothermal generating facility located within Sierra's
service territory near Reno, Nevada known as Steamboat 2. Such Project shall
consist of all geothermal production and injection ▇▇▇▇▇, geothermal fluid
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collecting and processing facilities, electric generators, turbine(s), cooling
facilities, electrical interconnection facilities, and other associated plant
facilities. Specific make, model, and generator nameplate rating for the
generating units are contained in Exhibit A.
(p) "Station Use" shall mean the capacity and energy used to operate the
Project's auxiliary equipment. Auxiliary equipment includes, but is not limited
to, forced and induced draft fans, well pumps, air coolers, boiler feed pumps,
lubricating oil systems, plant lighting, fuel handling systems, control systems,
and sump pumps and any other facility specific equipment operated by the power
generated by the Project.
3. Exhibits. The following Exhibits A through Q are attached hereto and
incorporated herein by reference. Exhibits C, G, H, I, J and K, upon approval by
the Public Service Commission of Nevada ("PSCN") of any amendments or
supplements to, or replacements of such rules or schedules, shall be modified to
reflect such amendments, supplements, or replacements. Exhibits A, E, F, L, M,
N, O, P and Q may be modified by mutual agreement of the Parties. Exhibit B
shall be modified pursuant to Section 6 of this Agreement. Exhibit D shall be
modified pursuant to Sections 5 and 6 of Exhibit D.
Exhibit A Project Unit Listing
Exhibit B Capacity Table
Exhibit C Schedule CSPP
Exhibit D Payment Schedule
Exhibit E Sample Billing Calculations
Exhibit F Estimated Project Schedule
Exhibit G Rule No. 16, Service Connections, Meters, and Customer's
Facility
Exhibit H Rule No. 17, Meter Tests and Adjustments of Bills for Error
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Exhibit I Rate Schedule FSS, Firm Standby Service
Exhibit J Rule No. 2, Description of Service
Exhibit K Rule No. 15, Cogenerators and Small Power Producers (QFs)
Exhibit L SPPCo. Engineering Standard 2.2GN02
Exhibit M Facility Wiring Diagram and Specifications
Exhibit N Final Interconnection Drawing
Exhibit O Milestones Schedule
Exhibit P Semi-Annual Project Report
Exhibit Q Sample Liquidated Damage Calculations
4. Term and Termination. This Agreement shall be effective from the date of its
execution by both Parties and shall continue thereafter for a term of thirty
(30) years after 2400 hours on the Commercial Operation Date (the "Term");
provided, however, that this Agreement may terminate earlier pursuant to the
provisions of this section or Section 31.
This Agreement may be terminated at any time by written notice from Sierra
to Seller in the event any of the following conditions occur:
(a) Seller fails to satisfy the provisions of Section 9 of this Agreement
regarding the milestones and associated dates as contained in Exhibit O.
(b) Seller's Project does not deliver any capacity and energy to Sierra
during any continuous 180 day period after the Commercial Operation Date of
such Project unless due to Force Majeure, and Seller is not exercising
reasonable efforts to resume operation of the Project.
A notice of termination under this section shall be delivered under the
provisions of Section 24. In the case of termination all rights and liabilities
incurred under this Agreement shall be preserved until satisfied.
5. Remedies. Upon either Party's failure to perform any obligation under this
Agreement, the other Party, except to the extent specifically limited by this
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Agreement, may exercise any rights or remedies it may have in law or in equity
including but not limited to compensation for monetary damages, injunctive
relief and specific performance; provided, however, that neither Party shall be
liable to the other Party for any indirect, consequential, incidental, punitive
or exemplary damages. The definition of consequential damages shall include a
claim for lost profits by the Seller or Sierra.
6. Sale of Capacity and Energy.
(a) Subject to the provisions of this Agreement, Seller shall provide to
Sierra and Sierra shall purchase Firm Capacity and Firm Energy in the following
manner:
(1) Firm Capacity during each billing period in the Term hereof in
amounts not less than the Peak Period Capacity values specified in Exhibit
B, and
(2) Firm Energy which is expected to total approximately 111,400,000
kilowatt hours in any Contract Year subject to the restrictions specified
in Section 15 of this Agreement.
(b) Sierra shall, at the end of the third Contract Year and the end of
each Contract Year thereafter, calculate the three year rolling average of the
Peak Period Capacity for the three immediately preceding Contract Years. Such
three year rolling average shall be the sum of the billing period Peak Period
Capacity values for each of the thirty-six (36) months divided by thirty-six
(36). If such three year rolling average is greater than or equal to 95% of the
Average Peak Period Capacity value specified in Exhibit B, then the capacity
rate to be paid pursuant to Section 8 for the ensuing Contract Year shall be the
amount specified in Exhibit D. If such three year rolling average is less than
95% and greater than or equal to 85% of the Average Peak Period Capacity value
specified in Exhibit B, then the capacity rate to be paid pursuant to Section 8
for the
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ensuing Contract Year shall be reduced one percent (1%) for each one percent
(1%) or portion thereof that such average is below 100% of the Average Peak
Period Capacity value specified in Exhibit B; provided, however, that during the
last fifteen (15) Contract Years of the Term of this Agreement, the reduction in
the capacity rate shall be 1.3% for each one percent (1%) or portion thereof
that the three year rolling average is below 100% of the Average Peak Period
Capacity value specified in Exhibit B. If the three year rolling average is less
than 85% of the Average Peak Period Capacity value specified in Exhibit B, then
Seller shall pay Sierra for liquidated damages the sum of $1,000,000 adjusted as
described below. Liquidated damages shall be a lump sum one time payment in 1992
dollars and shall be subject to adjustment yearly commencing November, 1992 at
the same percentage rate as the preliminary value for The Gross National Product
Deflator ("GNPD") increase as reported in the Joint Economic Committee Report
published by the United States Department of Commerce, Bureau of Economic
Analysis. Such adjusted amount shall be determined by multiplying $1,000,000
times the fraction (rounded to six decimal places) formed by the GNPD for the
previous calendar year published prior to the month for which payment is billed
(numerator) divided by the GNPD for the calendar year ending November 1992
(denominator). In the event GNPD is rebased, GNPD for the calendar year ending
November 1992 shall be recalculated subject to the new rebased value. The amount
of the liquidated damage will be billed by Sierra as soon as reasonably
practicable after the determination of the three year rolling average and shall
be due from Seller within thirty (30) days of such billing.
Upon billing by Sierra for the liquidated damages, Exhibit B shall be
revised to reflect the three year rolling average by replacing each of the
Exhibit B Peak Period Capacity values with the average Peak Period Capacity
value for that billing period in the three year period described above. Said
average Peak Period
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Capacity value shall be calculated by adding the Peak Period Capacity value
for that billing period in each of the previous three years and dividing by 3.
Sierra shall prepare a revised Exhibit B to incorporate such revised Peak Period
Capacity values and such revised values shall be effective the first billing
period after the last billing period included in the three year rolling
average. The capacity rate will revert back to the amount specified in Exhibit D
effective with the revised Exhibit B. At the end of each Contract Year
thereafter, Sierra shall calculate the three year rolling average of the Peak
Period Capacity for the three immediately preceding Contract Years. Such three
year rolling average shall be the sum of the billing period Peak Period Capacity
values for each of the thirty-six (36) months divided by thirty-six (36). If
such three year rolling average is greater than or equal to 95% of the Average
Peak Period Capacity value specified in Exhibit B, then the capacity rate to be
paid pursuant to Section 8 for the ensuing Contract Year shall be at the amount
specified in Exhibit D. If such three year rolling average is less than 95% of
the average Peak Period Capacity value specified in Exhibit B, then the
capacity rate to be paid pursuant to Section 8 for the ensuring Contract Year
shall be reduced one percent (1%) for each one percent (1%) or portion thereof
that such average is below 100% of the Average Peak Period Capacity Value
specified in Exhibit B; provided, however, that during the last fifteen (15)
Contract Years of the Term of this Agreement, the reduction in the capacity rate
shall be 1.3% for each one percent (1%) or portion thereof that the three year
rolling average is below 100% of the Average Peak Period Capacity Value
specified in Exhibit B. Example of such calculations is included in Exhibit Q,
Sample Liquidated Damage Calculation.
(c) The Parties agree that Sierra will be substantially damaged in amounts
that will be difficult or impossible to accurately quantify if the Seller's
Project does not maintain a Peak Period Capacity value at or above 85% of the
Peak
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Period Capacity values specified in Exhibit B. Therefore, as described above,
the Parties have specified a sum which the Parties agree is reasonable as
liquidated damages for such occurrence. It is further understood and agreed
that the payment of the liquidated damages is in lieu of actual damages for such
occurrence. Seller hereby waives any defense as to the validity of any
liquidated damages provision in this Agreement. To the extent that Sierra seeks
a remedy pursuant to this Section 6, it shall not be entitled to any other
remedy pursuant to a claim of breach of contract based solely on this Section 6.
7. Determination of Commercial Operation Date.
(a) Seller shall demonstrate the Project capability during a shakedown
period of sustained operation prior to declaring the Project commercially
operable. The shakedown period of sustained operation shall be thirty (30)
continuous days during which period the plant shall generate for a minimum of
500 hours. The average generation net output level during the 500 hours shall be
at least 67% of the Peak Period Capacity value shown in Exhibit B corresponding
to the billing period the shakedown test is completed, provided that, if the 500
hours span two (2) billing periods, the Peak Period Capacity value shall be the
weighted average of the two billing periods values based upon the proportion of
test hours in each billing period. Sierra shall review recorded data to verify
completion of the shakedown test.
(b) As soon as possible after successful completion of the shakedown test,
Seller shall provide Sierra verbally and subsequently in writing pursuant to
Section 24 a statement by independent qualified professionals that the Project
capability demonstration has been completed and all major equipment associated
with the Project is installed and operational and capable of producing energy
and capacity at the monthly values noted in Exhibit B for the full Term of
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this Agreement under normal operating conditions assuming manufacturer's
recommended maintenance procedures are followed.
(c) (1) Coincident with or subsequent to Sierra's review of the data
described in Section 7(a) above, Seller may begin the test period for
determination of the Commercial Operation Date. Said test period shall
consist of 100 hours of continuous operation, designated by Seller, and
delivery of capacity and energy by the Project to Sierra during the same
100 hours. As soon as possible but not less than seven (7) days after the
completion of the test period of 100 hours, Seller shall notify Sierra
verbally that the test is complete, and specify the beginning and ending
hour of said 100 hour test period. Seller shall submit such notification
in writing to Sierra within seven (7) days of the verbal notification
pursuant to Section 24.
(2) Sierra will determine the average of the 25 maximum on-peak and
mid-peak hours of Adjusted Net Metered Output during the test period (the
"Qualifying Average"), regardless of whether said 25 hours are continuous.
(3) If the Qualifying Average does not equal or exceed 90% of the Peak
Period Capacity value shown in Exhibit B corresponding to the billing
period in which the 100 hour test is completed, the Project shall not be
declared commercially operable for establishment of a Commercial Operation
Date; provided that, if the 100 hour test spans two (2) billing periods,
the Peak Period Capacity value shall be the weighted average of the two
billing period values based upon the proportion of test hours in each
billing period.
(4) If the Qualifying Average equals or exceeds 90% of the Peak Period
Capacity value shown in Exhibit B corresponding to the billing period in
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which the 100 hour test is completed, the Project shall be declared
commercially operable at the end of the one-hundredth hour of the test for
establishment of a Commercial Operation Date; provided that, if the 100
hour test spans two (2) billing periods, the Peak Period Capacity value
shall be the weighted average of the two billing period values based upon
the proportion of test hours in each billing period.
8. Rate.
(a) Net Metered Output quantities shall be reduced to reflect the
additional system transmission losses, if any, that are determined to be
applicable to Seller's Project. The amount of the reduction shall be determined
in the interconnection study to be performed by Sierra for this Project. All
payments under this Section shall be based upon such Adjusted Net Metered Output
quantities.
(b) Sierra shall pay Seller for the Adjusted Net Metered Output of
Seller's Project produced between the effective date of this Agreement and 2400
hours on the Commercial Operation Date pursuant to Exhibit C, Schedule CSPP.
(c) If the Commercial Operation Date of the Project is on or before 2400
hours on November 1, 1992, then Sierra shall pay Seller, during the period
commencing on the Commercial Operation Date and continuing for the Term, for all
Adjusted Net Metered Output purchased from Seller's Project pursuant to the
applicable provisions set forth in Exhibit D adjusted pursuant to Section 6(b).
9. Project Schedule.
(a) Seller shall complete each Project milestone specified in Exhibit O,
Milestones Schedule, on or before 2400 hours on the date specified for each
milestone listed in Exhibit O and shall provide Sierra in writing pursuant to
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Section 24 with acceptable documentation as specified in Exhibit O certifying
such milestone completion within ten (10) days of such completion.
(b) Seller shall provide Sierra with the following data: hot water in
pounds per hour, temperature in degrees Fahrenheit at the turbine inlet valve
necessary to operate the plant at the average peak period capacity values in
Exhibit B. Data shall be provided to Sierra upon execution of this Agreement by
Seller. Sierra shall hold this information confidential to the extent such
information is designated as such by the Seller. Subject to Sierra's review and
acceptance, Seller may change this data no later than concurrent to completion
of Item 3 in Exhibit O. This information will be used as a baseline and
monitoring tool for items 3 and 8 in Exhibit O.
(c) Sierra shall acknowledge receipt of the documentation provided under
Section 9(a) and 9(b) and shall provide Seller with written acceptance or
denial of the milestone completion within ten (10) days of receipt of the
documentation. If any milestone is not completed by 2400 hours on the date
specified, this Agreement may be terminated by Sierra effective 2400 hours on
the specified milestone date. Sierra's decision to terminate the Agreement in
the event Seller fails to meet any of the milestones specified in this section
shall be based on Sierra's reasonable review of the status of the Project at
that time and the Project's ability to meet all other milestone dates. Sierra
shall provide to Seller written notice pursuant to Section 24 of such
termination.
10. Metering. Seller's Adjusted Net Metered Output shall be determined by meters
installed at or compensated to the Point of Delivery and adjusted for
appropriate system transmission losses pursuant to Section 8(a). The metered
quantities shall be the gross Project output less Station Use. All meters will
be sealed, operated, and tested in accordance with Sierra's Electric Rules No.
16 and No. 17, Exhibits G and H, respectively.
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11. Guarantees.
(a) Upon signature of this Agreement by Seller, Seller shall provide to
Sierra an ▇▇▇▇▇▇▇ money deposit of $180,000 based upon a fee of $15.00 per KW
and a capacity of 12,000 KW. The deposit may be in the form of cash, an
irrevocable letter of credit, or another form acceptable to Sierra. Such
deposit, if other than cash, shall list Sierra as beneficiary and provide Sierra
with clear first rights to the deposit in the event of a default as noted below
in Section 11(b).
(b) In the event Seller does not complete a milestone in accordance with
Section 9 of this Agreement, withdraws the Project, cancels the Project for any
reason including Force Majeure, or does not achieve a Commercial Operation Date
pursuant to Section 7 on or before 2400 hours on November 1, 1992, Seller shall
forfeit the $180,000 deposit to Sierra.
(c) Sierra will refund the deposit to Seller when the Project establishes
a Commercial Operation Date in accordance with Section 7.
12. Seller's Purchase of Capacity and Energy.
(a) Subject to Sierra's transmission capacity limitations, Sierra agrees
to provide electric capacity and energy to meet Seller's Station Use at times
when Seller's Project generation output is less than the Project Station Use.
Such service shall be provided pursuant to the applicable rate schedule
contained in Exhibit I, Schedule FSS, which is applicable to the backup/standby
service that is being provided to Seller under this Agreement. Such sale shall
be subject to the provisions of Exhibit J, Rule No. 2, Description of Service.
(b) Seller agrees to limit the starting inrush electric current of its
generators and motors so as not to cause more than a four (4) percent voltage
dip on Sierra's transmission system to which Seller's Project is interconnected.
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13. Payment.
(a) Firm Capacity and Firm Energy sold by Seller to Sierra pursuant to
Section 6 shall be determined by meters installed at or compensated to the Point
of Delivery. Such meters shall be read by Sierra during a billing period as
defined in Exhibit D and such metered amounts shall be used by Sierra to
calculate the payment to Seller pursuant to Section 8. Example of such
calculations is included in Exhibit E, Sample Billing Calculation. Within thirty
(30) days of receipt of such meter readings, Sierra shall deliver payment for
such Firm Capacity and Firm Energy to Seller at the address provided in
Section 24.
(b) Electricity supplied by Sierra to Seller pursuant to Section 12 shall
be paid for by Seller upon receipt of billing from Sierra, pursuant to Exhibit
I. Should Seller fail to pay statement(s) from Sierra in full pursuant to
Exhibit I, Sierra may offset future payments to Seller under this Agreement by
such unpaid amounts.
(c) Any other payments required to be made to Sierra under this Agreement
shall be made by Seller within thirty (30) days of receipt of an invoice from
Sierra requesting said payment. Should Seller fail to pay the amount of such
invoice, Sierra may offset future payments to Seller hereunder by such unpaid
amounts.
(d) After ▇▇▇▇▇▇▇▇ or payments made by Sierra to Seller pursuant to this
Section, Seller may request in writing from Sierra, within 30 days of such
▇▇▇▇▇▇▇▇ or payments, copies of the original data and calculations upon which
payments made by Sierra to Seller, or payments requested by Seller to Sierra are
based, including, without limitation, calculations made under Section 6 and
Schedule D.
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14. Maintenance.
(a) By April 1 of each calendar year, but no later than six (6) months
prior to beginning any proposed scheduled maintenance. Seller shall provide
Sierra with a list of proposed Scheduled Maintenance Periods for the following
24 month period. This list shall be subject to Sierra's review and acceptance.
Review and acceptance of the proposed maintenance schedule shall be completed
promptly but in no event longer than sixty (60) days after receipt by Sierra.
Such acceptance shall not be unreasonably withheld. The Parties shall coordinate
such maintenance in order to minimize the impact on the Parties' systems. Sierra
shall provide Seller with a list of scheduled maintenance periods on equipment
that will impact the delivery of capacity and energy from Seller's Project as
soon as reasonably practicable.
(b) In the event the Project must be shut down for unscheduled
maintenance, Seller shall notify Sierra as soon as practicable of the necessity
of such shutdown, the time when such shutdown has occurred, or will occur, and
the anticipated duration of the shutdown. Seller shall take all reasonable
measures and exercise reasonable efforts to avoid unscheduled maintenance and to
limit the duration of the shutdown.
(c) An operating procedures document prepared by Sierra which details the
operation procedures to be followed by the Project operators and Sierra's
dispatchers shall be executed by the Parties prior to delivery of capacity and
energy from the Project.
15. Continuity of Deliveries and Economic Dispatch.
(a) Subject to Prudent Electrical Practices, Sierra may require Seller to
curtail, interrupt, or reduce deliveries of Adjusted Net Metered Output, in
order for Sierra to construct, install, maintain, repair, replace, remove,
investigate, or inspect any of Sierra's equipment or any part of its system, or
if Sierra
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determines that curtailment, interruption, or reduction is necessary because of
emergencies or operating conditions on its system, other than economic dispatch
which is described in Section 15(b) below. Sierra may require that Seller reduce
its generation on any hour that Sierra would otherwise be required to operate
Sierra's plants below a minimum operational level. In such circumstances, Sierra
shall not be obligated to accept deliveries of, or pay Seller for, Adjusted Net
Metered Output that otherwise would have been delivered during such period of
curtailment, interruption, or reduction. Sierra shall use reasonable efforts to
resume acceptance as soon as is reasonably practicable.
(b) Sierra shall have the right to economically dispatch the Project for a
maximum of 11,140,000 kilowatt hours of Adjusted Net Metered Output each
Contract Year. Such economic dispatch capability shall be exercised by verbal
notice to Seller from Sierra by 1000 hours on the day preceding the day on which
the Project will be economically dispatched. Such notice shall include the hours
and the reduced energy price for such hours. Seller shall have the option of
accepting the reduced energy payment as specified by Sierra at the time of such
notice for continued deliveries of capacity and energy, or discontinuing
delivery of capacity and energy for the period described in Sierra's notice.
Seller shall notify Sierra verbally by 1100 hours of the option Seller has
selected.
For any month in which Sierra exercises its economic dispatch rights for
energy under this subsection, Sierra shall provide Seller an accounting of the
reduced energy price contained in the verbal notice by Sierra to Seller. Such
accounting shall be included in the following month's payment to Seller as
provided in Section 13.
16. Project Design, Construction and Operation.
(a) Seller shall, at Seller's expense, design, construct, install,
operate, and maintain Seller's Project. Seller accepts that it is designing a
Project to be
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integrated into a utility delivery system, and that it is designing a Project
and Interconnection Equipment to be compatible with the operational standards of
reliability and availability of Sierra's system. Specific Project requirements
as noted in the interconnection study to be conducted by Sierra shall be
incorporated into the design of the Project. Seller shall provide Sierra with
those specifications, drawings, and electrical data concerning the Project
necessary to allow Sierra to make stability and protection studies. All
specifications and changes in specifications, including new or additional
equipment, shall be subject to Sierra's review and acceptance. Such review and
acceptance shall be completed promptly but in no event longer than sixty (60)
days after receipt by Sierra and shall be for the sole purpose of insuring that
Seller's Project is compatible with Sierra's system. Such acceptance shall not
be unreasonably withheld. Sierra's acceptance of Seller's specifications,
drawings, and electrical data shall not be construed as confirming nor endorsing
the design, nor as a warranty of safety, durability, or reliability of the
Project. Sierra shall not, by reason of any review, acceptance, or failure to
review, be responsible for the Project, including but not limited to the
strength, details of design, adequacy or capacity thereof, nor shall Sierra's
acceptance be deemed to be an endorsement of the Project.
(b) The design and construction of the Project shall be Seller's
responsibility, and Seller shall ensure that the requirements of all applicable
federal, state, and local laws, and all regulations promulgated by such laws are
met. Prior to commencement of generation, and upon completion of any major
changes, Seller at Seller's expense, shall arrange for the Project to be
inspected and approved by appropriate federal, state, and local officials to the
extent required by applicable law.
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(c) Once Seller's and Sierra's electrical facilities are connected, both
Parties will operate their respective facilities in accordance with Exhibit K,
Rule No. 15, Exhibit L, Sierra's Specification 2.2 GN02, and revisions and
replacements thereto, Exhibit M, the Facility Wiring Diagram and Specifications
and Exhibit N, Final Interconnect Drawing agreed upon by the Parties to this
Agreement. The Parties acknowledge that with operating experience adjustment of
the operating requirements may be necessary.
(d) Sierra's obligation to interconnect Seller's Project is contingent
upon the approval of plans and specifications described in Section 17 below.
Such approval shall not be unreasonably withheld.
(e) Seller shall be responsible for the operation, maintenance, and
refurbishment of the Project to insure continued delivery of Firm Energy and
Firm Capacity pursuant to Section 6(a). Refurbishment shall include, but not be
limited to the drilling of additional ▇▇▇▇▇ and the installation of replacement
or additional generating equipment. Sierra shall have the right to review any
proposed refurbishments, modifications or installations made by Seller and
witness all such refurbishments, modifications or installations and any formal
well tests on production, injection, and slim hole ▇▇▇▇▇ performed by Seller.
Sierra shall hold this information confidential to the extent such information
is designated as such by the Seller. Seller shall provide Sierra with thirty
(30) days prior notice of its intent to perform any refurbishments,
modifications, installations, or formal well tests or in the event of unplanned
maintenance such notice shall be given as soon as reasonably practicable.
(f) Seller warrants that the Project will be operated in a manner which
will not reduce or interfere in any way with the extent or availability of
geothermal fluid to operate the projects that are the subject of the Long Term
Page 18 1/11/91
Agreements dated November 18, 1983 and October 29, 1988, and subsequent
amendments, between Far West Capital, Inc. and Sierra.
Should Seller elect to construct an additional geothermal facility or
facilities utilizing the same resource used by the Project, Seller warrants that
the additional facility or facilities will be operated in a manner which will
not reduce or interfere in any way with the extent or availability of geothermal
fluid to operate the Project in accordance with this Agreement.
(g) Seller shall make available to Sierra during the construction period
of the Project all pertinent information in connection with Seller's hot water
supply in the Steamboat Springs area, including but not limited to, drilling
data, test and well performance information and any reports pertaining to the
reservoir. Sierra and Seller shall conduct meetings as necessary to review this
data. Sierra shall hold this information confidential to the extent such
information is designated as such by the Seller.
(h) Commencing with the Commercial Operation Date, Seller shall provide to
Sierra on January 1 and July 1 of each year for the Term of this Agreement, a
Semi-annual Project Report which shall include, but not be limited to, the
information described in Exhibit P. In February of each year for the Term of the
Agreement, Seller and Sierra shall meet to conduct an annual review of plant and
resource performance. Additional data and meetings shall be required as
necessitated by project performance. Sierra shall hold all such information
confidential to the extent such information is designated as such by the Seller.
17. Interconnection.
(a) Seller shall install all Seller's Interconnection Equipment. Seller's
Interconnection Equipment shall be of utility grade and of a rating sufficient
to
Page 19 1/11/91
accommodate the delivery of the generation under this Agreement. Seller shall
allow Sierra to review the adequacy of all protective devices and to establish
requirements for settings and periodic testing; provided, however, that neither
such action or inaction by Sierra shall be construed as warranting the safety or
adequacy of Seller's Interconnection Equipment. Seller shall not make any
modification to Seller's Interconnection Equipment which substantially affects
the delivery of electricity without advance written notification to Sierra and
ultimate acceptance of each change by Sierra. Such review shall be done promptly
but in any event no longer than sixty (60) days from Sierra's receipt of all
information necessary for such review. Such acceptance shall not be unreasonably
withheld. All such equipment installed hereunder shall conform with the National
Electrical Code. Seller shall reimburse Sierra for Sierra's costs associated
with initial and periodic testing of Seller's Interconnection Equipment.
(b) Connection of Seller's Interconnection Equipment to Sierra's system
shall be by or under the direction of Sierra at Seller's expense. Sierra shall
schedule and complete the final interconnection and testing of the
interconnection facilities pursuant to a Special Facilities Agreement.
(c) In the event that it is necessary for Sierra to install any facilities
and equipment on Sierra's system or to reinforce Sierra's system to accommodate
Seller's deliveries, Seller shall reimburse Sierra for all of Sierra's costs
associated therewith, in accordance with the provisions of a Special Facilities
Agreement. Not less often than annually, Seller shall also reimburse Sierra
pursuant to Section 13 above, for all of Sierra's operation and maintenance
costs as determined by Sierra, resulting from Sierra's installation of
facilities and equipment under a Special Facilities Agreement. In addition,
Seller shall pay for the cost of the replacement of any such facilities during
the
Page 20 1/11/91
Term of this Agreement. Sierra shall use reasonable efforts to minimize such
costs.
18. Conditions. The obligation of Sierra to accept delivery of or purchase
capacity and energy under this Agreement is conditioned upon receipt of copies
of the following documents by Sierra prior to the initial delivery of Adjusted
Net Metered Output.
(a) Evidence of the qualification of Seller's Project as a cogeneration or
small power production facility pursuant to PURPA and the regulations
promulgated pursuant to said Act; and
(b) Evidence of application for and receipt by Seller of any permits or
other approvals required by Chapter 704 of the Nevada Revised Statutes; and
(c) A statement by independent qualified professionals sufficient to
establish that Seller's Project has geothermal resource supply capable of
producing energy and capacity at the monthly values noted in Exhibit B for the
full Term of this Agreement and a statement by independent qualified
professionals sufficient to establish that Seller's Project has generation
equipment capable of producing energy and capacity at the monthly values noted
in Exhibit B for the fall Term of this Agreement under normal operating
conditions assuming manufacturers recommended maintenance procedures are
followed; and
(d) Plans and specifications for Seller's Project and Interconnection
Equipment which are acceptable to Sierra, as set forth in Sections 16 and 17
above; and
(e) Evidence that Seller has made all filings necessary to qualify to do
business in the State of Nevada.
19. Liability and Indemnification. Each Party shall indemnify and hold harmless
the other Party against and from any and all loss and liability for
Page 21 1/11/91
personal injury, bodily injury or property damage claimed by any person or party
and resulting from or arising out of (1) the engineering, design, construction,
maintenance, or operation of the indemnitor's facilities, (2) the making of
replacements, additions, or betterments to, the indemnitor's facilities, or (3)
the manner in which Seller uses the Project's geothermal resource supply or the
facilities which interconnect Seller's Project with Sierra's electrical system.
Neither Party shall be indemnified for liability or loss to the extent such
liability or loss results from, or is contributed to by, that Party's negligence
or willful misconduct. The indemnitor shall, on the other Party's request,
defend any suit asserting a claim covered by this indemnity, and shall pay all
costs, including reasonable attorney fees, that may be incurred by the other
Party in enforcing this indemnify.
20. Insurance.
(a) Prior to commencement of construction of the Project, Seller and/or
its contractor(s) shall maintain worker's compensation or self-insurance which
satisfies the applicable requirements of Nevada law. Seller shall provide Sierra
with a certificate(s) evidencing such insurance prior to commencement of
construction of the Project.
(b) Prior to connection of the Project to Sierra's system, Seller shall
secure and continuously carry for the Term hereof, with an insurance company
or companies acceptable to Sierra, insurance policies for bodily injury and
property damage liability. Such acceptance shall not be unreasonably withheld.
Such insurance shall include: provisions or endorsements naming Sierra as
additional insured as its interest may appear; provisions that such insurance is
primary insurance with respect to the interest of Sierra and that any insurance
maintained by Sierra is excess and not contributory insurance with the insurance
required hereunder; cross-liability or severability of
Page 22 1/11/91
insurance interest clause; and provisions that such policies shall not be
cancelled or their limits of liability reduced without thirty (30) days prior
written notice to Sierra. Initial limits of liability for all requirements under
this section shall be not less than $2,000,000 for each occurrence.
(c) Seller shall provide Sierra with a copy of each insurance policy
required under this section, certified as a true copy by an authorized
representative of the issuing insurance company or, at the discretion of Sierra,
in lieu thereof, a certificate in a form satisfactory to Sierra certifying to
the issuance of such insurance. Seller shall submit such documents at the
address listed in Section 24 prior to connection of the Project to Sierra's
system and at all other times as such insurance policies are renewed or changed.
(d) If Seller has not obtained such insurance or maintained the status of
such insurance, Seller shall not deliver capacity and energy to Sierra, and
Sierra shall have no obligation to accept any tenders of delivery until
appropriate insurance is obtained or reinstated. Sierra's obligation to purchase
shall be reinstated only upon receipt of certificates of insurance showing that
such insurance has, in fact, been obtained or reinstated.
21. Permits, Licenses, and Authorizations. It shall be Seller's responsibility
to obtain any and all state, federal, and local permits, licenses, or other
documents necessary for the construction and operation of Seller's Project and
the sale of energy and capacity therefrom to Sierra. If Seller has not obtained
such documents as are material and necessary for the operation of the Project or
maintained the status and approvals they represent, Seller shall not deliver
capacity and energy to Sierra and Sierra shall have no obligation to accept any
tenders of delivery until the appropriate documents are obtained or reinstated.
Sierra's obligation to purchase shall be reinstated only upon receipt of proof
that such documents have, in fact, been obtained or reinstated.
Page 23 1/11/91
22. Option to Purchase.
Seller has leases or optioned property within the Steamboat Springs Known
Geothermal Resource Area which Seller believes have geothermal resources capable
of supporting at least 24 MW of power generation in excess of the 12 MW covered
by this Agreement and for the sum of $10.00, receipt of which is hereby
acknowledged by Seller, Seller hereby grants an option to Sierra to purchase the
presently unsold 24 MW capacity or any 12 MW increment thereof. This option is
subject to the following conditions:
a. If any portion of the capacity subject to this option is the subject of
a purchase agreement, letter of intent, or otherwise has been committed for sale
to another purchaser prior to Sierra's exercise of its option, then this option
will have lapsed and will be null and void with respect to such capacity amount.
Seller shall provide notice to Sierra in the event of each such commitment
within 30 days of each such commitment. Such notice shall include a statement of
the remaining capacity qualifying under this section.
b. The option must be exercised by giving notice in writing to Seller on
or before May 1, 1994. Such notice ("Option Notice") shall be issued at least 19
months prior to the expected Commercial Operation Date of that project.
c. The price to be paid for electricity sold to Sierra pursuant to this
option and the pricing escalation shall be the same as the price provided for
electricity sold under this Agreement; provided, that for every 12 month period
or portion thereof which expires prior to the exercise of this option after June
1, 1991, an escalation of 5.00% per year prorated for any portion thereof shall
be applied to the energy rate and the GNPD price deflator prorated for any
portion thereof for the previous year shall be applied to the capacity rate.
d. Seller shall notify Sierra as soon as reasonably practicable in the
event sufficient geothermal resource is not available for Seller to supply the
Page 24 1/11/91
capacity subject to this option. Such notice shall include a statement of the
remaining capacity which can be supplied by the geothermal resource.
If, upon Sierra's Option Notice, Seller determines that the economics of a
project required to supply the capacity in the option is no longer feasible,
Seller shall supply Sierra with a notice to that effect within thirty (30) days
of the date of Sierra's Option Notice.
e. The Parties shall execute a long term power purchase agreement for the
capacity and associated energy upon which the option is exercised, which
agreement shall include the same terms and conditions as included in this
Agreement. Such execution shall occur within sixty (60) days of the date Sierra
exercises its option in writing.
23. Right of First Offer.
(a) On and after June 1, 1992, Sierra shall have an exclusive right of
first offer to purchase any Transfer Interest (as hereinafter defined) on the
terms and conditions set forth herein. If Seller or any of its subsidiaries,
affiliates or other related entities ever desire to dispose of its or their
rights, title, or interest in the Project other than by a sale and leaseback of
Project or any part thereof (hereinafter referred to as a "Transfer Interest")
for financing, or if Seller receives a bona fide offer for purchase, lease or
other disposition of the Project, or any part of Seller's interest therein
(hereinafter also referred to as a "Transfer Interest"), which offer Seller is
prepared to accept, it shall give notice thereof in writing to Sierra (the
"Notice"). The Notice shall specify the terms under which Seller is prepared to
dispose of the Transfer Interest, including the purchase price of the Transfer
Interest, or include a copy of the acceptable offer received by Seller, as the
case may be. Sierra may request any information concerning the Project that it
considers necessary in evaluating its intent to accept such a first offer to
purchase.
Page 25 1/11/91
(b) For a period of sixty (60) days after receipt by Sierra of the Notice,
Sierra shall have the right to exercise its right of first offer with respect to
the Transfer Interest by giving written notice thereof to Seller. In the event
that Seller and Sierra are unable to arrive at an agreeable price for the
Transfer Interest, Sierra shall submit its best offer for said Transfer Interest
to Seller and thereafter, Seller shall not sell said Transfer Interest for
substantially different terms or at a lower price than those offered by Sierra
without providing Sierra with notice in accordance with Section 23(a).
(c) In the event Sierra elects not to exercise its right of first offer
pursuant to the foregoing provisions and a sale or lease of the Transfer
Interest is not fully consummated, in accordance with the terms and conditions
set forth in the Notice, within one year from the date Sierra receives the
Notice, Seller agrees that Sierra's right of first offer to purchase or lease
the Project, or any part thereof, shall be reinstated in accordance with the
provisions of Section 23(a). Any sale of any Transfer Interest shall not
extinguish Sierra's right of first offer with respect to any portion of the
Project or the Seller's interest in the Project as the case may be, not
transferred pursuant to such sale or lease. Sierra's right of first offer shall
continue to apply to any future sale of any Transfer Interest. Any lease of any
Transfer Interest shall not extinguish Sierra's right of first refusal with
respect to any extensions of such lease or with respect to any other leases,
sales or other dispositions of any Transfer Interest.
24. Notices. Whenever in this Agreement it shall be required, permitted, or
desired that notice or demand be given by either Party to or on the other, such
notice or demand shall be in writing and may be either personally served or sent
by United States mail and shall be deemed to have been given when personally
served, when deposited in the United States mail, certified or registered, with
postage prepaid and properly addressed or when transmitted by facsimile;
Page 26 1/11/91
provided, however, notices delivered by facsimile shall only be effective if
delivered on a day that is considered a regular business day by both Parties.
For the purpose hereof, the address of the Parties hereto, until notice of a
change thereof is given as provided in this paragraph, shall be as follows:
SIERRA:
Sierra Pacific Power Company
Power and Fuel Contracts Manager
▇▇▇▇ ▇▇▇▇ ▇▇▇▇, ▇▇▇▇, ▇▇ ▇▇▇▇▇
▇.▇. ▇▇▇ ▇▇▇▇▇
▇▇▇▇, ▇▇ ▇▇▇▇▇
Phone: (▇▇▇) ▇▇▇-▇▇▇▇
Telecopy: (▇▇▇)▇▇▇-▇▇▇▇
SELLER:
Far West Capital, Inc.
▇▇▇ ▇▇▇▇▇▇▇▇▇ ▇▇▇▇ ▇▇▇▇▇
▇▇▇▇▇ ▇
▇▇▇▇ ▇▇▇▇ ▇▇▇▇, ▇▇ ▇▇▇▇▇
Telephone: (▇▇▇) ▇▇▇-▇▇▇▇
Telecopy:(▇▇▇) ▇▇▇-▇▇▇▇
25. Force Majeure.
(a) The term Force Majeure as used herein means acts of God, labor
disputes, and sudden actions of the elements. Unless caused by an independent
identifiable event of Force Majeure, the non-availability of geothermal resource
supply to generate capacity and energy from the Project shall not be considered
an event of Force Majeure.
(b) If either Party, because of Force Majeure, is rendered wholly or
partly unable to perform its obligations under this Agreement, that Party shall
Page 27 1/11/91
be excused from whatever performance is affected by the Force Majeure to the
extent so affected, provided that:
(1) The Party claiming Force Majeure promptly gives the other Party
oral notice, followed by written confirmation describing the particulars
of the occurrence.
(2) The suspension of performance is of no greater scope and of no
longer duration than is required by the Force Majeure.
(3) The nonperforming Party uses its best efforts to remedy its
inability to perform. This subsection shall not require settlement of any
strike, walkout, lockout, or other labor dispute on terms which in the
sole judgment of the Party involved in the dispute, are contrary to its
interest. It is understood and agreed that settlement of strikes,
walkouts, lockouts, or other disputes shall be at the sole discretion of
the Party having the difficulty.
(4) When the nonperforming Party is able to resume performance of
its obligation under this Agreement, that Party shall give the other Party
written notice to that effect.
26. Successors in Interest. This Agreement shall be binding on both Parties, and
on their heirs, successors in interest, and permitted assigns except as
provided in Section 28 below.
27. Assignment. Subject to Section 28 below, neither Party shall voluntarily
assign this Agreement without the prior written consent of the other Party.
Such consent shall not be unreasonably delayed or withheld. Any assignment made
without such consent shall be void.
28. Collateral Assignments. Either Party shall have the right, without the other
Party's consent, but with a thirty (30) day prior written notice to the other
Party, to make a collateral assignment of its rights under this Agreement to
satisfy the
Page 28 1/11/91
requirements of any development, construction, or other long-term financing or
refinancing.
A collateral assignment as described above shall not constitute a
delegation of Seller's obligations under this Agreement, and this Agreement
shall not bind the collateral assignee. Any collateral assignee succeeding to
any portion of the ownership interest of Seller in the Project shall be
considered Seller's successor in interest and shall thereafter be bound by this
Agreement.
Such assignment shall not increase Sierra's obligations nor decrease
Sierra's rights hereunder.
29. Entire Agreement. This document constitutes the entire agreement of the
Parties and supersedes all previous agreements whether written or oral. This
Agreement may be amended only by an instrument in writing signed by both Parties
hereto.
30. Governing Law. This Agreement shall be interpreted, governed by and
construed according to the laws of the State of Nevada, as if executed and to be
performed wholly within the State of Nevada. Any litigation by the Parties as to
this Agreement shall be in a court of competent jurisdiction in the State of
Nevada.
31. PSCN Approval
(a) Sierra's obligation to purchase and Seller's obligation to supply
capacity and energy pursuant to this Agreement are expressly conditional upon
approval of this Agreement by the PSCN. Sierra shall, prior to January 31, 1991,
file this Agreement for approval with the PSCN as part of an amended resource
plan. Sierra and Seller shall use best efforts in obtaining approval by the
PSCN. PSCN approval shall not be considered to have occurred for purposes of
this Agreement unless 1) such approval is issued on or before May 15, 1991, 2)
the approved amended resource plan includes purchases of Firm Capacity and
Page 29 1/11/91
Firm Energy pursuant to this Agreement, 3) the PSCN approves this Agreement in
its totality and without change, and 4) the PSCN issues a specific finding and
order that Sierra acted in a reasonable and prudent manner in executing this
Agreement.
(b) If such PSCN approval does not occur, Sierra shall have the right to
terminate this Agreement by providing Seller written notice of Sierra's intent
to terminate this Agreement prior to May 30, 1991. Such notice shall be given
pursuant to Section 24.
(c) If Sierra does not provide Seller written notice as described in
subsection (b) above of Sierra's intent to terminate this Agreement, this
Agreement shall be deemed to be in full force and effect.
32. Dispute Resolution. In the event that a dispute should arise between Sierra
and Seller concerning the terms and enforcement of this Agreement, the Parties
agree to resolve their dispute by means of binding arbitration conducted in
Reno, Nevada, under the commercial arbitration rules and procedures of the
American Arbitration Association. The Parties shall first endeavor to select a
single arbitrator who, by reason of his/her education and experience, is
mutually acceptable to both Parties. If the Parties are unable to agree upon a
single arbitrator, they shall each choose one (1) arbitrator, and the two
arbitrators thus selected shall choose a third arbitrator to form a three-member
panel to hear and resolve the dispute. In preparing their cases for presentation
to the arbitrator(s), the Parties shall have the same rights of discovery
afforded to litigants under the Nevada Rules of Civil Procedure and the local
rules of the Second Judicial District Court of Washoe County, Nevada.
33. Multiple Originals. Two (2) copies of this Agreement have been executed by
the Parties. Each executed copy shall be deemed an original.
Page 30 1/11/91
to litigants under the Nevada Rules of Civil Procedure and the local rules of
the Second Judicial District Court of Washoe County, Nevada.
33. Multiple Originals. Two (2) copies of this Agreement have been executed by
the Parties. Each executed copy shall be deemed an original.
IN WITNESS WHEREOF the Parties hereto have executed this Agreement on
this 24TH day JANUARY, 1991.
Sierra: Seller:
SIERRA PACIFIC POWER COMPANY FAR WEST CAPITAL, INC.
By: /s/ ▇▇▇▇▇▇ ▇▇▇▇▇▇▇ By: /s/ ▇▇▇▇ ▇. ▇▇▇▇▇▇▇▇
--------------------------- ---------------------------
TITLE: Vice President TITLE: President
Electric Operations
Date: 1/24/1991 Date: 1/24/1991
[STAMP]
Page 31 1/11/91
EXHIBIT A
PROJECT UNIT LISTING
TO BE ATTACHED BY SEPTEMBER 1, 1991
SPECIFICATION FOR TURBINE GENERATORS
EXHIBIT B
CAPACITY TABLE
FAR WEST'S PROJECT
BILLING PERIOD PEAK PERIOD CAPACITY VALUE KW
-------------- -----------------------------
JANUARY ........................................ 13,400
FEBRUARY ....................................... 13,350
MARCH .......................................... 13,170
APRIL .......................................... 13,050
MAY ............................................ 12,830
JUNE ........................................... 9,950
JULY ........................................... 9,140
AUGUST ......................................... 9,140
SEPTEMBER ...................................... 10,140
OCTOBER ........................................ 13,110
NOVEMBER ....................................... 13,260
DECEMBER ....................................... 13,460
AVERAGE OF THE PEAK PERIOD
CAPACITY VALUES, KW ............................ 12,000
Exhibit C
PAGE 1 OF 3
SIERRA PACIFIC POWER COMPANY
▇▇▇▇ ▇▇▇▇ ▇▇▇▇, ▇▇▇▇, ▇▇▇▇▇▇ 14th Revised P.S.C.N. Sheet ▇▇. ▇
▇▇▇▇▇▇ ▇▇. ▇▇▇▇▇▇▇▇ ▇▇. ▇ Cancelling 13th Revised P.S.C.N. Sheet No. 2
SCHEDULE NO. CSPP
SHORT-TERM RATES
COGENERATION AND SMALL POWER PRODUCTION
APPLICABILITY
This schedule is applicable only to purchases from Qualifying Facilities
as defined in Utility's Nevada Electric ▇▇▇▇▇▇ ▇▇.▇ Rule No. 15 under a
Short-Term Purchase Agreement with Utility and where no other schedules are
specifically applicable.
RATES
Utility will pay the sum of the following rates for the enrgy and capacity
provided as determined by meter readings:
(1) ENERGY RATE
a. Time-differentiated:
1991
--------------------------------------------------
▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇ ▇▇▇▇▇▇▇ ▇▇▇ Quarter
01/01-03/31 04/01-06/30 07/01-09/30 10/01-12/31
----------- ----------- ----------- -----------
Winter
All On-Peak kWh, per kWh $0.02402 $0.01882 N/A $0.02193
Plus all Mid-Peak kWh, per kWh $0.02378 $0.01876 N/A $0.02190
Plus all Off-Peak, kWh, per kWh $0.02022 $0.01677 N/A $0.01822
Summer
All On-Peak kWh, per kWh N/A $0.01895 $0.01944 N/A
Plus all Off-Peak, kWh, per kWh N/A $0.01669 $0.01784 N/A
b. Non-time differentiated: (See Special Condition 3)
All kWh, per kWh $0.02249 $0.01796 $0.01864 $0.02052
(Continued)
Issued: 1/1/91
Issued By:
Effective: 1/1/91 ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 304-E
EXHIBIT C
PAGE 2 OF 3
SIERRA PACIFIC POWER COMPANY
▇▇▇▇ ▇▇▇▇ ▇▇▇▇, ▇▇▇▇, ▇▇▇▇▇▇ 14th Revised P.S.C.N. Sheet ▇▇. ▇
▇▇▇▇▇▇ ▇▇. ▇▇▇▇▇▇▇▇ ▇▇. ▇ Cancelling 13th Revised P.S.C.N. Sheet No. 3
SCHEDULE NO. CSPP
SHORT-TERM RATES
COGENERATION AND SMALL POWER PRODUCTION
(Continued)
RATES (Continued)
(2) CAPACITY RATE
a. Time-differentiated:
1991
-------
Winter
All On-Peak kWh, per kWh $.00873
Plus all Mid-Peak kWh, per kWh $.00782
Plus all Off-Peak kWh, per kWh $.00461
Summer
All On-Peak kWh, per kWh $.00722
Plus all Off-Peak, kWh, per kWh $.00468
b. Non-time differentiated: (See Special Condition 3)
All kWh, per kWh $.00652
SPECIAL CONDITIONS
1. The payment period for Utility purchases hereunder shall be the time
interval between two consecutive meter readings that are taken for billing
purposes.
2. The Utility and the Qualifying Facility shall have executed a Short-Term
Purchase Agreement for the purchase and sale of capacity and energy.
3. Qualifying Facilities having rated (nameplate) capacities of 100 kW or less
shall have the option to choose either flat or time-differentiated rates.
Qualifying Facilities have rated (nameplate) capacities in excess of 100 kW will
receive payments based on the time-differentiated rates only.
(Continued)
Issued: 1/ 1/90
Issued By:
Effective: 1/ 1/90 ▇▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 304-E
EXHIBIT C
PAGE 3 OF 3
SIERRA PACIFIC POWER COMPANY
▇▇▇▇ ▇▇▇▇ ▇▇▇▇, ▇▇▇▇, ▇▇▇▇▇▇ Original P.S.C.N. Sheet No.
Tariff No. Electric No. 2 Cancelling P.S.C.N. Sheet No.
SCHEDULE NO. CSPP
SHORT-TERM RATES
COGENERATION AND SMALL POWER PRODUCTION
(Continued)
SPECIAL CONDITIONS, (Continued)
4. Daily time periods will be based on Pacific time and are defined as
follows:
Winter Period On-Peak 5:01 p.m. to 10:00 p.m. daily
Mid-Peak 7:00 a.m. to 5:00 p.m. daily
Off-Peak All other hours
Summer Period On-Peak 10:01 a.m. to 10:00 p.m. daily
Off-Peak All other hours
The winter period will consist of eight months from October through May.
The summer period will consist of four months from June through September.
5. Qualifying Facilities providing energy to Utility hereunder shall be
entitled to receive electric service from Utility on the filed rates schedule(s)
contained in Utility's Nevada Electric ▇▇▇▇▇▇ ▇▇. ▇ applicable to the type and
location of the Qualifying Facility.
6. All purchases made under this schedule are subject to the provision of
Rule No. 15 as contained in Utility's Nevada Electric Tariff No. 1.
Issued: 6/23/86
Issued By:
Effective: 6/23/86 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 249-E
(Revised)
Exhibit D
Payment Schedule
Page 1 of 3
1. This payment schedule is applicable only to purchases of Firm Capacity and
Firm Energy from Seller's Project described in this Agreement.
2.a. Commencing on the Commercial Operation Date and continuing for the Term of
this Agreement, Sierra will pay the sum of the following energy and
capacity rates for the Firm Energy and Firm Capacity delivered as
determined by the Adjusted Net Metered Output:
2.b. Subject to the provisions in Sections 15(b) of the Agreement, the energy
payment shall be the sum of the products of the appropriate energy rate
and the corresponding period kWh Adjusted Net Metered Output.
Energy payment = Sigma Periods (kWh delivered x Energy Rate)
$ PER KILOWATT-HOUR BASE ENERGY RATE
$0.02425 per kilowatt hour
If Seller has accepted a reduced rate for the sale of energy in accordance
with Section 15(b) of the Agreement, then such reduced rate specified in
the verbal notice shall be utilized in the calculation of payment for the
Adjusted Net Metered Output delivered for the time period specified in the
verbal notice.
2.c. The capacity payment shall be as noted below and shall be subject to
adjustment as noted in Section 2 of this Exhibit and Section 6(b) of the
Agreement.
Capacity Payment = Capacity Rate x Capacity Level
Capacity Rate Effective Date
------------- --------------
$19.04/kW Month Commercial Operation Date
$14.00/kW Month Fifteenth (15) Anniversary
of Commercial Operation Date
Exhibit D
Payment Schedule
Page 2 of 3
Capacity Level = the lesser of:
(a) The kWh generated during the Peak Period divided by the Peak Period
hours or,
(b) The monthly on-peak capacity value noted in Exhibit B corresponding
to the billing period.
3. The Peak Period hours will be reduced by the cumulative monthly total of
Peak Period hours associated with Sierra's requirement to curtail Adjusted
Net Metered Output pursuant to Sections 15 (a) and 15 (b) of the
Agreement. It shall be Seller's responsibility to maintain a log of the
monthly and cumulative total of curtailment hours curtailed pursuant to
subsection 15 (a) of the Agreement and notify Sierra monthly of such
amounts.
4. The billing period for Sierra purchases hereunder shall be the time
interval between two consecutive meter readings that are taken for billing
purposes.
5. Daily time periods will be based on Pacific time and are defined as
follows:
Winter Period
On-Peak 5:01 p.m. to 10:00 p.m. daily
Mid-Peak 7:00 a.m. to 5:00 p.m. daily
Off-Peak All other hours
Summer Period
On-Peak 10:01 a.m. to 10:00 p.m. daily
Off-Peak All other hours
The winter period will consist of eight (8) months from October through
May. The summer period will consist of four (4) months from June through
September.
Exhibit D
Payment Schedule
Page 3 of 3
This table is excerpted from Electric Tariffs ▇▇. ▇, ▇▇▇▇ ▇▇▇▇▇ ▇▇. ▇,
▇▇▇▇▇▇▇▇ No. CSPP, and is subject to change in accord with the on-peak,
mid-peak, and off-peak periods as described in Sierra's own rate schedules
for the sale of electricity, as revised from time to time.
6. The energy rate contained herein shall be adjusted on November 1 of each
year starting on November 1, 1993 through and including the fourteenth
anniversary of the Commercial Operation Date of the Project. The
adjustment shall be calculated as follows:
R(n) = (1.0412) R(n-1)
R = the indexed rate
n = the November 1 through October 31 year in which the adjustment
takes place
On the fifteenth anniversary of the Commercial Operation Date of the
Project and continuing for the Term, the adjustment shall be calculated as
follows:
R(n) = (1.03) R(n-1)
R = the indexed rate
n = the November 1 through October 31 year in which the adjustment
takes place
The capacity rates will remain fixed at the level indicated in Section 1
of this Exhibit, unless modified pursuant to Section 2 of this Exhibit.
EXHIBIT E
Page 1 of 3
SAMPLE BILLING CALCULATIONS
This example is for purposes of illustrating billing under the rate schedule
contained in this Agreement only, and does not supplement or amend the terms of
the Agreement to which it is attached.
1. If the Project qualified for payment under Section 8 (c) of this
Agreement, the following payment method is applicable:
Assume : a. On-peak generation is 1,914,250 kWh.
b. Mid-peak generation is 3,828,500 kWh.
c. Off-peak generation is 3,536,325 kWh.
d. Exhibit D energy rate is $.02425/kWh.
e. The energy and capacity was delivered during the First
First Contract Year for the March billing period.
f. The Capacity Rate is $19.04/kW-month.
g. There were 465 mid and on-peak hours
during the billing period.
Calculation of the Energy Payment:
The energy payment will equal the sum of the products of on-peak,
mid-peak, and off-peak generation kilowatt hour values and the energy
rate.
On-peak = 1,914,250 kWh x .$02425 = $46,420.56
Mid-peak = 3,828,500 kWh x $.02425 = $92,841.13
Off-peak = 3,536,325 kWh x $.02425 = $85,755.88
-----------
Energy Payment $225,017.57
Calculation of Capacity Payment:
The capacity payment will equal the lesser of 1 a) the product of the
Capacity Rate and the kWh generated during the Peak Period hours, divided
by the number of Peak Period hours or b) the product of the
EXHIBIT E
Page 2 of 3
Capacity Rate and Peak Period Capacity Value of 13,170 kW for the March Billing
Period.
1) $19.04 kW x 5,742,750 kWh/465 = $235,144.00
2) $19.04/kW x 13,170 kW = $250,756.80
Capacity Payment $235,144.00
Calculation of Total Payment:
Total Payment will equal the sum of the capacity payment and energy
payment.
Total Payment = $231,976.88 + $235,144.00 = $467,120.88
2. If the Project qualified for payment under Section 8 (b) of this
Agreement, the following payment method is applicable:
Assume: a. On-peak generation is 458,333 kWh.
b. Mid-peak generation is 825,000 kWh.
c. Off-peak generation is 550,000 kWh.
d. On-Peak Exhibit C capacity rate is
$.00873/kWh and energy rate is $.02402/kWh.
e. Mid-peak Exhibit C capacity rate is
$.00782/kWh and energy rate is $.02378/kWh.
f. Off-peak Exhibit C capacity rate is
$.00461/kWh and energy rate is $.02022/kWh.
EXHIBIT E
Page 3 of 3
Calculation of Capacity Payment:
The capacity payment will equal the sum of the products on-peak,
mid-peak, and off-peak generation kilowatt hour values and their
respective rates.
On-peak = 458,333 kWh x $.00873 = $4,001.25
Mid-peak = 825,000 kWh x $.00782 = $6,451.50
Off-peak = 550,000 kWh x $.00461 = $2,535.50
Capacity Payment $12,988.25
Calculation of Energy Payment:
The energy payment will equal the sum of the products of on-peak,
mid-peak, and off-peak generation kilowatt hour values and their
respective rates.
On-peak = 458,333 kWh x $.02402 = $11,009.16
Mid-peak = 825,000 kWh x $.02378 = $19,618.50
Off-peak = 550,000 kWh x $.02022 = $11,121.00
----------
Energy Payment $41,748.66
Calculation of Total Payment:
Total Payment will equal the sum of the capacity payment and energy
payment.
Total Payment = $12,988.25 + 41,748.66 = $54,736.91
EXHIBIT F
ESTIMATED PROJECT SCHEDULE
TO BE ATTACHED BY APRIL 1, 1991
First Revised Sheet P.S.C.N. No. 49
Cancelling Original Sheet P.S.C.N. No. 49
EXHIBIT G
PAGE 1 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
A. Service Installation
1. Overhead Service Connections
Upon a bona fide application for service, and where the Utility's
distribution pole line is located on the consumer's premises, or on a
street, highway, lane, alley, road or private easement immediately
contiguous thereto, the Utility will, at its own expense, furnish and
install a single span of service wires from its pole to the Customer's
first approved permanent support, provided such support is of a type,
and is so located that such service wires may be installed in
accordance with good engineering practice, and in compliance with all
applicable Commission and other laws, ordinances, rules, including
those governing clearances and points of attachment.
Where the Utility's distribution pole line is not complete to the
point noted above, the overhead system may be extended in accordance
with Rule No. 9, Electric Line Extensions.
2. Underground Service Connections
(a) General
In areas where the Utility establishes and maintains an
underground distribution system, service connections within said
underground areas will be made underground only, except upon
written permission of the Utility.
Where the Utility's underground distribution system is not
complete to the point designated by the Utility where the service
connection is to be made to such system, the system may be
extended in accordance with Rule No. 9, Electric Line Extensions.
(b) Underground Service from Underground Systems
(1) New Underground Service Installations
Upon a bona fide application for service, to an
Applicant's premises located adjacent to the Utility's
underground system, an underground service connection will be
provided by the Utility in accordance with the following
provisions:
(A) the Applicant shall
1. provide and maintain, at his expense, any required
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
EXHIBIT G
PAGE 2 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(b) Underground Service from Underground Systems (Continued)
(1) New Underground Service Installations (Continued)
(A) the Applicant shall (Continued)
transformer vault, pull box, or other duct
termination facilities,
2. perform the necessary trenching, backfill, and paving
for the service lateral,
3. furnish and install any select backfill materials
required,
4. furnish, install, and maintain, at his expense, any
specified conduit or duct from the transformer vault,
pull box, or other duct termination facilities to the
service connection point,
5. permit the Utility to use the trench and any conduit
or duct system on his premises for the purpose of
housing the Utility's service conductors or cables,
6. pay to the Utility the cost of any conductors or
cables required between the service connection point
and the duct termination facilities in addition to
that provided by the Utility in Section A.2.(b).(1).
(B).6. hereof, and
7. provide and maintain, at his expense, any necessary
outdoor termination enclosures.
(B) the Utility shall
1. specify the number, size and location of the
transformer vaults, pull boxes, or other duct
termination facilities,
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
EXHIBIT G
PAGE 3 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(b) Underground Service from Underground Systems (Continued)
(1) New Underground Service Installations (Continued)
(B) the Utility shall (Continued)
2. designate the location of the service connection point
at or near the property line of Applicant,
3. specify the number, size, type and manner of
installation of conduit or duct systems on Applicant's
premises,
4. specify the size of the conductors or cables to be
installed,
5. install the conductors or cables from the service
connection point to the duct termination facilities,
and
6. furnish and maintain, at its expense, all conductors
or cables required for installation between the
service connection point and the duct termination
facilities for a distance of one hundred (100) feet or
less.
(C) the conductors or cables shall be terminated as follows:
1. Secondary service (480 volts or less). The conductors
or cables shall terminate in the service terminating
pull section of the Applicant's switchgear or in a
pull box or other terminating facilities furnished and
installed by the Applicant.
2. Primary service (2,400 volts or more). The conductors
or cables shall terminate in the service terminating
pull section of the Applicant's switchgear or in a
room, vault or other suitable enclosure.
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
EXHIBIT G
PAGE 4 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(b) Underground Service from Underground Systems (Continued)
(2) Underground Service Installations Replacing Existing Overhead
Services
In those instances and in those areas where an existing
overhead distribution system is replaced by an underground
distribution system, underground service connections will be
supplied in the same manner and subject to the same conditions
as for new installations under Section A.2.(b).(1). above.
(c) Underground Services from Overhead Systems
(1) New Underground Service Installations
Upon a bona fide application for underground service from
an overhead system to an Applicant's premises, an underground
service connection will be provided by the Utility in
accordance with the following provisions:
(A) the Applicant shall
1. provide and maintain, at his expense, any required
transformer vault, pull box, or other duct termination
facilities,
2. perform the necessary trenching, backfill, and paving
on his property and on the Utility easement or
right-of-way to the pole,
3. furnish and install any select backfill materials
required,
(Continued)
ISSUED: April 17, 1970 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: June 5, 1970 President
Cancelling Original Sheet P.S.C.N. No. 53
EXHIBIT G
PAGE 5 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(c) Underground Service from Overhead Systems (Continued)
(1) New Underground Service Installations (Continued)
(A) the Applicant shall (Continued)
4. furnish, install, and maintain, at his expense, any
specified conduit or duct from the transformer vault,
pull box or other duct termination facilities to the
riser,
5. furnish and install, at his expense, an underground
riser conduit to a point eight feet above the ground
on the designated pole,
6. furnish the riser conduit and the required protective
coverings, attachments and terminals to complete the
riser installation,
7. permit the Utility to use the trench and any conduit
and duct system on his premises for the purpose of
housing the Utility's service conductors or cables,
8. pay to the Utility the cost of any conductors or
cables required between the service connection point
on the pole and the duct termination facilities in
addition to the provided by the Utility in section
A.2.(c).(1).(B).8. hereof, and
9. provide and maintain, at his expense, any necessary
outdoor termination enclosures.
(B) the Utility shall
1. specify the number, size and location of the
transformer vaults, pull boxes or other duct
termination facilities,
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
EXHIBIT G
PAGE 6 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(c) Underground Service from Overhead Systems (Continued)
(1) New Underground Service Installations (Continued)
(B) the Utility shall (Continued)
2. designate the pole or location of such pole where the
service connection will be made,
3. specify the number, size, type and manner of
installation of conduit or duct systems on Applicant's
premises,
4. specify the number, size and type of riser together
with associated protective coverings and attachments,
5. specify the size of conductors or cables to be
installed,
6. install the conductors or cables from the service
connection point on the pole to the duct termination
facilities,
7. install the remaining portion of the riser, and
8. furnish and maintain, at its expense, all conductors
or cables required for installation between the
service connection point on the pole and duct
termination facilities for a distance of one hundred
(100) feet or less.
(C) the conductors or cables shall be terminated as follows:
1. Secondary service (480 volts or less). The conductors
or cables shall terminate in the service terminating
pull section of the Applicant's switchgear or in a
pull box or other termination facilities furnished and
installed by the Applicant.
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
Cancelling First Revised Sheet P.S.C.N. No. 55
EXHIBIT G
PAGE 7 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
2. Underground Service Connections (Continued)
(c) Underground Service from Overhead Systems (Continued)
(1) New Underground Service Installations (Continued)
(C) the conductors or cables shall be terminated as follows:
(Continued)
2. Primary service (2,400 volts or more). The conductors
or cables shall terminate in the service terminating
pull section of the Applicant's switchgear or in a
room, vault or other suitable enclosure.
(2) Underground Service Installations Replacing Existing Overhead
Services
Upon a bona fide application for replacement of an
existing overhead service with an underground service to an
Applicant's premises, an underground service connection will
be supplied in the same manner and subject to the same
conditions as for new installations under Section A.2.(c).(1).
above.
(d) Replacement or Reinforcement of Existing Underground Systems
Whenever, in the judgement of the Utility, an underground
service requires replacement or reinforcement, such
replacement or reinforcement will be made in the same manner
and subject to the same conditions as for new installations
under Section A.2.(b). (1). hereof.
3. Number of Services to be Installed
The Utility will not install more than one service, either
overhead or underground, for the same voltage and phase classification
for any one building or group of buildings on a single premises,
except that separate services may be installed for separate buildings
or groups of buildings
(Continued)
ISSUED: April 17, 1970 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: June 5, 1970 President
EXHIBIT G
PAGE 8 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
3. Number of Services to be Installed (Continued)
where necessary for the operating convenience of the Utility. Where
required by law, local ordinance, and if at Customer's convenience;
where the Utility installs more than one metered service, each meter
will be billed separately. Where more than one class of service is
required for a Customer and is to be supplied from the same pole,
manhole or service box, the service outlets are to be located as close
together as practicable.
4. Connection of Applicant's Service to Utility Lines
Only authorized employees of the Utility will be permitted to
connect the Applicant's service lateral and the Applicant's
terminating facilities to, or disconnect the same from the Utility's
electric lines.
5. Meters and Associated Equipment
(a) General
The Utility will, at its own expense, install a suitable meter
on an Applicant's premises in a location furnished by him and
approved by the Utility, which location shall, at all reasonable
times, be accessible for reading, testing and maintaining the
meter. No rent or other charge shall be made by the Applicant for
the use of this location.
(b) Multiple-Occupancy Buildings
In multiple-occupancy buildings where a number of meters are
required to measure the electricity supplied, all meters will be
located at a central point and each meter socket or panel will be
clearly marked to indicate the particular location supplied
through it.
In buildings which are divided into two or more stores or
other commercial premises, meters may be installed in the separate
premises provided no adjacent alleyway, common basement or other
location accessible to all the tenants and suitable for the
installation of
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
Original Sheet P.S.C.N. No. 56A
EXHIBIT G
PAGE 9 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
5. Meters and Associated Equipment (Continued)
(b) Multiple-Occupancy Buildings (Continued)
a group of meters exist. In such buildings, all wiring from the
Utility's point of delivery to the individual meters shall be in
rigid conduit.
(c) Sealing of Meters
All meters will be sealed by the Utility at the time of
installation and no seal shall be altered or broken except by one
of its authorized employees.
(d) Equipment Furnished by Customer
All service switches, meter sockets, meter and instrument
transformer housing, cutouts and similar devices, irrespective of
voltage, required in connection with a service and meter
installation on a Customer's premise shall be furnished,
installed and maintained by the Customer in accordance with the
Utility's requirements.
(e) Equipment Furnished by Utility
The Utility will furnish and install the necessary instrument
transformers, test facilities and meters. The Utility will furnish
the metering enclosures when in the opinion of the Utility it
appears necessary to locate metering equipment at a point that is
not accessible to the Customer.
(f) Master Meters
A master meter will be furnished and installed by the Utility
upon application by the owner or lessee of any buildings where the
floors (or portions thereof) or rooms or groups of rooms are
rented separately and where electric energy is to be metered and
resold by said owner or lessee to the individual tenants as
provided in Rule No. 18, Supply To Separate Premises and Resale.
In such cases, the said owner or lessee shall furnish, install,
maintain and test the submeters.
(Continued)
ISSUED: June 23, 1966 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: October 3, 1966 President
EXHIBIT G
PAGE 10 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
6. Transformer Installations on Applicant's Premises
(a) General
In those instances where the Utility, for aesthetic, economic
or engineering reasons, desires to install transformers on
Applicant's premises, the Applicant shall furnish a satisfactory
right-of-way for the high voltage primary service conductors and
shall provide adequate space for the transformer installation.
Right-of-way and space provisions must be such that legal
clearances from adjacent structures can be maintained and the
vault, transformer room, or enclosures shall conform with all
applicable laws of the State of Nevada, and/or municipal
regulations, and/or regulations of other public bodies having
jurisdiction thereof, and shall meet with the approval of the
Utility.
(b) Installation of 75 Kva and Larger
(1) The Utility will not furnish pole-type structures.
(2) Where transformers and associated equipment or appurtenances
are to be located in a fireproof vault or room in a building
(or structure), the Applicant shall, at his expense, provide
and maintain such vault or room as specified by the Utility.
Applicant shall also furnish and install, at his expense, all
secondary equipment and material necessary to receive service
at the secondary terminals of transformer(s) or as otherwise
specified by the Utility. The Utility will, at its expense,
complete the installation.
(3) Where transformers and associated equipment or appurtenances
are to be located outdoors, the Applicant shall, at his
expense, provide and maintain, as specified by the Utility, a
concrete pad or foundation and suitable enclosure, if
required. The Applicant shall also furnish and install, at his
expense, all secondary equipment and material necessary to
receive service at the secondary terminals of the
transformer(s) or as otherwise specified by the Utility. The
Utility will, at its expense, complete the installation.
(Continued)
ISSUED: April 17, 1970 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: June 5, 1970 President
EXHIBIT G
PAGE 11 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
A. Service Installation (Continued)
6. Transformer Installations on Applicant's Premises (Continued)
(c) Installations of Less Than 75 KVA
(1) The Utility will erect a pole-type transformer structure, at
its expense, and service from this structure will be supplied
as specified by the Utility.
(2) In those instances where the Applicant has provided a
fireproof vault or room, at his expense, the installation
shall be made in accordance with Section A.6.(b).(2). above.
(3) In those instances where the Applicant has provided a concrete
pad or foundation, the installation will be made in accordance
with Section A.6.(b).(3). above.
B. Ownership
The transformers, meters, service wires, appliances, fixtures and
other facilities furnished by the Utility at its own expense and located
wholly or partially upon a Customer's premises for the purpose of
delivering electric energy to the Customer will at all times be and remain
the property of the Utility which shall have the right to repair or
replace them at any time or to remove them after service to the Customer
has been discontinued.
Such equipment may also be used to supply other Customers whether or
not on the same premises, provided the proper rights-of-way have been
obtained.
No rent or other charge whatsoever shall be made by the Customer
against the Utility for placing or maintaining said transformers, meters,
service wires, appliances, fixtures, etc. upon the Customer's premises.
The Customer shall exercise reasonable care to prevent the facilities
of the Utility upon said premises from being damaged or destroyed, and
shall refrain from interfering with same, and, in case any defect therein
shall be discovered, shall notify the Utility thereof.
(Continued)
ISSUED: April 17, 1970 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: June 5, 1970 President
EXHIBIT G
PAGE 12 OF 13
Rule No. 16
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
C. Maintenance
The Utility will be responsible for the maintenance of its own
property only, and the Customer shall be responsible for the maintenance
of all other property required for the receipt of electric energy from the
Utility.
D. Right of Access
Upon application for electric service and the establishment of
service pursuant thereto, the Customer shall be deemed to grant to the
Utility and its assigns, to whatever extent the Customer may be empowered
to make such grant, an irrevocable easement upon and through the
Customer's premises for the location of the facilities of the Utility
required to provide service. Any such grant from the owner of the premises
serviced shall be deemed to be an easement running with the land, and
shall bind his heirs and assigns.
The Utility will, at all reasonable times, have the right of access
to a Customer's premises for any purpose normally connected with the
furnishing of electric energy and the exercise of the rights secured to it
by law or these rules.
E. Responsibility for Loss or Damage
The Utility will not be responsible for any loss or damage caused by
any negligence or wrongful act of a Customer or Customer's authorized
representatives in installing, maintaining, or operating the receiving
facilities or utilizing equipment for which electric energy is being
supplied.
The Customer shall, at his sole risk and expense, furnish, install,
inspect and keep in good and safe condition all electrical wires, lines,
machinery and apparatus of any kind or character which may be required
for: (1) receiving electric energy from the lines of the Utility,
regardless of the location of the transformers, meters or other equipment
of the Utility; and (2) applying utilizing such energy, including all
necessary protective appliances and suitable housing therefor.
The Customer shall also transmit and deliver and be solely
responsible for the transmission and delivery of all electric energy over
or through Customer's wires and equipment, regardless of the place where
such electric energy may be transformed or metered.
ISSUED: July 27, 1967 Issued By:
▇▇▇▇ ▇. ▇▇▇▇▇
EFFECTIVE: September 20, 1967 President
Rule No. 16 EXHIBIT G
PAGE 13 OF 13
SERVICE CONNECTIONS, METERS AND CUSTOMER'S FACILITIES
(Continued)
F. Remote Metering
Remote metering is available to any Customer with 120/240 volt single
phase service who does not desire to comply with Section D, Right of
Access, hereto, relative to meter reading.
The Customer will be required to pay Utility $100.00, in advance, for
the cost of installing the facilities necessary to provide remote
metering. The remote metering equipment will remain the property of
Utility, and Utility will maintain the equipment.
Utility will require a minimum of two (2) annual inspections of the
meter and remote register for verification of the meter readings.
If at any time there should exist a difference between the meter
reading and the remote register reading, the meter reading will be
considered as the proper basis for purposes of billing. If a meter test is
required, it will be done in compliance with Rule No. 17.
G. Customer's Responsibilities
1. Utility Owned Facilities
Utility property installed on the premises served for the purpose of
measuring or supplying service to a customer is placed there under
the Customer or property owner's protection. The Customer or property
owner will be held responsible for the breaking of seals, tampering
or interfering with Utility's meter or meters or other equipment of
Utility placed under their protection. Only authorized employers of
Utility will be allowed to make repairs or adjustments to meters or
other apparatus belonging to the Utility. Where such repairs or
adjustments are necessary, a charge shall be made to the customer or
property owner as appropriate, in addition to actual material costs.
See Schedule SC, PSCN No. 63C.
H. Tax Liability on Customer Contributions
Contributions by customers of or for facilities or equipment provided
under this rule will be increased by the appropriate tax liability factor
from Section C.5 of Rule No. 9 to cover the Utility's tax liability on
such contributions. Such tax liability will be paid in cash.
Issued: 11/28/88 Issued By:
▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
Effective: 11/28/88 President
Advice No.: 273-E
Amended
RULE NO. 17 EXHIBIT H
PAGE 1 OF 3
METER TESTS AND ADJUSTMENT OF BILLS FOR METER ERROR
A. Tests
1. Facilities
The utility shall provide or have access to a facility to determine
the accuracy of its meters.
2. On Customer Request
The utility shall test the meter of a customer upon his request.
No charge will be made for preparing the test once during any 12
month period. The utility may charge the customer a fee, as sat forth
in Schedule SC, PSCN No. 63C, for any additional test conducted
during the period.
The customer may be present and may request a qualified
representative of the Commission be present at the time a test is
conducted.
If a meter is tested at the request of a customer, the utility shall,
within a reasonable time after the test:
a. Provide the customer with a written statement of the results of
the test.
b. Notify the customer in writing if the meter is replaced or
repaired.
The utility will prepare and maintain a record of the results of each
test conducted pursuant to this section. The record will include:
a. The name and address of the customer.
b. The meter number.
c. The type of meter.
d. The type of test.
e. The date on which the test was conducted.
f. The results of the test.
g. A description of any action taken as a result of the test.
(Continued)
Issued: 1/16/90 Issued By:
▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
Effective: 1/16/90 President
Advice No.: 292-E
RULE NO. 17 EXHIBIT H
PAGE 2 OF 3
METER TESTS AND ADJUSTMENT OF BILLS FOR METER ERROR
(Continued)
B. Adjustment of Bills for Meter Error
1. If a meter is tested and found to be inaccurate by more than two
percent(2%), the ▇▇▇▇ for service of any customer affected must be
adjusted as provided in this section.
2. Except as otherwise provided in Section 8.3., if the meter has:
a. Slow Metering:
Under-recorded the usage of electric energy. The adjustment must
be made only for the period of the most recent three (3) months
of usage.
b. Fast Metering:
Over-recorded usage, the adjustment must be made only for the
period of the most recent six (6) months of usage.
c. Non-Registering Meters:
Upon test, been found to be non-registering, utility shall ▇▇▇▇
the customer for the estimate of consumption not registered for
either the period the meter was in use at such customer's
premises, or the preceding three (3) months, whichever is
shorter.
3. Unauthorized Service
If the utility establishes that the meter has been tampered with or
used without authorization, the billing adjustment must be calculated
for a period not to exceed the most recent six (6) months of usage or
the date on which the tampering or unauthorized use began, whichever
is greater.
(Continued)
Issued: 1/16/90
Issued By:
Effective: 1/16/90 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 292-E
RULE NO. 17 EXHIBIT H
PAGE 3 OF 3
METER TESTS AND ADJUSTMENT OF BILLS FOR METER ERROR
(Continued)
B. Adjustment of Bills for Meter Error (Continued)
4. Underpayment
A customer who, because of an adjustment to his ▇▇▇▇, owes the
utility money for service may pay that amount over a three (3) month
period.
5. Overpayment
The utility shall credit the account of a customer who was
overcharged because of an inaccurate meter not later than thirty (30)
days after the overcharge is determined.
6. Calculation of Billing Adjustment
Bills for this purpose shall be based upon:
a. Customer's prior use;
b. Customer's subsequent use correctly metered;
c. Utility's experience with other customers of the same class; and
d. The general characteristics of customer's operations.
Issued: 1/16/90
Issued By:
Effective: 1/16/90 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 292-E
EXHIBIT I
PAGE 1 OF 4
EXPERIMENTAL SCHEDULE NO. FSS
FIRM STANDBY SERVICE
COGENERATION AND SMALL POWER PRODUCTION
APPLICABILITY
Service hereunder is applicable to any Customer where all or part of the
electrical requirements can be supplied from a cogeneration or small power
production source which meets the criteria for a Qualifying Facility set forth
is subpart B, Sections 292.201-292.207 of the FERC rules (45 Fed. Reg. 17959),
and which service is elected by the Customer to be billed under the net metering
option described in Rule No. 15, paragraph B.3.a. QFs billed under the seperate
metering option of Rule No. 15, paragraph B.3.b. will be billed under the
appropriate rate schedule for regular service.
The cogeneration or small power production source may be connected for:
(1) parallel operation with service Utility, or (2) isolated operation with
standby or breakdown service provided by Utility by means of a double-throw
switch.
This schedule is limited to Customers having a maximum total demand equal
to or greater than fifty (50) kilowatts and where another schedule is not
specifically applicable.
This tariff will be effective for a period of two years from the original
effective date or until changed with the approval of the Public Service
Commission of Nevada.
TERRITORY
Entire Nevada service area, as specified.
RATES
Customer Charge
Per meter per month: $700.00
(Continued)
Issued: 10/1/89
Issued By:
Effective: 10/1/89 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 289-E
EXHIBIT I
PAGE 2 OF 4
EXPERIMENTAL SCHEDULE NO. FSS
FIRM STANDBY SERVICE
COGENERATION AND SMALL POWER PRODUCTION
(Continued)
RATES (Continued)
Fixed Stand by Demand Charge
For each kilowatt of contract demand $ 3.47
Additional Variable Demand Charge
For each kilowatt of maximum total demand
in excess of the contract demand $ 3.47
Variable Demand Charge
For each kilowatt of On-Peak billing demand $ 3.51
For each kilowatt of Mid-Peak billing demand $ 1.76
Energy Charge
Base Tariff Base Tariff Total
General Rate Energy Rate Energy Charge
------------ ----------- -------------
Winter
All On-Peak kWh, per kWh $ .01358 $ .02789 $ .04147
Plus all Mid-Peak kWh, per kWh $ .01138 $ .02789 $ .03927
Plus all Off-Peak kWh, per kWh $ .00495 $ .02789 $ .03284
Summer
All On-Peak kWh, per kWh $ .01270 $ .02789 $. 04059
Plus all Off-Peak kWh, per kWh $ .00806 $ .02789 $ .03595
Deferred Energy Accounting Adjustment
All kWh per kWh (02/01/90 - 01/31/91) $ .00113
(Continued)
Issued: 9/1/90
Issued By:
Effective: 9/1/90 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 301-E
EXHIBIT I
PAGE 3 OF 4
EXPERIMENTAL SCHEDULE NO. FSS
FIRM STANDBY SERVICE
COGENERATION AND SMALL POWER PRODUCTION
(Continued)
RATES (Continued)
Power Factor Adjustment
Credit (or charge) at the rate of $.0014 per kvarh for all actual
kvarh less than (or greater than) equivalent kvarh at a 90% power
factor level per Special Condition 5.
Voltage and Transformer Adjustment
Where service delivered directly from a primary distribution or
transmission system, the Customer, demand and energy charges shall be
decreased as follows:
Primary
Distribution Transmission
------------ ------------
a. Where service is metered at or
compensated to the delivery point 1.25% 7.50%
b. Where customer owns and maintains
all equipment required for transformation
from the delivery voltage 1.25% 7.50%
c. Where both a) and b) exist 2.50% 10.00%
d. Where neither a) nor b) exist None 5.00%
Late Charge
1% on any amount in arrears from previous ▇▇▇▇▇▇▇▇.
Tax Adjustment Charge
2% of total ▇▇▇▇ within incorporated area (3/4 of 1% for City of
Gabbs) or as designated in specific franchise agreements.
(Continued)
Issued: 2/6/89
Issued By:
Effective: 2/6/89 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 281-E
EXHIBIT I
PAGE 4 OF 4
EXPERIMENTAL SCHEDULE NO. FSS
FIRM STANDBY SERVICE
COGENERATION AND SMALL POWER PRODUCTION
(Continued)
MINIMUM CHARGE
The minimum charge for service hereunder shall be the sum of the customer
charge, demand charges, energy charges, deferred energy accounting adjustment,
power factor adjustment, voltage and transformer adjustment, late charge and tax
adjustment charge.
SPECIAL CONDITIONS
1. A written contract will be required for service hereunder, for a
minimum term of not less than five years.
2. Determination of Demand: The demand for any billing shall be defined
as the maximum measured fifteen minute average kilowatt load in the
billing period. In instances, however, where the use of energy by a
Customer is intermittent or subject to violent fluctuations, a
shorter time interval may be used and the demand determined from
special measurements. At Utility's option, a thermal type of demand
meter which does not reset after a definite time interval may be used
for demand measurements.
3. Contract Demand: The contract demand for Customers requiring standby
service for all of their self-generation capacity shall be the
nameplate capacity, in kW, of connected self-generation capacity for
which Utility will standby. In the event that measured output from
the self-generation equipment in any month exceeds the previously
established contract demand, Utility may revise the contract demand
to this higher measured amount.
(Continued)
Issued: 2/6/89
Issued By:
Effective: 2/6/89 ▇▇▇▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 281-E
EXHIBIT J
PAGE 1 OF 5
Rule No. 2
DESCRIPTION OF SERVICE
A. General
1. Service described hereunder may be obtained by any person or agency
by making application in accordance with Rule No. 3 and, if required,
by signing a contract in accordance with Rule No. 10. Each Applicant
will also be required to establish credit in accordance with Rule
No. 12. Applicant will be informed as to the conditions under which
service will be established if the requested service requires a
Utility installation beyond that specified for a service connection
in Rule No. 16.
2. The type of service available at any particular location should be
ascertained by inquiry at the local Utility office.
3. It is the responsibility of the Applicant to ascertain and comply
with regulations of governmental entities having jurisdictional
authority.
4. Alternating current service of approximately 60 hertz is regularly
supplied.
5. Voltages referred to in these tariffs are nominal and refer either
to voltage between energized conductors and ground, or to voltage
between energized conductors.
B. Service Delivery Voltages
1. The following are standard service voltages, however, not all
voltages are or can be made available at a given service delivery
point:
(Continued)
Issued: 9/21/84
Issued By:
Effective: 9/21/84 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 231-E
EXHIBIT J
PAGE 2 OF 5
Rule No. 2
DESCRIPTION OF SERVICE
(Continued)
B. Service Delivery Voltages (Continued)
Transmission
Distribution Voltages Voltages
-------------------------------------------------------------- ----------------
Single-Phase Three-Phase Three-Phase
Secondary Secondary Primary Three-Phase
-------------------------------------------------------------- ----------------
120/240 3-Wire 120/240 4- Wire* Contact local Contract local
120/208 3-Wire* 120/208 Y 4-Wire Utility office. Utility office.
277/480 Y 4-Wire
*Limited availability - subject to Utility approval.
2. Voltages greater than 600 volts but less 25,000 volts are defined as
primary distribution voltages. Service at primary distribution
voltages may be available on request subject to Utility approval.
3. Voltages of 25,000 volts and above are defined as transmission
voltages. Service at transmission voltage may be available on
request subject to Utility approval.
4. Where the Applicant desires voltage control within unusually close
limits beyond that supplied by the Utility is the normal operation of
its system, the Applicant, at his own expense, is responsible for
installing, owning, operating, and maintaining any special or
additional equipment on the load side of the point of delivery.
(Continued)
Issued: 9/21/84
Issued By:
Effective: 9/21/84 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 231-E
EXHIBIT J
PAGE 3 OF 5
Rule No. 2
DESCRIPTION OF SERVICE
(Continued)
C. General Load Limitations
1. Single and Three-Phase Secondary Service
Service Configuration Maximum
--------------------------------- Demand
Nominal -----------
Voltage Phase kW
--------------- -------------- -----------
120/240 1theta 150
120/208 1theta 150
120/208Y 3theta *
120/240 3theta *
277/480Y 3theta *
*Contingent upon transformer KVA size limitations
Note: Not all of the above voltages are or can be made available at a given
service location. It is the responsibility of the Applicant to consult
the local Utility office to ascertain the service configuration(s)
available at the location in question.
(Continued)
Issued: 9/21/84
Issued By:
Effective: 9/21/84 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 231-E
EXHIBIT J
PAGE 4 OF 5
Rule No. 2
DESCRIPTION OF SERVICE
(Continued)
C. General Load Limitations (Continued)
2. Load Balance
A customer's connected load must be balanced as nearly as practicable
between energized conductors. In no case shall the difference in
amperage between two energized conductors on a secondary service
exceed 10 percent or 50 amperes, whichever is greater. The
difference between the load on a lighting phase of a four-wire delta
service and the load on the power phase may exceed these limits.
3. Protective Devices
a. Loads connected to a service shall have sufficient protective
devices, installed and maintained at the customer's expense, to
prevent damage to equipment during routine conditions that may
include sudden loss of voltage, sudden re-energization, opening
of one or more phases, and voltage or current fluctuations or
variations.
b. It is the responsibility of the customer to furnish, install, and
maintain at his expense any protective devices necessary to
coordinate with Utility's protective devices to avoid exposing
other Utility customers to unnecessary service interruptions.
c. The connection and operation of customer owned generation
facilities in parallel with the Utility's system will be governed
by the requirements of Rule No. 15.
4. Interference With Service
The customer shall not connect load to his service that introduces
abnormal currents, voltages, and/or frequencies to the Utility's
system or to communication facilities, or that interferes with a
normally acceptable quality of service to any other customer. Upon
notification by the Utility that one of the above conditions exist,
(Continued)
Issued: 9/21/84
Issued By:
Effective: 9/21/84 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 231-E
EXHIBIT J
PAGE 5 OF 5
Rule No. 2
DESCRIPTION OF SERVICE
(Continued)
C. General Load Limitations (Continued)
4. Interference With Services (Continued)
the customer shall either discontinue use of the load causing the
interference with service or install and maintain, at his expense,
the corrective measures necessary to reasonably limit the
interference with service. If the customer fails to take corrective
measures in a timely manner and continues to use the load causing the
interference with service, the Utility may terminate service after
prior notice in accordance with Rule No. 6 of these Rules and
Regulations. Customer shall contact the local Utility office for
maximum allowable motor starting currents.
5. Power Factor Correction
The customer shall provide, at his expense, the necessary power
factor corrective equipment to maintain a power factor of at least
90% lagging unless a power factor adjustment is being applied for
billing purposes in accordance with appropriate rate schedules.
(Continued)
Issued: 9/21/84
Issued By:
Effective: 9/21/84 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 231-E
EXHIBIT K
PAGE 1 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
A. Applicability
Under provisions of this rule, the utility will purchase energy or energy
and capacity from qualifying cogenerators and small power production
facilities. These facilities will be allowed to operate in parallel with the
utility.
1. A Qualifying facility is one that meets the criteria set forth in
Subpart B, Sections 292.201 - 292.207 of the FERC rules. (45 Fed.
Reg. 17959)
2. Parallel generation is defined as a system in which the QF's
generation can be connected to a bus common with the utility's
system. Power transfer between the QF's facilities and the utility's
system is a common result.
B. BUY-SELL ARRANGEMENT
1. Utility will purchase power from qualifying small power production or
cogeneration facilities at a rate which reflects the cost which
Utility can avoid as a result of obtaining the power.
2. Utility will sell power to qualifying small power production or
cogeneration facilities based on filed Rate Schedules applicable to
comparable customers without generation.
3. Utility offers two metering options to QF's.
a. Netting Generation and Load - Metering Option I
1. The QF can choose to have the metering arranged so that
Utility purchases the
(Continued)
Issued: 3/20/81
Issued By:
Effective: 3/20/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 176-E
EXHIBIT K
PAGE 2 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
a. Netting Generation and Load - Metering
Option I (continued)
1. (Continued)
net energy which the QF does not use, and so that Utility
sells net energy which the QF does not generate.
2. When the QF's generation output is greater than his load,
Utility will purchase the excess energy which the QF does not
use. The purchase meters will register only the energy which
is supplied from the QF's system to Utility's system.
3. When the QF's generation output is less than his load,
Utility will charge the QF only for the power requirements
which are not supplied by the QF's generation. The billing
meters will register only the power requirements which are
supplied from Utility's system to the QF's system.
4. Neither the purchase meters nor the billing meters will be
allowed to reverse rotation.
5. If the applicable rate schedule requires demand metering the
demand meter will register only the demand which is supplied
from Utility's system to the QF's system. This demand meter
will be used to determine the billing demand and the
applicable rate schedule.
(Continued)
Issued: 5/4/81
Issued By:
Effective: 5/4/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 178-E
EXHIBIT K
PAGE 3 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
a. Netting Generation and Load - Metering
Option I (continued)
5. (Continued)
It is feasible that the QF's generation could reduce his
demand enough to move the customer to a different rate
schedule.
b. Separate Generation and Load - Metering
Option II
1. The Qualifying Facility can choose to have the metering
arranged so that Utility purchases 100% of the QF's
generation output, and so that Utility sells 100% of the QF's
load requirements.
2. The QF's generation and load shall be treated separately and
independently. For example, if a cogeneration facility
produces 50 KW and consumes 30 KW, it would be treated the
same as another qualifying facility that produces 50 KW, and
is located next to a factory that uses 30 KW.
3. The QF should note that the purchase meter will reverse its
rotation if the generator loses power and goes into a
motoring state. The Utility may require a reverse power relay
to prevent this condition.
C. INTERCONNECTION COSTS
1. The Qualifying Facility shall pay all costs of interconnection with
the Utility's facilities.
(Continued)
Issued: 5/4/81
Issued By:
Effective: 5/4/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 178-E
EXHIBIT K
PAGE 4 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
C. INTERCONNECTION COSTS - (Continued)
2. Utility financing for specified portions of interconnection costs is
available on an individual contract basis. The contracts will be
negotiated with each Qualifying Facility and will include, but not be
limited to, the following terms:
a. The Utility will finance only the services drop and metering
equipment.
b. The owner of the Qualifying Facility will be required to execute
a promissory note in an amount equal to the actual costs of
construction, bearing interest at the prime rate prevailing at
the time of execution plus 1%.
c. The Utility will require that the debt be secured by property,
bond, letter of credit, or other adequate security.
d. Monthly payment amounts and repaying schedules will be determined
on a case-by-case basis.
D. QF DESIGN & OPERATING REQUIREMENTS
The QF must meet Utility's latest design and operating specifications in
addition to all national, state, and local construction and safety codes.
Utility's design and operating specifications are the minimum requirements
that the QF must meet.
(Continued)
Issued: 10/21/81
Issued By:
Effective: 10/21/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 189-E
EXHIBIT K
PAGE 5 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
D. QF DESIGN & OPERATING REQUIREMENTS (Continued)
These requirements are intended to protect other customers and Utility
from damage caused by the parallel generation facility.
These design requirements are not intended to protect the QF's generation
facility from every possible source of damage. The parallel generation QF
may wish to install additional protective equipment to protect his
generation facility.
1. All protective device relay settings and all electrical schematics
must be approved in writing by Utility.
2. The QF will purchase, own, operate, and maintain the required
protective equipment.
3. Utility reserves the right to require additional protective equipment
and safety measures as further experience may dictate.
4. The operation of the QF's generation facility must not reduce the
quality of service to other Utility customers. No abnormal voltage,
currents, frequencies, or interruptions are permitted.
5. The QF will at no time energize a de-energized Utility circuit,
without the permission and the supervision of Utility personnel.
6. The QF shall not bypass any of the protective relays or equipment.
(Continued)
Issued: 5/4/81
Issued By:
Effective: 5/4/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 178-E
EXHIBIT K
PAGE 6 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
D. QF DESIGN & OPERATING REQUIREMENTS (Continued)
7. The QF is responsible for damage caused to other customers and to
Utility as a result of mis-operation or malfunction of the QF's
generation facility or protective equipment.
8. Utility is not responsible for damage caused to the QF's facility as
a result of acts over which Utility has no control.
9. Utility is not responsible for damage caused to the QF's facility as
a result of automatic or manual reclosing.
10. The QF is responsible for performing scheduled maintenance on the
generation facility and the protective equipment to keep the facility
in proper operating condition. Utility reserves the right to inspect
the customer's facility to check for a hazardous condition or a lack
of scheduled maintenance.
11. Utility reserves the right to discontinue parallel generation with
reasonable prior notice for any of the following:
a. Utility needs to perform non-emergency maintenance or repair of
utility facilities.
b. The QF's generation reduces the qualify of service to other
customers.
c. Inspection of the QF's facility reveals a hazardous condition or
a lack of scheduled maintenance.
(Continued)
Issued: 5/4/81
Issued By:
Effective: 5/4/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 178-E
EXHIBIT K
PAGE 7 OF 7
Rule No. 15
COGENERATORS AND SMALL POWER PRODUCERS (QF'S)
(Continued)
D. QF DESIGN & OPERATING REQUIREMENTS (Continued)
12. Utility reserves the right to open the main disconnecting device and
cease parallel generation without prior notice in the event of a
system emergency.
a. The QF is advised that his generation facility must be capable of
withstanding load rejection of this nature. Utility is not
responsible for any damage caused to the QF's equipment as a
result of disconnection from Utility's system.
Issued: 5/4/81
Issued By:
Effective: 5/4/81 ▇▇▇ ▇. ▇▇▇▇▇▇▇
President
Advice No.: 178-E
EXHIBIT L
PAGE 1 OF 17
SMALL POWER PRODUCTION AND COGENERATION PLANNING AND DESIGN CRITERIA
FOR GENERATION GREATER THAN ONE MEGAWATT*
TABLE OF CONTENTS
Section Page No.
------- --------
1.0 APPLICATION AND POLICY ........................................ 2
2.0 CONTRACT INFORMATION .......................................... 3
3.0 INTERCONNECTION AND TRANSIENT STUDY REQUIREMENTS .............. 4
4.0 METERING ...................................................... 6
5.0 DESIGN REQUIREMENTS AND SPECIFICATIONS ........................ 7
* Design criteria for qualifying facilities whose output is less than one
megawatt are specified in SPPCo. Engineering Standard 2.2 GW 01.
--------------------------------------------------------------------------------
CHG DATE DESCRIPTION | DWN | DSGN | CHKD | APVD
--------------------------------------------------------------- SHEET 1 OF 11
-----------------
VOL SECT PAGE
APPROVED BY -----------------
------------------ ENGINEERING & CONSTRUCTION STANDARD 1 2.2
DESIGNED | CHECKED
[LOGO] SMALL POWER PRODUCTION
------------------ AND CO-GENERATION FOR GENERATION -----------------
DRAWN | DATE GREATER THAN ONE MEGAWATT DRAWING NO.
1 10/20/88 SIERRA PACIFIC POWER CO. 2.2GN02
--------------------------------------------------------------------------------
1.0 APPLICATION AND POLICY
1.1 Application
The purpose of this standard is to present the planning and design
requirements which all customer-owned qualifying power production
facilities (QF) must meet or exceed prior to parallel operation with
Sierra Pacific Power Company's (SPPCo.'s) electric system. This
document applies to all customer-owned qualifying power production
facilities whose gross aggregate output exceeds one megawatt (1 MW).
The QF Developer and SPPCo. personnel are to use this document when
planning installations of QF generation. It is emphasized that these
requirements are general and may not cover all details in specific
cases. The QF Developer should review project plans with SPPCo.
before purchasing of installing equipment.
The abbreviations QF for customer-owned qualified power production
facility and SPPCo. for Sierra Pacific Power Company will be used for
the remainder of this standard.
1.2 QF Definition
A qualifying facility is one that meets the criteria set forth in
Subpart 13, Section 202.201-292.207 of the FERC rules.
1.3 Policy Statements
- Under provisions of SPPCo. Rule No. 15, in Nevada, and Rule No. 21
in California, submitted to and approved by the appropriate
regulatory agency SPPCo. will purchase energy or energy and
capacity from qualifying facilities.
- QF generation will be integrated into SPPCo.'s electric system in a
manner that will not adversely impact the quality of service to
customers or cause adverse impacts to personnel or existing
equipment.
- The QF will be required to operate in a prudent manner that will
not result in injury to customers of SPPCo. personnel nor cause
damage to customer or SPPCo. equipment.
--------------------------------------------------------------------------------
ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE
SMALL POWER PRODUCTION -----------------
[LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 2 OF 11
GREATER THAN ONE MEGAWATT -------------
DRAWING NO.
SIERRA PACIFIC POWER CO. 2.2GNO2
--------------------------------------------------------------------------------
EXHIBIT L
PAGES 3 OF 17
2.0 CONTRACT INFORMATION
2.1 Initial Contact
Initial developer contact should be addressed to the Manager of Power
Contracts Engineering Department at (▇▇▇) ▇▇▇-▇▇▇▇. A flow chart
follows to visually aid the QF Developer in defining coordination
requirements.
2.1.1 The QF Developer will be required to submit a written request
for a power purchase agreement. A description of the project
(resource or fuel, size of unit(s), net generation, and
ultimate plant total), the project location (township, range,
and section), and any other pertinent data should be
included.
2.1.2 From the information provided by the QF Developer, SPPCo.
will provide an estimate of the cost of an interconnection
study, the alternative to be studied, and the approximate
interconnection __________ of each alternative to be studied.
SPPCo. will also provide a draft power purchase agreement, a
data sheet to be completed by the QF Developer which supplies
project study data, and an information request regarding the
project.
2.1.3 Fill out and return "Data Request For Generator
Interconnection" Form.
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3.0 INTERCONNECTION AND TRANSIENT STUDY REQUIREMENTS
The interconnection study, which develops requirements and alternatives
with supporting cost estimates for the required interface
facilities, is required for all projects. The transient study is required
when SPPCo. determines that the size and location of the proposed QF may
cause conditions detrimental to the electric system.
3.1 Interconnection Study
The interconnection study examines the steady state effect that the
QF generation has on SPPCo.'s system. The study is computer based and
models the QF's generation in SPPCo.'s transmission system.
The study will determine the optimum interconnection alternative for
the QF Developer's project and recommend a system that meets SPPCo.'s
reliability and quality of service standards with the lowest overall
cost to the QF Developer.
The following is a list of the information developed in the
interconnection study for use by the QF and SPPCo.
- Analysis of alternatives to determine the least expensive
connection method that meets SPPCo.'s reliability and quality of
service standards.
- Recommended conductor size for the interconnection line determined
by using the QF Developer's economic data.
- Recommended step-up transformer cap range, settings, and winding
configuration.
- Available fault duty.
- Recommended BIL ratings.
- Expected maximum and minimum voltages.
- Voltage sag and surge for largest motor start and unit drop, and
define any system modifications to meet SPPCo. sag and surge
requirements.
- Additions to SPPCo.'s electric system required to serve QF start-up
loads.
- Possible source of construction power.
- Communications, supervisory control, and telemetering requirements.
- Metering requirements.
- Interconnection protection requirements and/or modifications to the
existing system.
- Transfer trip requirements (if any).
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EXHIBIT L
PAGES 5 OF 17
- Frequency and type of utility interruption expected.
- System reactive requirements.
- System operation considerations.
- Special facilities, construction schedule, and equipment lead
times.
- Average incremental losses.
- Potential impacts of QF project on system reliability and quality
of service to existing QF projects and other customers.
3.1.1 Attachment 1, Part A is a data sheet detailing the
information required to perform the interconnection study.
The QF Developer shall ___ the data sheets to sub___ the data
required for the study.
3.2 Transient Study
High-speed transients can result in degradation of the quality of
service, equipment damage, and/or potential safety problems.
Transients are not reviewed in the interconnection study. The
transient study is performed using a specifically tailored computer
program to determine the nature of high-speed transients and to
evaluate the corrective actions necessary to minimize their effects.
The necessity for a transient study will be determined after the
preliminary analysis of the interconnection study. The following
relative criteria increase the necessity for a transient study.
- Strength of the interconnected system.
- Location with respect to other customer loads.
- Probability of isolation of the QF with other loads.
- Size of the QF generator.
- Connection of EHV (230 kV and above) system.
3.2.1 Attachment 1, Part B is a data sheet detailing the
information required to perform the transient study. The QF
Developer shall utilize the data sheets to submit the data
required for the study.
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4.0 METERING
4.1 Metering Location
Metering of capacity and energy purchased from the QF will normally
be accomplished at the point of delivery. If point-of-delivery
metering is not practical, metering may be established at other
locations. Exact location will be determined on a site-specific
basis. All metering will be compensated to the point of delivery.
4.2 CT and PT Location
The QF Developer shall make provisions in their design to include the
installation of the metering CTs and PTs by SPPCo. The installation
will be site specific with design approval by SPPCo. The CTs and PTs
shall be located such that there are no taps prior to their location
in the circuit when viewed from the SPPCo. system. The CTs and PTs
will be metering class and will be used for revenue metering only. No
customer-owned metering and relaying will be allowed in the metering
circuits.
4.3 Metering Provisions
The metering will be confined to a separate enclosure/cubicle that
is locked and/or sealed by SPPCo. All metering installations shall
comply with SPPCo.'s metering standard as detailed in SPPCo.'s
Standard Volume 2.
SPPCo. will specify, procure, and install the metering current
transformers (CTs), potential transformers (PTs), and meter(s).
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EXHIBIT L
PAGES 7 OF 17
5.0 DESIGN REQUIREMENTS AND SPECIFICATIONS
5.1 Interconnection Facility
SPPCo. will design, procure, and construct at the QF Developer's
expense an interconnection facility (Point of Delivery), separate
from the QF, that will isolate the generation from SPPCo.'s system
when required.
This facility is not intended to protect the QF Developer's
generation. SPPCo. recommends consulting the generator manufacturer
and/or engaging the services of a registered electrical engineer for
the design of the generator unit protection schemes. Generator unit
protection is the sole responsibility of the QF Developer.
Location, ownership, control, and maintenance will be defined in the
Power Purchase and Facilities contracts.
5.1.1 Facility Components
The interconnection facility, as a minimum, will consist of a
control building, the interrupting and isolating device(s),
protective control devices, and data-acquisition equipment.
All the above will be enclosed in a fenced yard with
restricted access. SPPCo. Standard GI0005T presents the
minimum-design specifications for substation interconnection
facilities. GI0005T supplements the following requirements:
5.1.1.1 The control building will be temperature controlled
and weatherproof to enclose the AC and DC power
sources; the relaying devices; and the
telemetering, supervisory RTU, and communication
equipment.
5.1.1.2 The interrupting device will be a power circuit
breaker capable of interrupting maximum available
fault current or industry-standard minimum levels,
whichever is greater. It shall be connected for
SPPCo. supervisory control.
If the addition of a line tap and extension to the
QF's generation adds any appreciable exposure to
the existing transmission/distribution facilities,
additional circuit breaker(s) may be required at
the tap point to mitigate this exposure.
Air-break switches will be installed on each side
of the circuit breaker to isolate the breaker for
inspection and maintenance purposes. Single-breaker
schemes will not include bypass provisions. Where
lines terminate on switches, ground blades will be
required.
5.1.1.3 The following protective relays will be installed
at the interconnection point (minimum requirement).
Typical settings required by SPPCo. are defined
below. Sierra will
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provide site-specific settings prior to
interconnection testing.
- Phase and Neutral Overcurrent Relays.
- Over/Undervoltage Relays.
- Over/Undervoltage protection will be set to pick
up at 111 percent of nominal with a definite
time to trip of 3.0 seconds. In addition, the
high-speed (0.15 second) trip will be initiated
if the voltage at the interconnection exceeds 115
percent of nominal.
- Over/Underfrequency Relays.
Underfrequency protection will typically be set
at 58.0 Hz with a time delay of 15 seconds to
coordinate with the SPPCo. underfrequency load
shedding scheme. The turbine-generator supplied
by the QF Developer should be designed to operate
at 58.0 Hz for 15 seconds without any loss of
life.
Overfrequency protection will be set to trip at
61 Hz in three seconds and at 63 Hz in 0.15
seconds.
- Negative Sequence Relay (Loss of Phase).
This relay will be set to detect loss of one
phase with a generator output down to 20 percent.
Tripping time will be dependent upon what other
devices must be coordinated with, but a typical
value would be three-five seconds.
- Synch-Check Relay.
The relay will prevent the circuit breaker from
operation under excessive phase-angle differences
and it will limit torques on the QF generator
that could damage equipment.
Disclaimer - The interconnection protection and
settings outlined above are not to be construed
as protection of the QF turbine generator.
Additional supplementary protection may be
required.
5.1.1.4 A Supervisory Remote Terminal Unit will be
installed at the interconnection facility with
the necessary interface to connect it to SPPCo.'s
communications system. This system will provide
telemetering and control.
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EXHIBIT L
PAGES 9 OF 17
The following information will be remotely monitored with the
telemetering equipment:
- ▇▇▇▇▇ In/Out
- Vars In/Out
- Amps
- KWHr and KVarHr
- Line Voltage at Interconnection
- Interconnection Breaker Status/Control
5.2 SPPCo. System Modifications Required to Support the QF
In addition to the above requirements, replacement or upgrade of
existing protective devices(s) at other locations may be necessary as
a result of the addition of QF generation. This may include breakers,
relays, controls, and other protective devices.
Should the QF's generation have the potential to be isolated with a
portion of the SPPCo. system such that the connected load is less
than or equal to the output of the generator, additional protection
may be required. This protection may consist of additional relaying
or may entail the design of a complete remedial-action scheme
utilizing transfer tripping or some other method to minimize
potential adverse effects caused by the QF. Transient study results
will dictate the extent of additional protection requirements or
operating restrictions.
5.3 Extension Line
If ownership, by SPPCo., of the extension line is contemplated by the
QF Developer, the line must be constructed such that it complies with
SPPCo.'s design, construction, and material standards. In addition,
all right-of-way and permits will be reviewed and approved by SPPCo.
The extension line (transmission or distribution) design will be
submitted by SPPCo. for review to ensure that the proposed
installation meets the minimum requirements as specified by SPPCo.
SPPCo. Standard GI0001T defines the minimum design standards for
transmission lines, and SPPCo. Standard GEN01T defines the minimum
standards for distribution lines.
5.4 Customer Design Requirements
This section provides the minimum requirements that the QF Developer
must meet for major equipment, design review, and design
responsibility.
5.4.1 Codes - The QF Developer's installation must meet all
applicable national, state, and local building and safety
codes. In addition, installations shall comply with the
National Electric Code, National Electric Safety Code (ANSI
C2), and ANSI, IEEE, and NEMA standards for electrical
materials and equipment.
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5.4.2 Major Equipment Requirements
5.4.2.1 Synchronous Generation - Units or groups of smaller
units in one location with individual or total
aggregate capacity greater than 1 MW must use
synchronous generators, with speed-droop governors
and high-speed excitation systems. Individual units
should have a minimum operating capability of .90
lagging to 95 leading power factor at rated real
power output. At times SPPCo. may require direct or
indirect voltage or power factor control of these
units to maintain acceptable system operation.
Exception:
Units or groups of units connected directly to the
distribution system (SPPCo.'s 25 kV or below
electrical system) must be reviewed for safety,
security, and transient response associated with
islanding conditions. This review may dictate a
requirement for induction rather than synchronous
generation. SPPCo. will specify induction or
synchronous generation in these cases subsequent to
the interconnection/transient studies.
5.4.2.1.1 Individual generators 1 MW or larger are
required to have speed-droop governors
with a permanent droop setting of 5%.
While synchronized to SPPCo.'s
electrical system, the governor will
operate in droop mode and shall not be
blocked without prior permission from
SPPCo. Separate generation controllers
will have to be reviewed and approved
before the unit will be allowed to go
into service.
5.4.2.1.2 Individual generators 1 MW or larger
should have excitation systems with
operational, continuously acting (IEEE
Def. 2.12.1), automatic voltage
regulators. Voltage regulators shall not
be left in non-automatic operation
without prior permission from SPPCo. The
voltage response ratio (IEEE Def. 3.18
and 3.21) of said systems are required
to be .5 or greater. The facility
developer/owner must supply SPPCo. with
test results documenting the response
ratio performance. SPPCo. reserves the
right to determine on an individual
basis, whether a generators excitation
system is acceptable.
5.4.2.1.3 Individual generators 1 MW or larger may
be required to have a power factor
regulator. Determination of this
requirement will be performed by SPPCo.
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EXHIBIT L
PAGES 11 OF 17
5.4.2.1.4 Individual generators with a capacity
less than 75 MW may be required to have
power system stabilizers installed with
their excitation systems. The
determination will be performed by
SPPCo. and will be dependent on the
location of the facility, excitation
system type and performance relative to
SPPCo.'s electrical network.
5.4.2.1.5 Individual generators 75 MW or larger
are required to have power system
stabilizers (PSS) installed with their
excitation systems. The PSS must be
calibrated and operated in accordance
with Western Systems Coordinating
Council (WSCC) standard procedures for
calibration, testing, and operation of
PSS equipment. In addition, the
calibration and test reports must be
submitted to SPPCo.'s Transmission
Planning Department for review and
approval. The facility will not be
considered operational until calibration
of the PSS has been performed to
SPPCo.'s satisfaction. A copy of the
WSCC Power System Stabilizer Test
Procedures may be obtained from SPPCo.
5.4.2.2 Power Transformer - All step-up power transformers
connected to SPPCo.'s system must have a grounded
wye high-voltage winding. It is recommended that
the low-voltage winding (generator side) of the
step-up transformer be a delta connection. The
nominal voltage ratings (high side and BIL) must be
compatible with the system voltages on the line to
which it is attached. Where low-side metering will
be utilized, certified test results detailing the
losses of the transformer must be provided to
SPPCo.
5.4.3 It is the responsibility of the QF Developer to incorporate
the following information into the design of their
generation facility. The QF Developer should not limit their
design to only these items.
5.4.3.1 Full Load Rejection - The QF Developer's generation
facility must be designed with the capability or
protection to withstand sudden loss of load.
5.4.3.2 Primary Voltage Changes - The generator exciter
system and voltage regulation equipment on
synchronous generators must be capable of operating
subject to normal primary voltage changes on
SPPCo.'s system ranging from 7.5 percent above or
below nominal primary voltage to +/-10 percent
during emergency conditions. During a disturbance,
the voltage may fluctuate beyond the 10 percent
range. Equipment that is not capable of
withstanding these excursions should be protected.
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5.4.3.3 Harmonics - The QF Developer's generation facility
shall not cause unacceptable distortion of the
sinusoidal voltage or current wave form. The
maximum allowable total harmonic voltage (all
harmonics) and current distortion cannot exceed the
values published in IEEE Standard 519.
5.4.3.4 Voltage Sag - Motor starting and switching
operations are limited so that the momentary
voltage sag (flicker) during motor starting or
switching does not exceed 4 percent of the nominal
system voltage for any other customers.
5.5 Proposed Design Review
The QF Developer shall submit, for SPPCo.'s review, a generation
facility one-line diagram, approved by a registered professional
engineer, indicating the QF's protective devices and their functions.
Current and potential transformer ratios must be included on the
on-line diagram when required. In addition, protective device types,
styles, and settings must be provided. The review is intended to
ensure that the proposed installation meets the minimum requirements
to protect SPPCo's system from misoperations of the generating unit.
SPPCo. reserves the right to require additional protective equipment
and safety measure as further experience may dictate.
5.6 Synchronizing Equipment
Synchronizing equipment is required for synchronous generators at the
interconnection, generator, and other breakers as necessary. The
generator must be brought on-line parallel to SPPCo.'s system by one
of the following methods:
5.6.1 Automatic synchronizing.
5.6.2 Manual synchronizing - A synch-check ralay is required to
supervise manual closing of the generator circuit breaker.
5.7 QF Telephone requirements
The QF Developer is required to install a telephone for direct
communication with SPPCo.'s Electric System Control Center (ESCC).
The telephone communication between the QF and ESCC shall be delay
free.
66:014
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EXHIBIT L
PAGES 13 OF 17
[LOGO]
DATA REQUEST FOR GENERATOR INTERCONNECTION
NOTE: FOR VALUES GIVEN IN PER UNIT, PLEASE INCLUDE BASES.
IF THERE ARE ANY PROBLEMS OR IF THERE IS ANY CONFUSION WITH THE
FOLLOWING FORM(S), PLEASE CONTACT SPPCo.'s TRANSMISSION PLANNING
DEPARTMENT.
1. A RANGE AND TOWNSHIP SITE MAP OF THE PLANNED FACILITIES WITH THE
TURBINE/GENERATOR STEP UP TRANSFORMER AND SUBSTATION IDENTIFIED.
(PLEASE ATTACH)
2. A ONE-LINE DIAGRAM OF THE PLANNED GENERATION FACILITIES. (PLEASE
ATTACH) THE ONE-LINE DIAGRAM SHOULD INCLUDE:
A. TRANSMISSION/DISTRIBUTION LINES(S)
B. GENERATORS
C. TRANSFORMERS
D. MOTORS
E. BREAKERS
F. FUSES
G. LIGHTNING ARRESTORS
H. DISCONNECT SWITCHES
I. POWER FACTOR CORRECTION EQUIPMENT (IE CAPACITORS/REACTORS)
J. STATION SERVICE LOADS
K. OTHER SPECIAL DEVICES
3. A CONSTRUCTION SCHEDULE WITH CONSTRUCTION POWER, START-UP POWER, AND
FULL LOAD TESTING DATES IDENTIFIED (IF A MORE DETAILED SCHEDULE IS
AVAILABLE PLEASE ATTACH)
DESCRIPTION DATE
----------- ----
START CONSTRUCTION ____/____/____
CONSTRUCTION COMPLETE ____/____/____
START-UP, BEGIN FULL-LOAD TESTING ____/____/____
FULL-LOAD TESTING COMPLETE ____/____/____
4. AN ESTIMATED ON-LINE DATE AND THE TOTAL FUTURE CAPACITY FOR ANY
ADDITIONAL GENERATION ADDED AT THE INITIAL SITE
SIZE ON-LINE DATE
---- ------------
MW ____/____/____
MW ____/____/____
MW ____/____/____
5. TURBINE/GENERATOR DATA: (INFORMATION SHOULD BE PROVIDED FOR EACH
GENERATOR.) GENERATORS MUST BE SYNCHRONOUS IF AGGREGATE GENERATION IS
1 MW OR GREATER.)
▇▇▇▇ #▇ ▇▇▇▇ #▇ ▇▇▇▇ #▇ (ETC)
------- ------- -------------
A. TYPE OF GENERATING UNIT
(IE INDUCTION OR SYNCHRONOUS) _______ _______ _______
MANUFACTURER _______ _______ _______
EXCITATION SYSTEM TYPE - _______ _______ _______
B. RATED MVA - _______ _______ _______
C. MAXIMUM GROSS OUTPUT (MW) - _______ _______ _______
D. RATED LEADING POWER FACTOR - _______ _______ _______
RATED LAGGING POWER FACTOR - _______ _______ _______
E. NOMINAL VOLTAGE AND ACCEPTABLE
VOLTAGE RANGE (VOLTS +/-%) - _______ _______ _______
F. ESTIMATED LOAD FACTOR, NUMBER OF
HOURS/YEAR OF OPERATION, OR MWH/YEAR - _______ _______ _______
G. STABILITY DATA:
1. INERTIA OF TURBINE/GENERATOR (MW-SEC) - _______ _______ _______
2. TRANSIENT DIRECT AXIS REACTANCE (PU) - _______ _______ _______
3. EXCITATION SYSTEM DATA (SEE NOTE 1)
(PLEASE ATTACH)
4. GOVENOR DATA (SEE NOTE 1 PLEASE ATTACH)
NOTE 1: THIS INFORMATION MAY NOT BE REQUIRED FOR AN INTERCONNECTION STUDY,
BUT WILL BE REQUIRED BEFORE THE ACTUAL OPERATION OF THE UNIT.
6. STEP-UP TRANSFORMER DATA:
(INFORMATION SHOULD BE PROVIDED FOR EACH TRANSFORMER. STEP-UP
TRANSFORMER MUST BE GROUNDED WYE ON THE HIGH VOLTAGE WINDING.)
XFMR #1 XFMR #2 XFMR #3 (ETC)
------- ------- -------------
A. SELF-COOLED AND TOP MVA RATINGS
(OR/FOA MVA) - _______ _______ _______
B. NOMINAL VOLTAGE RATING (KV) - _______ _______ _______
AVAILABLE TAPS FOR EACH WINDING (+/-%) _______ _______ _______
C. ELECTRICAL CONFIGURATION OF EACH WINDING
(DELTA OR WYE):
1. HIGH SIDE WINDING - _______ _______ _______
2. LOW SIDE WINDING - _______ _______ _______
IMPEDANCE ON THE OA BASE (%) - _______ _______ _______
7. AUXILIARY LOAD DATA:
A. MINIMUM LOAD AND POWER FACTOR; IE DURING PLANT SHUTDOWN WITH
MINIMUM FACILITIES OPERATING (KW & PF) -
B. MINIMUM LOAD DURING
START-UP (KW) -
C. MAXIMUM LOAD AND POWER FACTOR DURING NORMAL OPERATION (KW
& PF)
1. ONE UNIT OPERATING -
2. TWO UNIT OPERATING -
3. ETC.
D. LARGEST MOTOR TO BE STARTED (HP) -
STARTING METHOD -
INRUSH KVA AT RATED MOTOR VOLTAGE -
EXHIBIT L
PAGES 15 OF 17
TRANSIENT STUDY DATA REQUIRED FOR A GENERATION INTERCONNECTION TRANSIENT
STUDY
NOTE: ITEMS ARE CONSIDERED MANDATORY.
IGNORE ANY ITEMS FOR WHICH THE DATA HAS PREVIOUSLY BEEN SUPPLIED.
FOR VALUES GIVEN IN PER UNIT, PLEASE INCLUDE BASES.
1. TRANSMISSION/DISTRIBUTION LINE DATA:
A. KV LINE-TO-LINE
B. LINE LENGTH (S)(MI)
C. CONDUCTOR TYPE(S)
D. NEUTRAL TYPE(S)
E. NEUTRAL GROUNDING CONFIGURATION
F. LINE STRUCTURE TYPE(S) (CONFIGURATION OF CONDUCTORS AND NEUTRAL
WITH HEIGHT ABOVE GROUND AND SPACINGS DENOTED.)
XFMR #1 XFMR #2 XFMR #3 (ETC)
------- ------- -------------
2. TRANSFORMER DATA:
A. PRIMARY/SECONDARY/TERTIARY MVA RATINGS ____/____/____ ____/____/____ ____/____/____
B. PRIMARY/SECONDARY/TERTIARY VOLTAGE RATINGS ____/____/____ ____/____/____ ____/____/____
C. PRIMARY/SECONDARY/TERTIARY TAPS)
(NOTE INTENDED OPERATIONAL TAPS) ____/____/____ ____/____/____ ____/____/____
D. WINDING CONNECTION DIAGRAMS (PLEASE ATTACH)
E. BIL RATINGS (KV) ______ ______ ______
F. IMPEDANCE ON THE OA BASE (%) ______ ______ ______
3. CAPACITOR/REACTOR DATA:
A. TYPE
B. RATED KVA
C. RATED KV
D. IMPEDANCE (%)
4. STATION SERVICE LOAD DATA:
A. TYPES OF LOADS AND KVA
B. TOTAL OPERATIONAL LOAD KVA AND POWER FACTOR:
1. NORMAL
2. MAXIMUM
3. MINIMUM
5. LIGHTING ARRESTOR DATA: (PROVIDE INFORMATION FOR ALL ARRESTORS IE
LINE AND TRANSFORMER
A. MANUFACTURER
B. TYPE
C. VOLTAGE RATINGS
6. INDUCTION GENERATOR DATA:
▇▇▇▇ #▇ ▇▇▇▇ #▇ ▇▇▇▇ #▇ (ETC)
------- ------- -------------
A. FULL LOAD CURRENT _______ _______ _______
B. POWER FACTOR _______ _______ _______
C. SLIP OR SPEED AT FULL LOAD _______ _______ _______
D. LOCKED ROTOR CURRENT AT 100% VOLTAGE _______ _______ _______
E. LOCKED ROTOR POWER FACTOR _______ _______ _______
F. ELECTRICAL TORQUE AND CURRENT VERSUS SPEED
CURVE FROM 0% TO 100% SPEED _______ _______ _______
G. MOMENT OF INERTIA (WR2) OF THE GENERATOR AND
TURBINE (GEARCASE ALSO IF USED) _______ _______ _______
H. GOVERNOR SYSTEM MODEL WITH PARAMETERS _______ _______ _______
I. PRIME MOVER SYSTEM MODEL WITH PARAMETERS _______ _______ _______
7. SIERRA/WSCC FULL REPRESENTATION
SYNCHRONOUS GENERATOR DATE:
▇▇▇▇ #▇ ▇▇▇▇ #▇ ▇▇▇▇ #▇ (ETC)
------- ------- -------------
A. GENERATOR DATA:
1. BASE KVA _______ _______ _______
2. MAXIMUM KW _______ _______ _______
3. MINIMUM KW _______ _______ _______
4. TERMINAL VOLTAGE (KV) _______ _______ _______
5. RATED POWER FACTOR _______ _______ _______
6. DIRECT-AXIS SUBTRANSIENT REACTANCE, X"D
(PU) _______ _______ _______
7. QUADRATURE-AXIS SUBTRANSIENT
(PU) REACTANCE X"O (PU) _______ _______ _______
8. DIRECT-AXIS SUBTRANSIENT OPEN CIRCUIT
TIME CONSTANT, T"DO (SEC) _______ _______ _______
9. QUADRATURE-AXIS SUBTRANSIENT OPEN
CIRCUIT TIME CONSTANT, T"OO (SEC) _______ _______ _______
10. KINETIC ENERGY, EMWS _______ _______ _______
11. ARMATURE RESISTANCE, RA (PU) _______ _______ _______
12. DIRECT-AXIS TRANSIENT REACTANCE, X"D (PU) _______ _______ _______
13. QUADRATURE-AXIS TRANSIENT REACTANCE
X"O (PU) _______ _______ _______
14. DIRECT-AXIS NON-SATURATED
SYNCHRONOUS REACTANCE, XD (PU) _______ _______ _______
15. QUADRATURE-AXIS NON-SATURATED
SYNCHRONOUS REACTANCE, XO (PU) _______ _______ _______
16. DIRECT-AXIS TRANSIENT OPEN CIRCUIT TIME
CONSTANT, T"OO (SEC) _______ _______ _______
17. QUADRATURE-AXIS TRANSIENT OPEN CIRCUIT
TIME CONSTANT, T"OO (SEC) _______ _______ _______
18. STATOR LEAKAGE REACTANCE, XL (PU) _______ _______ _______
19. SATURATINO AT 1.0 P.U. TERMINAL
VOLTAGE SG1.0 _______ _______ _______
20. SATURATION AT 1.2 P.U. TERMINAL
VOLTANGE SG1.2 _______ _______ _______
▇▇▇▇ #▇ ▇▇▇▇ #▇ ▇▇▇▇ #▇ (ETC)
------- ------- -------------
B. EXCITER DATA
1. VOLTAGE REGULATOR GAIN, KA _______ _______ _______
2. VOLTAGE REGULATOR LAG TIME CONSTANT,
TA (SEC) _______ _______ _______
3. MAXIMUM VOLTAGE REGULATOR OUTPUT,
VRMAX (PU) _______ _______ _______
4. MINIMUM VOLTAGE REGULATOR OUTPUT,
VRM (PU) _______ _______ _______
5. EXCITER CONSTANT RELATED TO SELF-EXCITER
FIELD, KE (PU) _______ _______ _______
6. EXCITER TIME CONSTANT, TE (SEC) _______ _______ _______
7. EXCITER SATURATION AT MAXIMUM FIELD
VOLTAGE SE1 (PU) _______ _______ _______
8. EXCITER SATURATION AT 75% ▇▇▇▇▇▇▇ ▇▇▇▇▇
▇▇▇▇▇▇▇, ▇▇▇ (▇▇) _______ _______ _______
9. MINIMUM EXCITER OUTPUT VOLTAGE, EFDMIN
(PU) _______ _______ _______
10. MAXIMUM FIELD VOLTAGE, EFDMAX (PU) _______ _______ _______
11. ANALYTICAL BLOCK DIAGRAM WITH TRANSFER
FUNCTIONS AND ASSOCIATED CONSTANTS
A. EXCITER GAIN CONSTANTS _______ _______ _______
B. EXCITER TIME CONSTANTS (SEC) _______ _______ _______
C. GOVERNOR/TURBINE DATA:
1. MAXIMUM POWER OUTPUT OF TURBINE (MW) _______ _______ _______
2. STEADY-STATE DROOP _______ _______ _______
3. MAXIMUM VALVE OPENING VELOCITY (/SEC) _______ _______ _______
4. MAXIMUM VALVE CLOSING VELOCITY (/SEC) _______ _______ _______
5. ANALYTICAL BLOCK DIAGRAM WITH TRANSFER
FUNCTIONS AND ASSOCIATED CONSTANTS:
A. GOVERNOR TIME CONSTANTS (SEC) _______ _______ _______
B. TURBINE TIME CONSTANTS (SEC) _______ _______ _______
C. TURBINE GAIN CONSTANTS _______ _______ _______
EXHIBIT M
FACILITY WIRING DIAGRAM AND SPECIFICATIONS
TO BE ATTACHED PRIOR TO DELIVERY OF ANY CAPACITY
AND ENERGY FROM SELLER TO SIERRA
EXHIBIT N
FINAL INTERCONNECTION DRAWING
TO BE ATTACHED PRIOR TO DELIVERY OF ANY
CAPACITY AND ENERGY FROM SELLER TO SIERRA
Exhibit O
Page 1
Item Date Milestone Standard Documentation
---- ---- --------- -------- -------------
No. 1 3/1/91 Resource exploration Geophysical or geological Provide documentation by a
exploration data on the qualified professional of
geothermal resource the actual resource
exploration work completed
and the associated data.
No. 2 1/1/92 Receive UEPA permit Order from Public Service Provide notice of verbal
approval from the Commission of Nevada approval by the Public
Public Service granting the Project rights Service Commission of Nevada
Commission of Nevada for construction for UEPA permit, followed
with the written decisions
from the agenda hearing
where the approval was made
No. 3 2/1/92 Completion of testing Complete the drilling & Provide Sierra with the data
of initial production testing of the initial from the well test, which
well(s) to be used for production well(s), which test is performed by
the Project shall deliver hot water at qualified professionals,
not less than 796,000 pounds which indicates delivery of
per hour and a temperature hot water of quality and
of not less than 325 quantity as indicated
degrees F for a test period
of 48 continuous hours or
until stabilization occurs.
Stabilization shall be
considered met when the flow
rate and temperature at the
end of any 8-hour continuous
period shall not be
considerably less than the
first hour of the 8-hour
period.
No. 4 9/1/91 Issue purchase order Purchase order with vendor Provide Sierra with a copy
for the turbine indicating requisition of of purchase order from
generators turbine/generator sets vendor with a specified
delivery date
No. 5 2/1/92 Begin pouring of Complete preparation of Provide documentation by a
turbine/generator turbine/generator foundation qualified professional that
foundations and begin pouring of the foundation is prepared
concrete for mounting of and that concrete pouring
turbine/generator sets has begun
No. 6 6/1/92 Delivery of Receipt of turbine/generator Provide documentation that
turbine/generators to sets from vendor delivered the turbine/generator sets
the plant site of the to plant site have been delivered to plant
Project site
No. 7 8/15/92 Complete installation Complete mounting of Provide documentation from a
of turbine/generators turbine/generator sets on qualified professional that
foundation the turbine/generators have
been mounted and set on the
foundation
Exhibit O
Page 2
Item Date Milestone Standard Documentation
---- ---- --------- -------- -------------
No. 8 8/1/92 Completion of well Complete the drilling of all Provide Sierra with the data
drilling for all ▇▇▇▇▇ production and injection from the well tests, which
to be used for the ▇▇▇▇▇, which shall deliver tests are performed by
Project hot water of not less than qualified professionals,
3,184,000 pounds per hour which indicates the delivery
and a temperature of not of hot water of quality and
less than 325 degrees F, and quantity as indicated and
shall be capable of capability of injection of
injecting all fluids all production fluids from
produced by the production the Project
▇▇▇▇▇
No. 9 9/1/92 Commence the thirty Begin thirty day shakedown Provide notice to Sierra
day shakedown period period pursuant to Section 7 pursuant to Section 7 of the
as described in of the Agreement Agreement that the shakedown
Section 7 of the period has begun
Agreement
No. 10 11/1/92 Achieve a Commercial Perform 100-hour test pursuant Provide notice to Sierra
Operation Date pursuant to Section 7 of the pursuant to Section 7 of the
to Section 7 of the Agreement & establish a Agreement that the
Agreement Commercial Operation date Commercial Operation date
has been established
(1) Calculated as: 120% of the hot water number provided in Section 9(b)
divided by 4 (4 is the total number of ______ proposed).
(2) Calculated as: 120% of the hot water number provided in Section 9(b).
(3) These numbers shall correspond to the numbers provided in Section 9(b).
EXHIBIT P
SEMI-ANNUAL PROJECT REPORT
Monthly Data: Required for production and injection ▇▇▇▇▇.
Total production to plant (lbs/hr)_________________
Total plant output (kWh)_________________
Pressure at inlet________________________
Temperature at inlet_____________________
Daily data from Production well:
a) Flowing/pumping:
Steam_________________
Water_________________
Well head pressure_______________________
Well head temperature____________________
Operating time___________________________
b) Static:
Shut-in pressure or fluid levels___________________
Shut-in temperature______________________
Daily data from Injection well:
Temperature________________
Rate_______________________
Pressure___________________
Daily data from any observation well(s):
Downhole pressure at the production level_________________
Fluid Level________________
Following data record as it happens:
What and When Occurred Cost (Repair)
Plant outage ______________________ _____________
Unit outage ______________________ _____________
Equipment failures ______________________ _____________
Scale removal ______________________ _____________
Any fluid chemistry data from any well (s) (gas content, gas composition, liquid
composition)
Future Data
- Plans to drill any type of well _________________
- Plans for descaling _____________________________
- Plant modification and refurbishments ___________
- Any modification of plant _______________________
EXHIBIT Q
SAMPLE LIQUIDATED DAMAGES CALCULATIONS (12MW)
This example is for purposes of illustrating billing pursuant to the provisions
of Section 6 (b) utilizing the rate schedule contained in this Agreement only,
and does not supplement or amend the Terms of the Agreement to which it is
attached.
For the first three Contract Years:
Exhibit B values shall be used as part of the calculation for capacity
payment and the capacity rate used for billing purposes would be 100% of the
value specified in Exhibit D.
Beginning in the fourth Contract Year:
The previous three year Peak Period Capacity value average was 85%. The
capacity rate used for billing purposes for the fourth year would be 85% of the
value specified in Exhibit D.
Beginning in the fifth Contract Year:
The previous three year Peak Period Capacity value average is 79% of the
average Peak Period Capacity value specified in Exhibit B. The liquidated
damages amount paid to Sierra shall be $1,000,000 adjusted by the GNPD to the
current year. Each Peak Period Capacity value in Exhibit B would be revised to
the average Peak Period Capacity value for that billing period in the previous
three year period. Those numbers are shown as the new Exhibit B values in the
sample calculation table.
The new Exhibit B values shall be used as part of the calculation for capacity
payment and the capacity rate used for billing purposes for the fifth year would
be 100% of the value specified in Exhibit D.
Beginning in the sixth Contract Year:
The previous three year Peak Period Capacity value average was 91%. The
capacity rate used for billing purposes for the sixth year would be 91% of the
value specified in Exhibit D.
Beginning in the seventh Contract Year:
The previous three year Peak Period Capacity value average was 88%. The
capacity rate used for billing purposes for the seventh year would be 88% of the
value specified in Exhibit D.
SAMPLE LIQUIDATED DAMAGES CACULATIONS (12MW)
JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV DEC ANNUAL %
EXHIBIT B 13400 13350 13170 13050 12830 9950 9140 9140 10140 13110 13260 13460 12000 100
FIRST YEAR 11390 11348 11195 11093 10906 8458 7769 7769 8619 11144 11271 11441 10200 85
2ND YEAR 11390 11348 11195 11093 10906 8458 7769 7769 8619 11144 11271 11441 10200 85
3RD YEAR 11390 11348 11195 11093 10906 8458 7769 7769 8619 11144 11271 11441 10200 85
4TH YEAR 8978 8945 8824 8744 8596 6667 6124 6124 6794 8784 8884 9018 8040 67
NEW EXHIBIT 10586 10547 10404 10310 10136 7861 7221 7221 8011 10357 10475 10633 9480 100
5TH YEAR 8575 8543 8427 8351 8210 6367 5849 5849 6489 8389 8485 8613 7679 81
6TH YEAR 10480 10441 10300 10206 10034 7782 7148 7148 7930 10253 10371 10527 9385 99
7TH YEAR 9951 9914 9780 9691 9528 7389 6787 6787 7530 9735 9847 9995 8911 94
8TH YEAR 9951 9914 9780 9691 9528 7389 6787 6787 7530 9735 9847 9995 8911 ▇▇
▇▇▇ ▇ ▇▇ ▇▇▇ ▇▇▇▇▇ ▇▇▇▇▇▇▇▇▇▇ OF THE EXHIBIT 85
2ND 3 YR AVG 9480 PERCENTAGE OF THE REVISED EXHIBIT 79
3RD 3 YR AVG 8640 PERCENTAGE OF THE REVISED EXHIBIT 91
4TH 3 YR AVG 8368 PERCENTAGE OF THE REVISED EXHIBIT 88
5TH 3 YR AVG 8658 PERCENTAGE OF THE REVISED EXHIBIT 91