Long-Term Power Purchase 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  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. Page 1 1/11/91  (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. Page 2 1/11/91  (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 wells, geothermal fluid Page 3 1/11/91  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 Page 4 1/11/91  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 Page 5 1/11/91  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 Page 6 1/11/91  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 Page 7 1/11/91  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 Page 8 1/11/91  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 Page 9 1/11/91  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 Page 10 1/11/91  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 Page 11 1/11/91  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. Page 12 1/11/91  11. Guarantees. (a) Upon signature of this Agreement by Seller, Seller shall provide to Sierra an earnest 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. Page 13 1/11/91  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 billings or payments made by Sierra to Seller pursuant to this Section, Seller may request in writing from Sierra, within 30 days of such billings 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. Page 14 1/11/91  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 Page 15 1/11/91  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 Page 16 1/11/91  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. Page 17 1/11/91  (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 wells 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 wells 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 6100 Neil Road, Reno, NV 89511 P.O. Box 10100 Reno, NV 89520 Phone: (702) 689-4889 Telecopy: (702 ###-###-#### SELLER: Far West Capital, Inc. 921 Executive Park Drive Suite B Salt Lake City, UT 84117 Telephone: (801) 268-4444 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/ Gerald Canning By: /s/ Alan O. Melchior --------------------------- --------------------------- 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 6100 Neil Road, Reno, Nevada 14th Revised P.S.C.N. Sheet No. 2 Tariff No. Electric No. 2 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 Tariff No.1 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 -------------------------------------------------- 1st Quarter 2nd Quarter 3rd Quarter 4th 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 William L. Keepers President Advice No.: 304-E  EXHIBIT C PAGE 2 OF 3 SIERRA PACIFIC POWER COMPANY 6100 Neil Road, Reno, Nevada 14th Revised P.S.C.N. Sheet No. 3 Tariff No. Electric No. 2 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 William L. Keepers President Advice No.: 304-E  EXHIBIT C PAGE 3 OF 3 SIERRA PACIFIC POWER COMPANY 6100 Neil Road, Reno, Nevada 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 Tariff No. 1 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 Austin W. Stedham 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. 2, PSCN Sheet No. 4, Schedule 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Neil W. Plath 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: Austin W. Stedham 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: Austin W. Stedham 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 bill 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 bill 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 Austin W. Stedham 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 bill, 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 Austin W. Stedham 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 Austin W. Stedham 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 Austin W. Stedham 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 billings. Tax Adjustment Charge 2% of total bill 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 Austin W. Stedham 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 Austin W. Stedham 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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 Joe L. Gremban 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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 3 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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). - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 4 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 5 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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). - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 6 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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 - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 7 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 8 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  EXHIBIT L PAGES 9 OF 17 The following information will be remotely monitored with the telemetering equipment: - Watts 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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 9 OF 11 GREATER THAN ONE MEGAWATT ------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 10 OF 12 GREATER THAN ONE MEGAWATT -------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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. - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 11 OF 12 GREATER THAN ONE MEGAWATT -------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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 - -------------------------------------------------------------------------------- ENGINEERING & CONSTRUCTION STANDARD VOL | SECT | PAGE SMALL POWER PRODUCTION ----------------- [LOGO] AND COGENERATION FOR GENERATION 1 2.2 SHEET 12 OF 12 GREATER THAN ONE MEGAWATT -------------- DRAWING NO. SIERRA PACIFIC POWER CO. 2.2GNO2 - --------------------------------------------------------------------------------  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.) UNIT #1 UNIT #2 UNIT #3 (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: UNIT #1 UNIT #2 UNIT #3 (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: UNIT #1 UNIT #2 UNIT #3 (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 _______ _______ _______  UNIT #1 UNIT #2 UNIT #3 (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% MAXIMUM FIELD VOLTAGE, SE2 (PU) _______ _______ _______ 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 wells production and injection from the well tests, which to be used for the wells, 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 wells 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 wells. 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 ###-###-#### 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 94 1ST 3 YR AVG 10200 PERCENTAGE 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