QUESTIONS AND ANSWERS - 2016 ALL SOURCE RFP
Q1. Page 39 of the RFP lists the PACE delivery points that are of "primary interest" to PacifiCorp to take receipt of power. PacifiCorp has 345kV transmission facilities from Mona - Huntington - Pinto - Four Corners yet does not list Four Corners as a potential delivery point in the RFP. Please explain why Four Corners is not a delivery point of "primary interest" in the RFP.
A1. PacifiCorp does not have any
available import capability from Four Corners into its system.
Q2. In Attachment 17, Section 4, Performance Guarantee, page 1358, Table 1 Performance Guarantees: Barometric Pressure = 12.458 psia. This conflicts with Section 1.1, Section 2 (Table 2-1), Appendix R (Section 2.2) and elsewhere in the RFP that defines the site elevation to be 5,051 feet. 5,051 feet corresponds to a barometric pressure of 12.203 psia, according to Supplier's calculations. Can you confirm what is the correct basis for guaranteeing performance, 12.458 psia or 12.203 psia.
A2. The Currant Creek plant site elevation is 5,051 feet above sea level. The barometric pressure listed in Attachment 17, Section 4, is a reference to an alternate location and is incorrect for the Currant Creek site. The mean barometric pressure for the Currant Creek plant site is 12.2 psia.
In addition, please refer to Exhibit A, Appendix B, Approved Vendors List, which is referenced under the News section of the webpage and is included under the Documents section of this webpage.
Q3. There appears to be several places where the RFP notes that renewable resources are acceptable but the RFP also implies that no special consideration (e.g. incremental value) will be given to these resources. Please confirm.
A3. For the price and non-price screens as part of the evaluation process, PacifiCorp will not assign a particular score based solely on the fact a resource is or is not a renewable resource.
Q4. Is 2016 a firm deadline for commercial operation? Is 2017 acceptable?
A4. A resource must be online by June 1, 2016.
Q5. Our resource is geothermal. Although PacifiCorp theoretically could schedule and dispatch it, it could be impractical because of resource characteristics. Would this eliminate it from further consideration?
A5. No.
Q6. There is not enough information to comply with the IBC 2009 code. All factors must be reported as per the code. ASCE7-05 which IBC takes its criteria from calls out these factors. Without them we have to design to worst case which increases cost without justification. We need this information for the site environmental criteria. I couldn't find it in the specs.
A6. The Contractor is responsible for determining the Soil Conditions at the Site of Currant Creek 2 (the Soils report included in the Appendices is included for information only. The Site Design Conditions are included in Table 2-1. The Seismic and Wind Criteria are included in Articles 7.2.3 and 7.2.4. The Site location is described in Article 1.1 (approximately 80 miles south of Salt Lake City and 1 mile west of Mona, Utah). The required "factors" should be formulated from the data provided, and the Contractor developed Soils data.
Q7. Appendix B, Item 2.B refers to a form of commitment letter identified as Attachment 22. There is no such document in the RFP Document list. Please tell me where to find it.
A7. Please see Attachment 15, which has the Forms of Credit Commitment Letters. Attachment 22 was incorrectly referenced in Appendix B and we apologize for the confusion. Please see the Document page of this website of Attachment 15 as well as a link to Attachment 15 below.
Q8. Attachment 14 provides the credit methodology for the base load bid category. What is the credit methodology for Intermediate Load and Summer Peak bid categories?
A8. The credit methodology in Attachment 14 describes the potential credit exposure to PacifiCorp in the event the resource fails to come on-line when expected, and outlines the methodology for either asset-backed resources or non-asset backed resources. There is not a different methodology for Intermediate Load and Summer Peak bid categories. The amount of credit assurance to be provided is outlined in the credit matrices and is the difference between this potential credit exposure and the level of credit risk tolerance. If the question is with regard to the amount of credit assurance to be provided for the above-referenced categories, please see page five of Appendix B (on the page beginning with
Credit Matrices Notes) which outlines how to adjust the amount of credit assurances in the credit matrix for an Intermediate Load or Summer Peak bid category.
Q9. In reference to PacifiCorp's January 6, 2012 RFP, the Intent to Bid document requests audited financial statements. We would like to enter into a Confidentiality Agreement (CA) with PacifiCorp prior to providing that highly confidential information. Can you facilitate such an agreement?
A9. The form of the Confidentiality Agreement is attached under the Documents tab of this website.
Q10. You have delineated three machines that would be acceptable to PacifiCorp for the Project if supplied in an EPC environment utilizing the Currant Creek site. We would ask if PacifiCorp would consider the Siemens SGT5-8000H for utilization on the Currant Creek site in an EPC turnkey execution model.
A10. Air modeling (permitting) work has been prepared for the three different combustion turbines and configurations identified in the technical specification based on information provided by the equipment suppliers. At this time, PacifiCorp does not plan to include the Siemens H technology as a Currant Creek option for a 2016 resource under this RFP.
Q11. There appears to be a discrepency between the number of MWs some EPC's are looking for versus the IRP requirements. Can you shed some light on how some came up with 620-665 MWs when the PacifiCorp IRP clearly stipulates 597 MW? Also, if the requirement is 665 MWs why is the Siemens H technology on the approved bidders list when it will be on the ground before MHI GAC?
A11. The original 597 MW capacity value was based on a proxy design that was prepared by for the Company's supply side resource table used in the IRP process. It was based on a 2x1 configuration using the General Electric 7FA.05 combustion turbine with dry-cooling based at Currant Creek. The 597 MW capacity level was the result of a performance study completed in October, 2009. At that time the design was based on approximately 85 MW of duct firing which was similar to the level of duct firing being considered for the Lake Side 2 plant. It should be noted that duct firing levels are not fixed by any particular design and can be changed.
In order to enhance the competitiveness of the RFP process for an EPC option at Currant Creek it was decided to allow different advanced combustion turbine options available from major suppliers. Since the October, 2009 study was performed, the capacities of both the General Electric and Siemens "F" class combustion turbines have increased. In addition, it was decided to allow the Mitsubishi GAC combustion turbine based on its extensive testing and the engineering review performed by a major insurance broker. Furthermore, Mitsubishi offers a fast start configuration for its GAC combustion turbine which results in reduced startup emissions. The fast start capability for reduced startup emissions is a criteria that is expected from all three combustion turbine configurations.
In order to level the playing field for the "F" class options with the larger GAC machine, sizing criteria was adopted which included modifying the level of duct firing and placing a limit on the air cooled condenser back pressure. Similar to the existing Currant Creek 1 plant, which has approximately 100 MWs of duct firing, it was decided to include up to an additional 100 MWs of duct firing for the "F" class machines at 20 degrees Fahrenheit and above and to limit air cooled condenser back pressures to 7.5 inches of mercury at 95 degrees Fahrenheit, with an air cooled condenser no larger than 54 cells for all cases. As a consequence of these sizing criteria, expected outputs ranged from 620 to 665 megawatts for the three configurations at 51 degrees Fahrenheit. The air permitting process for the three configurations under consideration has been underway since May 2011.
EPC bidders may submit a configuration with a lower capacity than the expected 620-665 megawatts at 51 degrees Fahrenheit.
Q12. What is the response time to provide answers to the questions being submitted?
A12. PacifiCorp has a target turnaround time of approximately 7 days to provide responses to questions. However, the turnaround time could depend on the complexity of the questions or whether or not PacifiCorp has documents requested by the bidders readily available.
Q13. During the Transmission Workshop for the 2016 All Source RFP, a PacifiCorp representative mentioned that the purpose of the RFP was to meet the needs of the Salt Lake City load bubble. Our analysis of the 2016 WECC High Summer and High Winter load flow models indicate that the electricity flow is East to West across Path C and Pavant/IPP-Gonder suggesting that additional generation west of those paths would be a better location since that would avoid flow constraints across those paths. Please explain if PacifiCorp has a different view.
A13. WECC base cases are developed for member system use and are intended to represent generalized flow conditions under varying load and resource scenarios (for example, a summer case might represent high hydro conditions in the NW along with high loads in California). As such, flows in these cases do not represent contractual obligations across a particular path and are, instead, simply a reflection of a particular load and resource combination selected for a study. On a contractual, scheduling capability basis, all the capacity west of the paths referenced is already committed to firm use.
Q14. Why does delivery across Path C from Populus require use of existing firm network allocation rights across Path C when the High Summer and High Winter load flow models indicate that electricity flow is East to West across Path C.
A14. The WECC uses a Contract Path methodology to regulate use of the transmission system. Therefore, in order to schedule power across an intertie or other scheduled path, the party making the schedule has to have the right to use a contiguous schedule path from source to sink. The available transmission capacity (ATC) across the many interties and scheduled paths in the WECC can be found on each transmission provider's OASIS site. As noted in the previous response, WECC cases are created to represent flows for a particular load and resource combination that was selected for study in the annual WECC study program and for the use of member systems. While these cases are used to study the transfer capability of various lines and paths, they provide no insight into the ownership or use of these lines and paths. Exising firm scheduling capability south bound is already committed, therefore the comment that existing allocated firm scheduling rights will be required to move incremental energy south across this path.
Q15. Excluding the cost of System upgrades and the times of completion of those upgrades, does PacifiCorp has a preference between locating the new resource in either the east or the west load bubble and why? What transmission related evaluation criteria other than integration costs will be applied for resources with Points of Delivery in the West System versus the East System?
A15. The east system has the highest growth rates and requires incremental resources. That said, we have no strong preferences for resources either east or west. New resources would be integrated into either system to serve load growth and potentially displace existing resources at higher cost. PacifiCorp presently has contractual rights through a third-party transmission provider from the East System to the West System. These rights are used to deliver existing generation resources in Wyoming, specifically Bridger generation, to loads in the West System. The terms and conditions associated with these contractual rights provide limited operational flexibility. PacifiCorp is required to purchase eastbound transmission capacity through the Idaho Power system.
Q16. Please explain how PacifiCorp will equitably address and compare transmission system integration costs and cost risks for a new resource directly interconnected with PacifiCorp versus such costs borne by a new resource interconnecting to a non-PacifiCorp system with firm transportation to PacifiCorp's system.
A16. As discussed in the Transmission Workshop, any resource located off system with firm transmission delivery rights to the PacifiCorp system will be treated on the same basis as on-system resource bids, within the delivery limitations identified in Attachment 20.
Q17. In Attachment 17, Section 2.4.1, page 44, the RFP states that the expected emission rates, equipment sizes .... are indicated on the Tables included in Appendix Q. It appears the reference to Appendix Q is incorrect, and should be Appendix U. Please confirm.
A17. The expected emission rates are located in Appendix U.
Q18. In Attachment 17, Section 5.2.8, page 155, the RFP states to size high pressure and intermediate pressure steam drums to provide a minimum of three (3) minutes of storage with no incoming water at the fired steaming rates. Using a HP drum retention time of 3 minutes may preclude the ability to fast start. Can the owner accept a 2 minute HP drum retention time?
A18. Based on past projects and vendor supplied data it is PacifiCorp's decision that, although the 3 minute retention time is preferable, a HP drum retention time of 2 minutes and a IP Drum retention time of 3 minutes is acceptable if this is required to provide the "Fast Start" capability.
Q19. The water analysis provided in the RFP is missing some important items. Please provide the following analysis: Silica, Potassium, Boron, Iron, Manganese, and SDI.
A19. Potassium is 0.78 mg/l and Manganese is 3.7 ug/l. The other requested constitutents are not available. Water analysis will be performed but is expected to take 2-3 weeks to complete.
The available Silt Density Index information is as follows: The SDI for Mona Well #1 is 3.4
Q20. It appears that Section 16.3 of the EPC Agreement (Attachment 4) is incorrect. Please provide the corrected language for "Liquidated Damages for Net Capacity and Net Heat Rate".
A20. The appropriate language for Section 16.3 of the EPA Agreement (Attachment 4) is provided below:
16.3 Liquidated Damages for Net Capacity and Net Heat Rate
To the extent the actual measured net capacity is less than 95% of the Guaranteed Net Capacity or the Guaranteed Net Incremental Net Capacity, Contractor shall take all corrective action required to achieve the requireed performance level. In the event contractor fails to achieve the Guaranteed Net Capacity or the Guaranteed Incremental Net Capacity (but has achieved at least 105% of the Guaranteed Net Capacity or the Guaranteed Incremental Net Capacity, as applicable), Contractor shall pay Performance Liquidated Damages calculated per the formulas and rates set forth in Exhibit A, Appendix M. To the extent that the actual Guaranteed Net Heat Rate or the Guaranteed Incremental Net Heat Rate, Contractor shall take all corrective action required to achieve the required performance level. In the event that the Contractor exceeds the Guaranteed Net Heat Rate or the Guaranteed Incremental Net Heat Rate (but has not exceeded the Guaranteed Net Heat Rate or the Guaranteed Incremental Net Heat Rate, is applicable by more than 105%), Contractor shall pay Performance Liquidated Damages calculated per the formulas set forth in Exhibit A, Appendix M. Provided that Substantial Completion is achieved, Contractor shall be granted a period of 180 days after the Substantial Completion Date to allow remedial actions to be taken to achieve the Guaranteed Net Capacity, the Guaranteed Incremental Net Capacity, the Guaranteed Net Heat Rate or the Guaranteed Incremental Net Heat Rate, prior to Contractor's obligation to pay Performance Liquidated Damages in accordance with Section 14.7. To the extent that Contractor has achieved Substantial Completion and met the required performance threshold for each of the Guaranteed Net Capacity, the Guaranteed Incremental Net Capacity, the Guaranteed Net Heat Rate and the Guaranteed Incremental Net Heat Rate, but not achieved one hundred percent (100%) of the guaranteed performance levels, contractor shall compensate Owner (or "buy-down") for teh unachieved performance pursuant to Exhibit A, Appendix M. Any such buy-down amounts shall be " Performance Liquidated Damages." The following liquidated damage rates shall apply for deficient performance: (a) Guaranteed Net Capacity ("GNCLD" as identified in Exhibit A, Appendix M) is One Thousand Six Hundred Dollars per kilowatt ($1,600/kW); (b) Guaranteed Incremental Net Capacity ("GINCLD" as identified in Exhibit A, Appendix M) is Seven Hundred and Fifty Dollars per kilowatt ($750/kW); (c) Guaranteed Net Heat Rate ("GNHRLD" as identified in Exhibit A, Appendix M) is Three Hundred and Fifty Thousand Dollars per British thermal unit per kilowatt-hour ($350,000)/BTU/KWh measured on a higher heating value basis; and (d) Guaranteed Incremental Net Heat Rate ("GINHRLD") as identified in Exhibit A, Appendix M) is Forty Thousand Dollars per British thermal unit per kilowatt-hour ($40,000) BTU/KWh measured on a higher heating value basis.
Q21. What is the expected operating profile for the facility (i.e. Currant Creek)? i.e. when it is cycled up daily, will it be ramped up to 100% baseload, or will it primarily be held between 50-80% load?
A21. It will primarily be held between 50-80% load factors.
Q22. I just wanted to confirm - Are you looking for PV Solar Generation in the 2016 All Source RFP?
A22. No resource type is precluded from this RFP provided that it is dispatchable or can be provided on a firm (uninterruptible) basis.
Q23. RFP Attachment 17, Section 4.2 states "PDS Model review will be the primary mechanism used for review of physical plant features". Please advise if Smart Plant 3D Model is acceptable?
A23. Smart Plant 3D is acceptable.
Q24. For bidders selecting Resource Alternative 3 (EPC - Currant Creek 2), Appendix U, titled Owner Prepared Data for Air Permit, includes emissions values for each OEM. The following questions are related to this document:
a. Please provide the status of the air permit and confirm whether the values in Appendix U are the basis of the air permit application;
b. Which values in Appendix U will the Owner request to be guaranteed by the selected EPC bidder?
c. Steady state emissions at each stack are listed in ppm and lb/hr. Please define the term "steady state" for purposes of the air permit requirements (i.e. above a emissions compliance load and below maximum ramp rate of ____ MW, etc.
d. Please confirm that the steady state emissions requirements would not apply during "transient" operation (i.e. outside the definition of "steady state" operation).
e. Please clarify the ramp rate required for each combustion turbine during normal operations. If the plant is to operated using AGC (automatic generator control), please clarify the ramp rate to be used in AGC.
f. Startup and shutdown emissions at each stack are listed in lb/event, and durations of startup events. This page notes that these values are at 59F. How will these requirements be revised at other ambient conditions?
g. If bids are provided that differ from the startup times listed in Appendix U, will they be accepted?
A24.
a. Appendix U has the information on equipment sizing and emissions limits for the draft air permit. The air permit application will be submitted to the Utah Division of Air Quality during the first half of April, 2012. The permit application includes emissions information consistent with Appendix U with the following exceptions:
(i) A 750 kW design basis is used for the emergency generator;
(ii) Operation of the emergency generator and fire pump will be limited to 100 hours per year for routine testing and maintenance consistent with the requirements of 40 CFR Part 63 subpart ZZZZ.
(iii) Operation of the auxiliary boiler will be limited to 6,000 hours per year;
It should be noted that the final air permit for Currant Creek Block 2 may include emissions and operations limitations different from those proposed in the permit application.
b. The EPC will need to meet the requirements of the air permit. Based on recently issued permits for power plants by the Utah Division of Air Quality, PacifiCorp anticipates emissions limitations for the stacks and auxiliary boiler. The bidder therefore would need to meet the emissions limits in the permit. Both the emergency generator and the fire pump should be in compliance with the applicable 40 CFR Part 60 subpart III requirements. Again, it should be noted the final air permit for Currant Creek Block 2 may include emissions rates different form those proposed in the permit application.
c. The "steady state" emissions provided in Appendix U reflect maximum emission rates between minimum emissions compliance load and 100% combined cycle load across the ambient temperature range including during the allowable ramping in between those two loads. Startup and shutdown emissions at 59F were used in the air modeling to support the permit application.
d. The steady state emissions limit would not be applicable outside the definition of "steady state" operation (i.e. startup/shutdown).
e. There are no required ramp rates for each combustion turbine specified in Appendix U. Bidders are expected to specify the normal ramp, fast ramp rate, and AGC capability for the overall plant in Exhibit A - Appendix K (Exhibit 1 to Appendix C (page 2)).
f. As startup and shutdown emissions can vary with ambient temperature, 59F is chosen as reference temperature at which startup and shutdown emissions should meet the limits provided in Appendix U. Startup and shutdown emissions at 59F were used in the air modeling to support the permit application. Bidders should identify if startup or shutdown emissions are greater than these values in their proposals at other ambient conditions.
g. A fast start configuration is being proposed for Currant Creek Block 2. The final air permit for Block 2 may include startup limitations that teh plant would be required to comply with. No limitations on startup times are being currently proposed in the permit application.
Q25. Will bids featuring "H" technology be considered for Resource Alternative 3 (EPC - Currant Creek 2)?
A25. Air modeling (permitting) work has been prepared for the three different combustion turbines and configurations identified in teh technical specification based on information provided by the equipment suppliers. At this time, PacifiCorp has not included the Siemens H technology as an option for Currant Creek 2 for a 2016 resource under this RFP.
Q26. RFP, Page 26, Section B "Pre-Bid Conference" Section states, "After the final approval of the RFP, Merrimack Energy Group, Inc. will be responsible to maintain and post all materials on a website established by the IE. The Company will be responsible to maintain and post all materials on the Company's website at www.pacificorp.com". However, Attachment 4 - EPC Agreement" and "Attachment 17" is showing on the PacifiCorp website only. It is not available on the Merrimack Energy site with all the other attachments. Please add "Attachment 4" and "Attachment 17" to the Merrimack Energy site.
A26. Please refer to the PacifiCorp website for these documents only due to the large size of the documents.
Q27. The following questions pertain to Appendix M of Attachment 17:
a. Could PacifiCorp please provide the measured noise level and specific 400-foot fence line measurement locations during which Currant Creek 1 (CC1) was operating both at steady-state conditions with 100% duct-firing , and during startup, shutdown and bypass conditions? This critical information is required so that in developing the acoustical model of the Project, cumulative noise levels for CC1 and CC2 at specific 400-foot fence line locations can be compared to the 70 dBA Guaranteed Noise Emission requirement as stated in Section 4.3.1.
b. Additionally, can PacifiCorp please provide the measured noise level and specific property boundary measurement during which CC1 was operating during normal conditions? This critical information is required so that in developing the acoustical model of the Project, cumulative noise levels for CC1 and CC2 at specific boundary locations can be compared to the 85 dBA Guaranteed Noise emission requirement stated in Section 4.3.1.
c. Additionally, can PacifiCorp please provide the measured LDN noise level and C-weighted noise level at the nearest residence during normal operation of CC1? This critical information is required so that in developing the acoustical model of the Project, cumulative noise levels for CC1 and CC2 at the nearest residence can be compared to the 55 LDN and 70 dBC Guaranteed Noise Emission requirement stated in Section 4.3.1.
d. If available, please provide noise test procedures to be used at the nearest residence to demonstrate compliance to teh 55 LDN and 70 dBC Guaranteed Noise Emission requirements stated in Section 4.3.1?
A27. Answers for all sub-question are provided below:
The final noise study after the completion of the Currant Creek 1 unit was issued to the prospective EPC contractors on the flash drive that was sent via FEDEX on February 23, 2012.
Q28. Appendix B (Credit Matrix): "Please note that should a Bidder be an existing counterparty with PacifiCorp, PacifiCorp reserves the right to protect itself from counterparty credit concentration risk and require credit assurance in addition to those outlined in the Credit Matrix"
a. What type of additional credit assurances would be required?
b. Appendix B (Credit Matrix): We do not see Attachments 21 and 22 among the documents on the websites. Would you be able to send them to us?
c. Could you send us Appendix G, and Attachment 4 and 6, since we seem not to be able to find them.
A28. The following are the responses to the above Questions
a. The type of credit assurances would be in the form of an acceptable letter of credit, cash, or another form acceptable to PacifiCorp.
b. There are no Attachments 21 and 22. These were incorrectly referenced in the RFP. Attachment 21 was renamed Attachment 14, and Attachment 22 was renamed Attachment 15. Please refer to Attachments 14 and 15.
c. Appendix G does not apply. Attachment 4 is included on this webpage under the heading "Documents". Attachment 6 is included on PacifiCorp's website for the 2016 All Source RFP.
Q29. Depending on which document you are reading, the proposal due date is either May 24, 2012 or May 9, 2012. Please clarify the schedule.
A29. The due date for proposals is May 9, 2012 as described in the final RFP posted on January 6, 2012. The due date of May 24, 2012 is the date included in the Draft RFP issued in October 2011. Please submit all proposal consistent with the May 9, 2012 established due date.
Q30. Could PacifiCorp provide the Appendices and Attachments that bidders are required to provide with their proposals in word format so that we can complete the forms to attach to our proposal.
A30. Attached are the following PacifiCorp Resource RFP 2016 documents that have been requested. These documents are included under the Documents Tab of this website as well as on PacifiCorp's website:
Appendix C-1 - PPA and TSA Information Request
Exhibit 1 to Appendix C-1
Appendix D - Fuel Supply Form
Appendix F - Bidder Site Control Form
Attachment 19 - Term Sheet
Form 2 - Permitting and Construction Milestones
Appendix C-2 - EPC Information Request
Appendix C-3 - Existing Asset Purchase Information Request
Exhibit 1 to Appendix C-2
Exhibit 1 to Appendix C-3
Q31. Please confirm whether the definition of "emission compliance load" in Note 1 of Appendix U is (a) the CTG load at which the emissions limits listed in Appendix U for steady state operation are achievable at the stack or (b) the load at which the CTG OEM defines as meeting the CTG outlet emissions (e.g. is "emissions compliance" measured at the HRSG stack outlet or the CTG exhaust?)
A31. The startup duration indicated in note 1 in appendix U is defined from gas turbine ignition to minimum emission compliance load. The emission compliance load here refers to the CTG load at which HRSG stack emissions meet the steady state emissions limit.
Q32. Attachment 17, Table 2-1 (Site Design Conditions) lists the historical gas pressure into the Currant Creek site between 887-1230 psig. However, Appendix M, Table 1 lists the fuel gas guarantee based upon a minimum 525 psig fuel delivery pressure to the site. Please confirm whether (minimum ) 650 psig will be available at the interconnection point with the existing Currant Creek 1 site. If not, please provide the range of available fuel gas pressures at the interconnection point.
A32. There is no pressure regulation provided at the Questar Pipeline gas metering yard at the Currant Creek Plant. Historical gas delivery pressures are as stated. The bidder is responsible for providing the necessary gas pressure regulation at Currant Creek to match the requirements of the proposed equipment. Based on historical gas pressure deliveries, it is expected that a minimum gas pressure of 650 psig will be available but is not guaranteed. A pressure guarantee is being pursued subject to FERC approval for gas pressures along QPC ML 104; based on the estimated pressure drop for gas deliveries through JTL 113 at that pressure guarantee, the expected gas pressure delivered at the Currant Creek Plant would be 615 psig.
Q33. Attachment 17, EPC Specifications, Section 1.2.3 - Terminal Points refers to conceptual site arrangement drawings included in Appendix C. This drawing should show the locations of the terminal connections: electric transmission, natural gas, water supply and fire water terminal points. We cannot find these terminal points in the drawings included in Appendix C. Might the drawings with this information be missing. If so, could you please provide such drawings.
A33. The terminal points are identified on drawing numbers 173604-2STA-G1001 (page 417), 173604-2STA-G1101 (page 419) and 173604-2STA-G1201 (page 421) of the technical specifications (Appendix C of Attachment 17) The terminal point index is located on the bottom right side of each drawing.
Q34. Does PacifiCorp intend to provide form of the Exhibits to the Agreements on the website in Word format?
A34. There are no Exhibits currently prepared for the PPA or the TSA as it will depend on the project and those exhibits will be developed as part of the negotiations. The APSA and EPC Exhibits are attached in PDF form only. Bidders can print them and mark them up accordingly.
Q35. It is unclear to bidder whether PacifiCorp intends the submission of a bid proposal to be legally binding. There appears to be conflicting language between the RFP instruction and the Tolling Service Agreement. Please clarify whether PacifiCorp's intention is that submission of a proposal is considered legally binding or if the cited RFP language is meant only to ensure that bidders do not change pricing or other material terms after submitting their proposal. Page 1 of the Tolling Service Agreement states that the TSA is not binding on either party until each party receives all required management and board approvals, including final legal and credit approvals.
A35. Appendix E states as follows;
The pricing and material terms of the proposal submitted must be binding.
The undersigned Bidder executes and submits this form with each Proposal it submits in PacifiCorp's RFP, and hereby certifies in each instance that all of the statements and representations made by it in its proposal are true to the best of the Bidder's knowledge, and agrees to be bound by the representations, terms, and conditions contained in the RFP. The Bidder accepts the contract attached to the RFP and indicated herein as applicable to its proposal, except as specifically noted in writing by Bidder. This proposal is firm and will remain in effect until the later of June 15, 2013 unless earlier released in writing by the Company or if the Bidder's proposal does not make the short list.
The TSA will not be binding on either party until each party receives all required management and board approvals, including final legal and credit approvals.
Q36. Reference to EPC Contract Exhibits F-1, F-2, and M. Have the referenced exhibits been distributed?
A36. There is no specific Exhibit F-1 and Exhibit F-2 as part of the RFP EPC documents. Bidders shall provide a Level I and Level II project schedules as Exhibits F-1 and F-2 respectively. The form of these schedules will also be used during execution of the project. For the purpose of a definition, Exhibit F-1 shall consist of a level I schedule which shall include major contract milestones, project milestones, mechanical and electrical design activities, procurement, construction, startup and commissioning activities. The Level I schedule will include start and end dates and durations. The Level I schedule would be expected to consist of 60 to 100 activities.
Exhibit F-2 will consist of a Level II schedule and would be a detailed schedule of project activities and would be expected to consist of 500 - 800 activities. As with the Level I schedule, the Level II schedule will include start and end dates and durations.
Q37. Where can I find Exhibit M - Form of Parent Guarantee for the EPC Contract?
A37. The text of what was intended to be Exhibit M can be found on pages 105-113 of Attachment 4 under the heading "Guaranty". A separate Exhibit M will be prepared as part of a final executable contract.
Q38. Please confirm that a bidder of an APSA (resource alternative 4) should base its net plant guarantees on the basis of 95F, 20% RH and site elevation at bidder's site.
A38. The 95F/20% RH is the 1% design day (i.e. the dry bulb temperature will not exceed 95F more than 1% of the time over an extended period of weather monitoring, on the order of 20+ years) for generation resources along the Wasatch Front. The 95F/20% RH shall be used as the reference point for performance testing for net plant guarantees.
For those bidders proposing new generation resources at sites which are not in or near the Wasatch Front that have materially different weather conditions, Bidder may propose an alternate 1% design basis of ambient dry bulb temperature and relative humidity for the purposes of net plant guarantees. Bidder shall provide the source and duration of weather information used to determine the alternate temperature/relative humidity guarantee basis.
Q39. Attachment 17, Section 9 Instrumentation and Controls, subsection 9.3 Distributed Control System has the requirement that the DCS shall be designed to be capable of complying with NERC CIPs requirements. There is no such statement in the sections applicable to the GT and ST control systems. Please confirm that only the DCS need be capable of NERC CIPs requirements and not the GT and/or ST control system need to have this capability.
A39. All portions of the Work to which the North American Electric Reliability Corporation Critical Infrastructure Protection Standards (NERC-CIPS) apply shall conform to the applicable portions of NERC-CIPS (see sections 1.4 and 4.1) and Exhibit A, Appendix W - NERC-CIP Work Scope, except where specified otherwise (See Exhibit W, NERC-CIPS Scope of Work, Item 3, last sentence).
Equipment which may meet the criteria for Critical Cyber Assets include, but are not limited to, the plant digital control system, combustion turbine-generator controls, steam turbine-generator controls, programmable logic controllers, remote terminal units, supervisory control and data acquisition/historian system, condition monitoring systems, performance monitoring systems and protective relay devices.
Q40. Attachment 17. Section Switchyard and Transmission Line to Mona Substation, Page 8-16 states that "the Contractor shall provide an RTU (remote terminal unit) in the Currant Creek 2 switchyard control building." In the same attachment, Page 9-11, states that an RTU to implement Dispatch Automatic Generation Control (AGC) will be furnished and installed in the switchyard control building by others. Are these different RTU's.
A40. Language in Attachment 17, Exhibit A, Section 8.3 and Section 9.7 are replaced as described below under Large Generator Interconnect Agreement. Attention is directed to Attachment 17, Exhibit A, Appendix L, Exhibit 1 to Appendix B to LGIA (Original Sheet No. 127 through 137) as added. Other sections of the LGIA may also apply. (See Documents Tab for a copy of the Currant Creek LGIA).
Q41. Attachment 17. Instrumentation and Control Scope, Page 1-14 requires "Fully Integrate Currant Creek 2 Control Room equipment into existing Block 1 Central Control Room utilizing equipment and programs similar to those used on Block 1." We understand that "fully integrated" means consistent graphics criteria so operators mistakes are avoided. Block 1 and Block 2 will have separate networks, with dedicated operator stations for each block. Only common data for common systems will be exchanged. e.g. through an Ovation multinetwork connection. Please clarify what is expected.
A41. "Block 2 DCS plant control consoles, operator workstations and processor cabinets shall be installed in the existing Block 1 Control Room and existing Block 1 dcs Room (adjacent to the Block 1 Control Room). To the extent practical and wherever applicable, Block 2 DCS hardware and software (control logic, operator interface graphics, etc.) shall be similar to that for Block 1, so that from the perspective of control room operators, controls for Blocks 1 and 2 have a similar "look and feel", thereby facilitating cross-training between Blocsk 1 and 2 and minimizing likelihood of confusion and operator error due to unnecessary differences. There is no intent for the Block 1 and Block 2 DCS systems to communicate with each other or share data other than data for common systems."
Q42. Please identify and list the changes to the Large Generator Interconnection Agreement identified in the response to Question 40.
A. The following changes apply to the Large Generator Interconnection Agreement:
Delete the following sections in Attachment 17, Exhibit A:
1. Appendix L, (Acrobat pages 986 to 1338) Standard Large Generator Interconnection Agreement (LGIA).
2. Section 8.1.2.1, Utility System Interface, next to last paragraph which states: "Contractor shall include all technical and operational requirements within the plant to design to meet the requirements of the LGIA and associated documents included in Appendix H."
3. Section 8.3 - Switchyard and Transmission Line to Mona Substation, RTU Communications Interface which states:
"Contractor shall provide an RTU (remote terminal unit) located in the Currant Creek 2 switchyard control building. Fiber connections shall be made directly to the RTU from the Currant Creek 2 DCS. Points not available in the DCS shall be hardwired directly to RTU. Contractor shall provide all facilities required for RTU communications on the power plant side, including but not limited to, duct bank, wiring, programming, and remote input/output interface equipment."
4. Section 8.3 - Switchyard and Transmission Line to Mona Substation. Fence Interface which states: "Contractor shall provide all fencing and gates to the switchyard. Fencing shall be installed in compliance with "PacifiCorp Standard 6B.5 Fence Application and Construction" dated September 2007" as provided in Appendix L".
5. Section 9.7 - Remote Terminal Unit (RTU) Dispatch which states: "An RTU to implement Dispatch Automatic Generation Control (AGC) will be furnished and installed in the switchyard control building by others. The Contractor will provide a fiber optic connection from the switchyard RTU located in the switchyard control building to the plant DCS. Provide all facilities required for RTU communications between the power plant and Switchyard control building. Any I/O points required at RTU but not available in the DCS shall be hardwired to the RTU. Facilities shall include but not be limited to, ductbank, fiber, wiring, programming, and interface equipment. The Contractor shall provide all required Fiber Patch Panels at the substation and control room and/or other location to allow for the complete termination of all fibers into and out of each location. The Contractor shall work with the Owner Dispatch Center and personnel and to test and commission the DCS to Dispatch link for control, monitoring and alarming functions as specified in Section 8."
In Attachment 17, Exhibit A, replace with:
1. Appendix L with the attached "Standard Large Generator Interconnection Agreement (LGIA) between PacifiCorp, on Behalf of its Transmission Function and PacifiCorp, on Behalf of its PacifiCorp Energy Business Division for Currant Creek II Generating Facility."
2. Section 8.1.2.1, Utility System Interface, new last paragraph which shall read: "Contractor shall include all technical and operational requirements within the plant to design to meet the requirements of the LGIA and associated documents included in Appendix L."
3. Section 8.3 - Switchyard and Transmission Line to Mona Substation, Communications Interface which shall read: "Contractor shall provide and install communications interfaces in the Currant Creek 2 switchyard control building as required to meet the Interconnection Customer obligations specified in Exhibit A, Appendix L - Standard Large Generator Interconnection Agreement (LGIA) between PacifiCorp, on behalf of its Transmission function and PacifiCorp, on behalf of its PacifiCorp Energy Business Division for Currant Creek II Generating Facility. Fiber connections shall be made directly to the RTU from the Currant Creek 2 DCS. Points not available in the DCS shall be hardwired directly to the interface. Contractor shall provide all facilities required for the communications interface on the power plant side, including but not limited to, duct bank, wiring programming, and remote input/output interface equipment."
4. Section 8.3 - Switchyard and Transmission Line to Mona Substation, Fence Interface which shall read: "Contractor shall provide all fencing and gates for the switchyard. Fencing shall be installed in compliance with "PacifiCorp Standard 6B.5-Fence Application and Construction" dated September 2007 as provided in Appendix F."
5. Section 9.7 - Remote Terminal Unit (RTU) Dispatch which shall read: "An RTU to provide communications and implement Dispatch Automatic Generation Control (AGC) will be furnished and installed by others in the switchyard control building in accordance with Exhibit A, Appendix L. Contractor shall provide space and equipment racks for installation of the RTU. The Contractor will provide a fiber optic connections from the switchyard RTU located in the switchyard control building to the plant DCS. Provide all facilities required for RTU communications between the power plant and Switchyard control building. Any I/O points required at RTU but not available in the DCS shall be hardwired to the RTU. Facilities shall include but not be limited to, ductbank, fiber, wiring, programming and interface equipment. The Contractor shall provide all required fiber patch panels at the substation and control room and/or other location to allow for the complete termination of all fibers into and out of each location. The Contractor shall work with the Owner Dispatch Center and personnel to test and commission the DCS to Dispatch link for control, monitoring and alarming functions as specified in Section 8."
Q43. There is much confusion in the RFP regarding Form 2. Table 4 states that all Bidders must submit Form 2 but Chart 1 does not indicate otherwise. Page 25 of the RFP at the top states "Forms 1 and 2 should be completed, if applicable". In the middle of the Flexibility paragraph, it states "to the extend Bidders want to propose in-service date deferral or acceleration options, Bidders should provide a complete description of their proposed deferral or acceleration options, Bidders should provide a complete description of their proposed deferral or acceleration option as an Attachment to Form 2. Be specific. When is Form 2 applicable and when is it not applicable. Can I submit a proposal under Resource Alternative 1 and 2 and not submit Form 2.
A43. Yes, you can submit a proposal under Resource Alternative 1 and or 2 without a Form 2. Form 2 is only applicable in the event a bidder elects to provide a proposal which includes a deferral or acceleration option.
Q44. Will you please provide an electrical one-line for the Currant Creek substation
A44. A conceptual one-line diagram for the Currant Creek switchyard is not available. The Contractor is responsible for the design of the Currant Creek switchyard. A one-line diagram of Mona Substation is not available at this time. Work in the Mona Substation consists of connecting slack lines from Contractor installed dead-end structure and existing dead-end structure outside the substation to dead-end structures inside the substation as shown in the Technical Specification. This work will be performed in coordination with PacifiCorp. If a one-line diagram is needed to complete the work the one-line diagram will be provided during detailed design.
Q45. Will the electric transmission service at Currant Creek transition to 500 kV?
A45. No. The Currant Creek interconnection voltage at the point of interconnection is 345 kV.
Q46. What is the plan for that transition from 345 kV? Who bears the costs if such a transition were to occur?
A46. The Contractor shall provide the design, equipment, procurement and construction to transform from the respective generator voltage to the transmission voltage of 345 kV as part of the work. Contractor bears all costs of constructing the Interconnection Customer's Interconnection Facilities described in the revised Attachment 17, Appendix L, Standard Large Generator Interconnection Agreement. Those costs include the costs of transforming from the respective generator potentials to the transmission system potential of 345 kV.
Q47. Can you please provide a breakdown of the costs of an electric interconnection at the Currrant Creek site?
A47. PacifiCorp Energy will pay the direct assigned costs of the Interconnection Agreement as shown in the revised Appendix L, Standard Large Generator Interconnection Agreement. Contractor shall pay all costs of constructing the Interconnection Customers Interconnection Facilities and any other construction obligations of the Owner under the Standard Large Generator Interconnection Agreement. Cost breakdowns shown in the revised Appendix L, Standard Large Generator Interconnection Agreement are the only cost breakdowns available at this time.
Q48. There does not appear to be a cell in Form 1 for contract Heat Rate (Btu/KWh) when the selected resource alternative is either a Tolling Service Agreement or a Power Purchase Agreement. Should not Row 45 contain a place for bidder to include Contract Heat Rate?
A48. If the Bidder procures the fuel (Field ID 16), Field ID 45 will be applicable for the Bidder to fill in. If the choice is for PacifiCorp to procure the fuel, PacifiCorp will make the decision based on actual heat rate rather than "Contract" heat rate.
Q49. Please provide the range of fuel gas temperatures at Currant Creek 1 terminal point to size the necessary heating for turbine requirements.
A49. Based on the average daily gas temperatures at Currant Creek for the period of 1/1/10 through 4/22/12, the range of gas temperatures are as follows:
Average - 57.4 degrees F
Maximum - 72.0 degrees F
Minimum - 43.2 degrees F
Standard Deviation - 7.8 degrees F
Q50. Regarding Bid Fees specified on page 23 of the RFP, there is a requirement for a certified check payable to PacifiCorp. As a multi-billion dollar corporation, we cannot do certified checks. What alternate methods will be acceptable? Corporate check? Wire? If a wire is acceptable, PacifiCorp bank information is required.
A50. Provided below is the Wiring Instructions for PacifiCorp Wholesale Account. Bidders who wire funds to PacifiCorp instead of submitting a check should note that they have wired such funds in their cover letter or provide some documentation with their proposal to identify how the Bid Fees were provided.
WIRE FUNDS TO:
PACIFICORP
JPM/CHASE
ABA 021000021
Account 5544688
On the "Further Credit Line" section of wire Bidders are to insert "All Source RFP - Resource 2016" and include the Bidder name as stated on top of their submitted Attachment 19 - Term Sheet.
If Bidders have any questions, please contact Tanya Sacks at (503) 813-5660 or Christine Cromwell at (503) 813-5668 or Krisit Olsen at (503) 813-5670.
Q51. Has PacifiCorp updated any documents associated with the All Source RFP?
A51. Yes. PacifiCorp Transmission has updated Attachment 20. The updated version of Attachment 20 is included in the Documents Tab of this website.
Q52. The RFP page 27 describes how bids are to be submitted. Are you expecting 2 paper copies of Form 1? Form 1 is a rather large spreadsheet.
A52. Form 1 should be provided on a flash drive and is not required in paper format.
Q53. Is a Bidder required to purchase firm transmission prior to submitting their proposal?
A53. No. The Bidder must demonstrate that they are able to purchase firm transmission and the availability of the transmission however, they are not required to purchase the transmission prior to submitting their proposal.
Q54. Is a single primary contractor required if a bidder is proposing the construction of a new resource under one of the Eligible Categories?
A54. Yes, Bidders should note that any proposal submitted that proposes new construction of a generation facility must utilize the services of a single primary Contractor under a single EPC contract or an equivalent structure which will not increase the risk of default by multiple contractors to the Company and its customers. However, the single EPC manages the construction of the project.
Q55. Attachment 17, Section 8.1.6 Telephone and Data Systems states that the Owner will supply and install the telephone and data switching equipment to the facilities listed in the table. Please provide information on this equipment (switches, routers, etc.) and wiring system (copper, fiber, jacks, patch panels, etc.).
A55. Changes to Attachment 17, Exhibit A, Section 8.1.6 are replaced as described below under Telephone and Data Systems. Attention is directed to Attachment 17, Exhibit A, Sections 1.2.3.4 and 8.1.6, and Appendix G, 8B.3.1-Data and Voice Network Infrastructure Wiring Guideline for additional information. Contractor provided equipment shall be Siemon certified components.
Q56. Attachment 17. Section 8.1.6 Telephone and Data Systems. How does the Contractor have to end the fiber and copper wiring in the admin-control building and in the terminal points for telephone, data and camera cable? Do we have to connect the cable and fiber in patch panels or equipment, or leave it in dead-end in the place required to connect it later by the Owner?
A56. Contractor shall terminate the fiber and copper wiring of telephone and data cable in the admin-control building, at locations where switches and routers will be located, and at termination points for telephone, data. Ends of camera cables shall be long enough to reach Owner installed equipment. Ends of camera cables shall be protected from damage. Others will terminate the ends of the camera cables.
Q57. Attachment 17. Section 8.17, Plant Security System states that "Contractor shall install raceway, power cable, and fiber optic cable to each of the plant fence corners, main entrance gate, contractor turnstile gate, and other areas as shown in Appendix P Security Conduit Termination Locations Drawing". Is it required a full CCTV coverage of the future plant including as a minimum the locations in Appendix P, or just the locations shown in Appendix P?
A57. The Contractor is not required to provide closed circuit television coverage of areas not described in Section 8.17, Plant Security System or Appendix P.
