PacificCorp 2009 RFP

Q1. In regard to points of delivery, is it acceptable to deliver power at the Dave Johnson power station in Wyoming or the Bonanza substation in Utah? If not, why not? Can we assume that the Aeolus substation will be a delivery point with access to the Gateway West transmission project?

A1. Deliveries at Dave Johnson would add to an existing generation surplus in SE Wyoming that requires transmission export capacity to PAC loads to the west. Energy Gateway capacity will moderate this constraint, however in-service dates may be an issue regarding bad timing. Note: if proposing a new generator interconnection at the Dave Johnson substation, be advised of severe space limitations for any new line termination. Any new generation interconnected to Windstar, as an alternate, would resolve space and design concerns at the existing Dave Johnson site. Bonanza substation and the Bonanza to Mona transmission line are owned by Deseret. Energy delivered at Bonanza needs to include transmission arrangements with Deseret to deliver the energy to Mona.

You can assume Aeolus is a delivery point for Gateway West, however, timing of Gateway west and the RFP bids should be considered. Public information shows the target in-service dates for Gateway west as 2014-2016. Current and future stakeholder developments and activities in Wyoming could negatively impact the in-service date. (Posted on January 5, 2010)

A2. The appendices are posted as .PDF and Word documents ("MS Word Version" is the link). Link to document: http//www.pacificorp.com/content/dam/pacificorp/Suppliers/RFPs/All_Source2009/RFP2009_AllSource_Appendix_12-2-09.doc. Page 5 is the intent to bid form. (Posted January 10, 2010)

A5. Deliveries at Four Corners are not being considered for an incremental resource. There is no additional transmission available to import generation into the PACE. (Posted January 11, 2010)

Q6. On page 26 of the Utah RFP it states "The Company will not accept renewable resources that cannot be dispatched or scheduled by PacifiCorp". How do you define schedule and dispatch? More specifically, is wind generation an acceptable resource per this RFP?

A6. If the resource can be scheduled firm from another control area or if the resource can be dispatched by PacifiCorp then it qualifies. If the wind resource is scheduled from another control area on an hourly firm basis with firm transmission then it does qualify. Standalone wind would not be allowed based on the fact that it is not schedulable or dispatchable, but we would welcome creative solutions to those issues. (Posted January 10, 2010)

Q7. On page 14 of PacifiCorp's All Source RFP Bid Conference Presentation, it is stated that "the Company will adjust the submitted capital cost of indexed bids from bidders for risk in the same manner as the Benchmark Resources. How is the risk adjustment mentioned above calculated? Does the risk adjustment apply to to Capacity Cost payments, Fixed O&M payments, and variably O&M payments when using the allowed indices (i.e. CPI, PPI-metals, GDP)?

A7. The risk adjustment is applied to only the capital cost if the bidder decides to index their bid. The risk adjustment only applies to the capital cost of a new resource. (Posted January 10, 2010)

- Are we allowed to have PacifiCorp reimburse us for any specific costs we incur? I am referring to the last bullet on page 44 of the RFP which talks about property taxes, sales tax, and insurance payments. How does this generally work?

A8. Yes, you are allowed to offer this price scheme. No, an existing resource cannot index a proposal and therefore no risk adjustment will be applied. No, PacifiCorp will not reimburse the bidder for any costs. (Posted January 10, 2010)

Q9. We are considering a bid into the All Source RFP but we have concern over the delivery points as identified in the bidder presentation. Our proposed delivery point for energy would be Four Corners. Is this an acceptable delivery point under the RFP? Is this a delivery point where we would be considered as a viable resource by PacifiCorp?

A9. No. This is not a delivery point in the RFP and the All Source RFP does not allow intermittent resources unless they are scheduled into the PacifiCorp control area on a firm basis or can be dispatched by PacifiCorp. (Posted Jan 11, 2010)

A10. A resource that can be dispatched or scheduled into the PacifiCorp control area, but for those Resource Alternatives that are Exceptions identified on page 14 and 15 of the RFP (i.e. qualifying facilities, load curtailment, etc.). (Posted Jan 11, 2010)

Q11. In regard to points of delivery, is it acceptable to deliver power at the Dave Johnson power station in Wyoming or the Bonanza substation in Utah? If not, why?

A11. Deliveries at the DJ or Bonanza substations are not being considered for an incremental resource. There is no additional transmission available to import generation into PACE. (Posted Jan 11, 2010)

Q15. Salt Lake Valley is one of the Points of Delivery. Since there is no substation by that name, can we assume the area along the 138kV line is suitable for POD?

Q16. According to the approved Lake Side Vendor List a "Siemens SGT6-5000F or Owner approved equivalent" can be bid to this site. Is a GE 7FA an owner approved equivalent for this site?

Q18. On page 26 of the RFP one of the unacceptable proposal characteristics is that the Company will not accept renewable resources that cannot be dispatched or scheduled by PacifiCorp. Does wind generation qualify based on this definition?

Q19. In Appendix A of PacifiCorp All Source RFP, there is a footnote at the end, saying PacifiCorp may require step-in rights, a second lien, a cap on debt to equity ratio and etc. These requirements could be problematic from a lenders perspective. Can you clarify these requirements and elaborate on the idea behind them?

A19. Step-in rights, a second lien, a cap on debt to equity ratio are required in the PPA, APSA and the Tolling Agreement. Please review these terms in these documents. These requirements are part of the overall credit and security package for any resource. (Posted Jan 11, 2010)

A.21. You can reply to either one but not to both of them. The only difference is that the Utah RFP allows for the review of coal as a resource, however, there are no other differences.

Q. 22. Deliveries are allowed at Borah/Brady. Would PacifiCorp be able to accept deliveries on the Jefferson or at Yellowtail? If so, for a PPA could the quantity be less than the 100 MW and based on the firm transmission capacity of the Seller? For example, would PacifiCorp consider an offer on the Jefferson for 70 MW.

A.22. No. Jefferson is not an acceptable Point of Delivery as the company has no firm right to import power at that point. In addition, the RFP is for a minimum of 100 MW.

Q1. We did not attend the pre-bid conference in March, but would like to become an active participant in this resource solicitation. We are following updates on the RFP website, which recently issued the final version of the RFP. As such, we'd like further detail on upcoming milestones for bid conferences, intent to bid filings and any other information that will assist us in getting up to speed in the process.

A1. Please refer to the schedule in the March 2008 presentation (e.g. Utah Presentation by PacifiCorp 3/12/2008) under the tab 2008 RFP Documents on this website on how you can participate in each of the states (4/21/2008).

Q2. Since the Final Draft for the PacifiCorp All Source RFP was submitted on March 28, 2008, and the Notice of Intent to Bid is +30 days from issuance, is it correctly assumed that Notice of Intent to Bid is due by April 28, 2008 for all bids regardless of site location?

Q3. Chart 1 in the RFP says "Life of the asset will be evaluated consistent with IRP Tables C.27 and C.28". The version of the 2007 PacifiCorp IRP available at the attached link : http://www.pacificorp.com/Navigation/Navigation 23807.html does not appear to have Tables C.27 and C.28. Please provide the appropriate tables or otherwise clarify what tables are being referred to in this Chart 1 of the RFP.

A4. Tables 5.1 and 5.2 are plant lives which are consistent with the depreciation schedule allowed by PacifiCorp regulators for each type of generating resource.

Q5. Please explain how the design plant life estimates contained in this table are used in the bid evaluation process for each of the seven resource alternatives (PPA, TSA, APSA on PacifiCorp sites, APSA on Bidder's site, Purchase of an existing facility, Purchasse of a portion of a facility jointly owned by and/or operated by PacifiCorp, Restructuring of an existing PPA or Exchange Agreement and/or Buyback of an Existing Sales Agreement)

A5. A Bidder may provide a proposal under any of the given seven alternatives. The term in all seven alternatives will be capped at the design life of the project consistent with Table 5.1 and 5.2. A bidder may, however, propose a term which is less than the life of the project in Table 5.1 and 5.2 and the Company will evaluate the proposal accordingly.

Q6. For instance, if an existing unit that qualified per Table 5.1 and 5.2 as having a 35 year life is going to be 8 years old at the time the sale is expected to be finalized (in 2012), does that mean that the bid evaluation will presume a 27 year remaining life?

A6. Yes, the Project life will be consistent with Table 5.1 and 5.2. The start date of the life of the project will be based on the commercial operation date of that specific project.

A9. The bidder can provide this information in the proposal, however, at this point in time the Company does not have a mechanism to provide additional value to such extention work.

Q10. As part of the 2008 All Source RFP, PacifiCorp is making two sites available to bidders. Please provide the process which a bidder must follow in order to negotiate a purchase or lease option on the properties. Will the sites go to the highest bidder? Is there a separate RFP for that? How will such bids be evaluated?

A10. The sites that are available in the RFP are not for sale or for lease. There is not a separate RFP for the sites. The sites are available to the Bidders to use in submitting their proposals or projects on those sites. The proposal which provides the least cost adjusted for risk proposal will have access to the company's site.

Q11. There was notice of a Final Draft RFP posted on the Utah PSC website on August 6th. Has the final RFP been posted on PacifiCorp's website? Where can I find it? Is there a pre-bid conference scheduled (according to what's posted that could be August 26th?).

A11. The 2008 Request for Proposals has not yet been approved in Utah. Once it is approved the dates in the schedule will be updated. There is no pre-bid conference scheduled for August 26th. The pre-bid conference will be scheduled once the 2008 RFP is approved and the dates are updated.

Q12. What are the details for the 2008 All Source RFP Bidders Conference to be held on October 22, 2008 in Salt Lake City? Can you please verify the date and location so that we can make travel arrangements.

A12. Details of the Pre Bid Conference scheduled for October 22, 2008 is provided under the News tab of this website. In addition, details are provided in this answer.

PacifiCorp will hold a Pre Bid Conference in both Utah and Oregon on October 22, 2008 at 1:00 pm to 3:00 pm Pacific time (or 2:00 pm to 4:00 pm Mountain time). Bidders could also choose to call-in to the conference.

The call in number is (503) 813-5600 or toll free at (800) 503-3360. Bidders should enter the Meeting ID of 222444 when prompted as well as the Password of 222444.

A presentation will be emailed prior to the Pre Bid Conference. For bidders not on the distribution list a copy will also be posted on this website as well as PacifiCorp's website.

If bidders have any questions they would like answered at the Pre Bid Conference please send them to RFPAllSource@PacifiCorp.com and the company will address them at the conference.

Q13. Can an expected operational profile or plant capacity factor be provided for the peaking purchases on a monthly, weekly, or hourly basis? Hourly or weekly level of detail would be better

A13. No, the bidder will be expected to include dispatch characteristics such as capacity, heat rate, variable O&M, gas transport charges, flexibility parameters for holding reserves such as start time, minimum run, ramping rate which are all input within the 2008 Request for Proposal. (Posted 10/17/2008)

A. 14. Yes, the Word versions will be posted (Posted 10/17/2008). The Word versions of the Documents will be available the week of October 27, 2008 and will be posted on the website when available. (Posted 10/22/2008).

Q.15. Also, are 'Final' versions of all appendices going to be posted? (several of the appendices have blank dates, 'insert dates' and other 'Final Draft' notations throughout; please verify these are in fact the final documents not drafts).

A.16 Section 54 of the Utah Rules and Code which includes the state statutes on competitive procurement is available on the Commission's website at http://www.psc.utah.gov. Please look under the tab for Rules and Codes. (Posted 10/27/2008).

Q17. We will bid from multiple sites. However, the resource alternative will be the same for all sites. Since the instructions for the NOI say a separate NOI is required for each Resource Alternative, we do not have to file an NOI for each site. Is that correct?

Q19. On the Notice of Intent to Bid form, there are different resource alternatives including a Qualifying Facility that is asset backed or non-asset backed. Can you please explain the difference in your methodology for evaluating a QF resource versus a PPA or Tolling agreement, assuming all are asset backed.

Q21. Will there be scheduled visits to the PacifiCorp sites, such as Lake Side and Currant Creek? If not, how can bidders be granted the opportunity to visit them? (11/6/2008)

Q22. Within the Appendices to the PacifiCorp RFP, under the Credit Matrix section, it states " ... if (a Moody's or S&P credit rating is) not available, the credit rating will be determined by the Company through an internal process ....". Please provide guidance on what credit rating we should use in determining the amount of credit assurances to be posted. (11/6/2008)

A22. If the bidder is not publicly rated by S&P or Moody's, the Company will determine a Credit Rating through an internal process review and utilizing a proprietary scoring model developed in conjunction with a third party. The bidder is to provide the complete information requested in Appendix B, and the Company will then provide the bidder with a Credit Rating, which will determine the amount of credit assurances to be posted.

Q23. I am requesting clarification on the Notice of Intent to Bid for the PacifiCorp 2008 All Source Request for Proposals. Specifically, if we are planning to bid more than one option (different technology and/or size of the facility) at a given site are we required to submit an NOI for each option? It appears that the only difference that would occur between options is in section 1 "Resource Alternatives" of Appendix A.

A23. Per the 2008 All Source RFP, one NOI is OK to cover multiple options on the same bid but the bidder must submit a separate Appendix A and B to cover the different options (i.e. size, equipment, technology, etc.) (11/7/2008)

Q24. In the Main Document Section 3A, Chart 2 there is an event "Benchmark Resource Proposals due: December 2, 2008". Please confirm whether these Proposals are made available to Bidders, and, if so, on what date.

A24. Section 1 page 8 of the RFP states that the Company will submit a detailed evaluation of each Benchmark Resource with supporting cost information to the Oregon PUC and the IE's at least one day prior to the opening of bidder proposals. The benchmark will not be available to bidders prior to their bidding. (11/7/2008)

Q25. We have several questions related to the timing of the bid evaluation, and how it relates to the timing estimates in Section 3A, Chart 2 of the Main Document. In the Main Document, Section 6, an "initial short list" and a "final short list" are described. Will bidders selected for the initial short list be notified? If so, when? Please answer in the context of the Main Document, Section 3A, Chart 2 (i.e. will the notification occur prior to event "Complete Evaluation: February 27, 2009"?)

A25. Yes, Bidders who make the initial short list will be notified. The time line will depend on how many proposals need to be analyzed. We anticipate that it will occur prior to the Complete evaluation in the RFP. (11/7/2008)

Q26. When will Bidders selected for the "final short list" be notified? Will this occur shortly following the estimated "Evaluation Complete" date? The estimated timing is important, due to the requirement to provide the guarantee commitment letter 20 days thereafter.

A26. Bidderes will be notified as to their inclusion on the final short list at the conclusion of the evaluation process. The date of February 27, 2009 and March 27, 2009 are tentative and is subject to movement. Credit commitment letters will not be due until 20 days after the notification. (11/7/2008)

Q27. In the Main Document, Section 3A, Chart 2, why is the Company estimating a 3.5 month gap between "Evaluation Complete: February 27, 2009" and "Bidder Negotiation: June 15, 2009"? Does the June 15, 2009 date represent when the Company expects to complete negotiations with Bidders?

Q29. If a bidder wishes to choose a Benchmark Resource site, to what extent is it expected that PPA bidders will need to follow the specifications and data requirements provided in the Site Specifications Attachments 24 and 25 to the RFP? Specifically, the detailed data required under page 42 (Oregon) or page 40 (Utah) of the RFP and depicted in Attachments 24 and 25, Appendix K may not be known at bid time. Will bids be penalized? Further, specific design decisions including subvendors seem restrictive for a PPA bid. Please clarify the intent of the last sentence of the 2nd paragraph on page 16 of the RFP - "If a bidder builds a project on either of the PacifiCorp sites, Currant Creek or Lake Side, the project must be built to meet the specifications provided in Attachments 24 or 25 as applicable.

A29. The Bidders will need to provide a proposal consistent with the specifications in the Attachments. To the degree there are any modifications the Bidder must provide a redline of the Attachment 24 and 25. The Company will then determine if the modifications in any way impact price or risk and it will be evaluated accordingly. Although specific details as described in the specifications may not be known at the time of bidding the bidder will be held accountable to meeting these standards with their bid - they will bear the risk.

Q31. Page 28 of the RFP indicates that submission of Intent to Bid Forms must be a physical copy, implying that October 31st email submissions are not accepted (with original after Oct 31). Is that correct? If so, this appears commercially unconventional.

Q32. Please verify the bid fees if we are proposing to bid several different generation equipment options at 2 different sites. The overall proposal would consist of (1) Two Combustion turbines at the 1st site and (2) Two combustion turbines or (3) 1x1 Combined cycles at the second site. All bids would be under a single Resource Alternative (i.e. Tolling Agreement). Is the calculation of $21,000 in bid fees correct?

A32. PacifiCorp calculates you bid fees to be $30,000 because you have 3 bids. 1) two combustion turbines at the 1st site, 2) two combustion turbines at a 2nd site and 3) three 1x1 combined cycles at the 2nd site. The RFP states in Section F bid fees for a proposal for a different Resource Alternative, at a different site or using a different technology will be considered a separate proposal and will be subject to a separate bid fee.

A33. Bidders will be responsible for interconnection of their resource to either the PacifiCorp system or a 3rd party transmission provider system and all communications with the transmission provider. If the bid resource is interconnected to a 3rd party transmission system the bidder is responsible for all transmission service arrangements for all deliveried energy under any PPA to the PacifiCorp system. PacifiCorp will include costs of integration to their transmission system and will apply for these studies to be initiated. This will be discussed at the Transmission Workshop on November 10.

Q35. If an Intent to Bid was submitted for one Resource Alternative, can a proposal be submitted for that Resource Alternative and another one (one which did not have an Intent to Bid)?

A35. If the proposal is for the same Resource Alternative then it is considered an Alternative but of the proposal is for a different resource alternative then it requires a separate Intent to Bid.

A36. Gadsby is not a brownfield site like Currant Creek and Lake Side 2. This would require a repowering of an existing generator which is not part of the 2008 All Source solicitation.

Q38. Within the PacifiCorp RFP, on page 17 under the Tolling Service Resource Alternative option, it states "... with such an amount being no less than 420 MW nominal generating capacity ....". Can a bidder offer a proposal that is a Tolling Service option that is under 420 MW required minimum limit, but offering 100% of the facility's generating capacity. The proposed facility would be approximately 300 MW.

Q39. Within the Appendices to the PacifiCorp RFP, under the Credit Matrix section, it states "if (a Moody's or S&P credit rating is) not available, the credit rating will be determined by the Company through an internal process ....". Please provide guidance on what credit rating we should use in determining the amount of credit assurances to be posted.

A39. The RFP states the Credit Rating is defined as the lower of: x) the most recently published senior, unsecured long term debt rating (or corporate rating if a debt rating is unavailable) from S&P or y) the most recently published senior, unsecured debt rating (or corporate rating if a debt rating is unavailable) from Moody's Investor Services. If option x) or y) is not available, the Credit Rating will be determined by the Company through an internal process review utilizing a proprietary credit scoring model developed in conjunction with a third party.

Q40. From the Company's response to Question 4 in the Q&A posted on the RFP website, are these depreciation schedules governing designed plant life documented anywhere? If so, can they be provided?

A42. Yes, if the proposal is fpr a new power power plant to be located in either Oregon or Washington. If the bid is for a power purchase agreement, bidders are expected to include any current or reasonably expected future emissions-related compliance costs (including future greenhouse gas allowance costs), within their proposed pricing.

A43. Currently, Oregon requires new power plants to offset approximately 17 percent of anticipated CO2 emissions and Washington requires new power plants to offset approximately 20 percent of anticipated CO2 emissions. Bidders should consult each state's power plant siting regulations for the latest offset obligations.

Q44. Please verify the bid fees if we are proposing to bid several different generation equipment options at two different sites. The overall proposal would consiste of (1) Two Combustion turbines at the first site and (2) Two Combustion turbines or (3) 1x1 Combined cycle at the second site. All bids would be under a single Resource Alternative (e.g. Tolling Agreement). Is the calculation of $21,000 in bid fees correct?

A44. PacifiCorp calculates your bid fees to be $30,000 because you have three bids: (1) Two combustion turbines at the first site, (2) Two combustion turbines at the second site, and (3) a 1x1 combined cycle at the second site. The RFP states in Section F that bid fees for a proposal for a different Resource Alternative, at a different site or using a different technology will be considered a separate proposal and will be subject to a separate bid fee.

Q45. Bidders will request new interconnection service as part of this RFP. Therefore, interconnection costs as determined by the Generator Interconnection Process, will not be known at the time of the bid. How does PacifiCorp Generation suggest the interconnection costs be included to remain in compliance?

A45. Bidder must either assume the interconnection cost or have a third party engineering firm provide them with a cost. Regardless, the bidder will be responsible for the cost to interconnect the resource and PacifiCorp will assess the cost to integrate the resource as part of the initial shortlist evaluation.

A49. This will be discussed at the Transmission workshop on November 10, 2008. However, it comes back to the fact that the resource must be integrated as a network resource.

Q51. Precisely where on the IE website should Bidders submit their "request for alternative eligible online dates" pursuant to Section 1 paragraph 3 of the RFP document?

A51. Bidders should submit any requests for eligible online dates or requests for alternative indices via a direct email question in the same manner all questions are submitted. (posted 11/13/2008)

A52.1 No. The selection of resources, as outlined in the 2008 All Source RFP on pages 60-63 will be based on an assessment of various resource portfolios on a cost adjusted for risk basis.

A52.2 Not necessarily. PacifiCorp will evaluate its options at the time of final short list and determine what is in the customers best interest. (posted 11/13/2008)

A53. No. PacifiCorp did have the presentation available at two locations as well as the phone in. If you have any specific questions please submit them and we will respond as quickly as possible. (posted 11/13/2008)

Q56. We were unable to call into the Transmission call on 11/10/2008, due to all the phone in lines being full. Was the call recorded, and can the recording be made available, so bidders unable to call in can hear the presentation?

Q57. If we are short listed, we would have to post a pre-determined credit amount for performance as of the execution date. This would be done without negotiation of other credit terms. It seems like credit is a negotiated item that entails more than simply one party posting a pre-defined amount when other credit terms aren't addressed.

A57. Yes, if you are on the Final Shortlist you would be required to provide a commitment letter for the pre-determined credit amount for performance 20 business days after having been selected on the Final Shortlist. The total credit amount will be negotiated as part of the Agreement prior to the execution date. (posted 11/16/2008)

A59. Yes, all credit terms will be negotiated as part of the final transaction. However, the bidder must be able to provide a commitment letter twenty days after being selected on the Final Shortlist. (posted 11/16/2008)

Q60. How does the Company evaluate a proposal whose depreciation schedule (allowed by PacifiCorp regulators) related to the sale of an existing facility is shorter than the design plant life of that asset? Or does the approval valuation per this RFP just allow for the Design Plant Life to be equivalent to the Depreciation Schedule?

A60. We first run an analysis using the approved book depreciation lives of the plant, just to cover the regulatory side. If we believe the economic life extends beyond the official book life, then we extend the analysis period to match the best estimate of the extended life if such extended life is known and measurable at the time of the analysis. (Posted 11/19/2008)

Q61. When is the appropriate time to propose adjustments to the Design Plant Life based on existing or planned plant improvements? How will these adjustments be evaluated and validated?

A61. Please treat existing improvements and proposed improvements as separate bid alternatives with different capital, performance, lifetime, etc. Also, please read the question on depreciation schedule vs design life. (Posted 11/19/2008)

Q63. We note that there are changes made between the older pdf version of the "Appendices, Attachments and Forms" document, and the recently released Word version. Can a blackline between the two documents be provided, or a list of changes? This same request applies to all the documents which had new Word versions released.

Q64. We note that the value in Attachment 13 for East System, Estimated Cost of Upgrades for the Salt Lake Valley 138 kV Point of Delivery has increased from $30 in the original PDF-provided file to $100 million in the more recent Word file. Please confirm that the $100 million amount is the most recent amount. If there is a particular reason causing the change, please provide the reason.

A64. The $100 million cost is the most updated value (August 5, 2008) on the PacifiCorp Transmission website. The latest version of Attachment 13 will be posted on the IE website under the Documents tab. (posted 11/16/2008)

A65. The integration costs in the RFP are the Network upgrades, however, they do not include the interconnection costs which are the bidders' responsibility. (posted 11/16/2008)

Q67. Section 4, page 50 of the RFP states - "Once the bidder is selected, PacifiCorp's transmission function has the option of funding the interconnection upgrades or requiring the bidder to fund such upgrades and then receive revenue credits per PacifiCorp's OATT. Any revenue credits shall be assigned to the Company." Is this statement suppose to indicate that the Bidder will ultimately not be refunded any of the interconnection costs (Network upgrade or otherwise).

Q68. On page 27 of the All Source RFP it states "if a Bidder submits the same proposal but with three different bid sizes, the proposal will be considered one proposal with two alternatives and .... pay one bid fee." If the Bidder is submitting a base bid with an alternative for 4th or 4th and 5th unit option (i.e. Base bid - 300 MW, Option 1 - 400 MW and Option 2 - 500 MW). What are the appropriate bid fees for this bid and alternative options?

Q69. With regard to page 10, paragraph 1, after the first short list is prepared, does this paragraph mean that at that time, PacifiCorp will add the Chehalis plant to the shortlist for evaluation against the bid projects that made it into the first shortlist? So, in essence, the bidders are also competing against the Chehalis acquisition?

A69. The bidders will not be bidding against Chehalis but the final shortlist analysis will include the Chehalis plant in PacifiCorp's resource mix for the evaluation of bids received in this RFP. (posted 11/16/2008)

Q71. Are the delivery points that are listed in the 2008 All Source RFP the only delivery points that can be put in a conforming bid, or can other delivery points not listed in the RFP also be used (with the bid remaining non-conforming)?

A71. Bids will be deemed conforming that represent cost effective resources that are capable of delivery into or in the Company's network resource system. If your point of delivery cannot meet this designation, then it will be deemed non-conforming. (posted 11/16/2008)

Q72. We would like to request an alternative eligible online date for each of two Resource Alternatives. We wish to offer our resource in a "tolling service agreement" category commencing on January 1, 2010 or as soon as PacifiCorp is able to evaluate and obtain approval for the proposal. Additionally, we wish to offer our resource in the "Purchase of an Existing Facility" category in a manner that would transfer ownership of the plant to PacifiCorp commencing on January 1, 2010 or as soon as the Company is able to evaluate and obtain approval for the proposal.

Q73. This question has to do with "Form 2: Permitting and Construction Milestones". Must bidders conform to the exact line items in the Form, or can bidders modify the line items in the Form to better suit the technology being bid?

Q74. Pursuant to Section 1, Paragraph 3 of the 2008 All Source RFP, we are writing to request approval for an alternative eligible online date. We anticipate that we may have resources available for dispatch or scheduling prior to June 1, 2012, and we would like to request an alternative eligible online date of January 1, 2012. We will confirm resource availability to meet the alternative eligible online date in our final proposal, pending your approval.

Q76. The Mechanical Availability inputs (ID 74-85) allow for variation by month. If the bidder anticipates that the availability may vary by year as well, how should this by reflected in Form 1?

Q77. If capacity payments (ID52) are allowed to escalate at a predetermined rate (not subject to an index), can the escalation rate be applied to 100% of the capacity payment (unlike the indexing option which limits indexing to 40% of payments) - where should this % be inputted in Form 1, if needed?

Q78. If capacity payments (ID 52) are allowed to escalate, will a time limit be applied to teh escalation - or can it be assumed that they would escalate over the entire contract? Where should the escalation end date need to be inputted into Form 1, if needed?

Q79. Are bidders allowed to submit a Capacity Payment (ID 52) that can escalate at a pre-determined rate (not subject to an index) - if so, where should the escalation rate for Capacity Payments be inputted into Form 1?

Q80. If an escalation rate is inputted for Start Costs (ID 46), Variable O&M Payment (ID 43), Fixed O&M Payment (ID 49) in Form 1, is there a mandated time limit for the escalation. In other words, can the payments be assumed to escalate through the entire life of the contract or does an escalation end date need to be inputted in Form 1?

Q81. Please confirm that Starts Costs (ID 46) should be inputted as $/start/unit in Form 1 and not as $/Mwh as implied in the RFP document (page 45 in Utah Main RFP Document).

Q82. The facility type field (ID 2) does not have an option for Simple Cycle Combustion Turbine units in Form 1. What should be inputted in ID 2 if a Simple Cycle Combustion Turbine is being bid?

A82. The "Combined Cycle" entry has been modified to read "Combined or Simple Cycle". With this selection, appropriate column headings will be displayed with "Simple Cycle" throughout. (Posted 11/19/2008)

Q83. Please confirm that the following prices should be inputted as of the bid submittal date (e.g. December 2008 nominal dollars) - Variable O&M Payments (ID 43), Start Costs (ID 46), Fixed O&M Payments (ID 49) in Form 1.

A83. This response is a correction to the guidance given in the Pricing Input Call: enter these amounts as of the first month of delivery from the bid resource. The updated Form 1 has this clarification in both the row title and the definitions. (Posted 11/19/2008)

Q84. On the Resource Capacity input field (ID 34) in Form 1, please confirm that 'degraded' capacity should be inputted and not nameplate capacity (if different).

Q85. From Form 1 - Pricing Input Sheet excel file, the formulas in Cell F48:I48 will return a "Not Applicable" unless F13 is populated with an entry that begins with "Comb". What resource type in F13 should bidders select for a natural gas simple cycle. Please keep in mind in your response that if the bidder uses the selection "Other", then the formulas in F48:I48 and S11:Z11 will not populate correctly to allow the user to enter simple cycle characteristics that are obviously intended to be entered in columns starting in G48, U11, and V11.

A85. The "Combined Cycle" entry has been modified to read "Combined or Simple Cycle". With this selection, appropriate column headings will be displayed with "Simple Cycle" throughout. (Posted 11/19/2008)

Q86. From Form 1 - Pricing Input Sheet excel file, in Table Q62:AB75, the monthly heat rates are contingent on the bidders temperature assumptions which can vary dramatically (historical 5/10/30/50 year for 7x24, heavy load hours, super peak hours, etc.). It would seem more prudent to have bidders submit heat rate-temperature curves and allow the Company to use uniform temperature assumptions to evaluate bids. Multiple bidders with the same technology and temperature-adjustment factors will have different evaluation results based on each bidders assumed monthly temperatures. How does the Company intend to compare monthly capacity and heat rate adjustments equitably?

A86. Please enter monthly heat rates based on best available temperature data for the resource site and for the hours of the day in which the bidder anticipates the resource would operate. PacifiCorp cannot be responsible for temperature data for every bid location. (Posted 11/19/2008)

Q87. From Form 1 - Pricing Input Sheet excel file, in Table Q10:AB53, the degradation factors (which are typically a function of capacity factor/generation/fired hours) are implicitly asking bidders to assume a capacity factor in order to translate into an annual table. It would seem more prudent to have bidders submit fired hour-heat rate degradation curve and allow the Company to use uniform fired hours by technology to evaluate bids. Multiple bidders with the same technology and degradation factors will have different evaluation results based on each bidders assumed run hours. How does the Company intend to compare annual degradation factor adjustments equitably?

Q88. Attachment 13 identifies Paul 500 kV (up to 600 MW) as a Point of Reference for PacifiCorp on its West System. Is this 600 MW of receipt capacity still available after factoring in PacifiCorp's acquisition of the Chehalis plant? In other words, can PacifiCorp still receive 600 MW at Paul even with the addition of Chehalis?

Q89. Form 1 Pricing Input; ID 2 Resource Type does not have simple cycle as an option in cell F13. Which alternative should we use for simple cycle gas fueled projects?

A89. The "Combined Cycle" entry has been modified to read Combined or Simple Cycle". With this selection, appropriate column headings will be displayed with Simple Cycle throughout.

Q90. For a new construction facility, NOT on a PacifiCorp site, proposing a TSA; is the Bidder required to use a single primary Contractor under a single EPC contract?

A90. Yes. Page 19 of the RFP states that any proposal submitted in the TSA category 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.

A93. Yes. Bidders may propose any of (7) different Resource Alternative structures and (3) exceptions in (3) separate Bid categories of resource requirements. The Bid categories are separated into Base Load, Intermediate Load and Summer Peak resources and can take the form of a Power Purchase Agreement, Tolling Service Agreement, Asset Purchase and Sale Agreement (PacifiCorp site and specifications), Asset Purchase and Sale Agreement (Bidder site), purchase of an existing facility, purchase of a portion of a facility jointly owned or operated by the Company, restructuring of an existing Power Purchase Agreement or Exchange Agreement or exceptions which include Load Curtailment, Qualifying Facilities or Eligible Renewable Resources. (Posted 11/19/2008)

Q94. In the event a party that wishes to bid in the RFP process missed filing a notice on the "Intent to Bid" filing date, does the party have the ability to still bid into the process, or does missing that date eliminate their opportunity to bid into the RFP?

Q95. On page 32 of the Oregon RFP document, there is a description of the capacity payment that states that it can be escalated. In the pricing discussion this week, it was stated by one of the participants that the form did not allow the capacity payment to be escalated by year. Is the pricing submittal form going to be modified to allow the escalation of the capacity payment by year? If the pricing submittal form is not modified, should an addendum be attached that details what the capacity payments bid is?

A96. Some of the Exhibits or Attachments to the PPA are included on the website. The remaining exhibits will be included in the final executed version of the PPA as part of negotiation for a specific project.

Q.97. For the NOI submittal, we would like to propose multiple project types (i.e. CT and combined cycle) at different sites for one or two alternatives. Should we complete the NOI for each option?

A97. Bidders should complete the forms in the NOI that have different information (i.e. site, technology, etc.) for each project. The options the bidder eventually selects to bid would be their decision given the bid fees, alternatives available, etc. PacifiCorp does not intend to look at the options the bidders were considering in their NOIs and select the preferred ones.

Q98. Can a Bidder who has previously submitted an NOI and been accepted as an eligible bidder, provide a new or different bid from another location other than the bids identified on the NOI?

A100. One NOI is OK to cover multiple options on the same bid but the bidder must submit a separate Appendix A and B to cover the different options (i.e. size, equipment, technology, etc.) (Posted 11/23/2008)

A101. The 138 kV interconnection in the Salt Lake Valley is a proxy for an interconnection to a major 138 kV hub. Since no specific point was provided it assumes major upgrades to an existing station and upgrades, reconductor, etc. to at least 4 138 kV lines.

Q102. If the project is interconnecting at a voltage higher than 138kV in the Salt Lake Valley, does that mean there is no system upgrade cost assumed in the evaluation?

Q103. Please verify that bidders do not have to submit an interconnection request to PacifiCorp Transmission and include that request with their proposals, but rather just include the estimated costs of interconnection within their proposals?

A103. Bidders must take all the risks of the interconnection of the project, inclusive of timing, construction and cost. It is the Bidders decision as to the timing and management of the interconnection request.

Q104. Can an expected operational profile or plant capacity factor be provided for the peaking purchases on a monthly, weekly, or hourly basis? Hourly or weekly level of detail would be better.

A104. No, the bidder will be expected to include dispatch characteristics such as capacity, heat rate, variable O&M, gas transport charges, flexibility parameters for holding reserves such as start time, minimum run, ramping rates which are all input within the 2008 Request for Proposal.

Q105. Section 4, page 50 of the RFP states "Once the bidder is selected, PacifiCorp's transmission function has the option of funding the interconnection upgrades or requiring the bidder to fund such upgrades and then receive revenue credits per PacifiCorp's OATT. Any revenue credits shall be assigned to the Company". Please describe in detail the mechanism that will be used to refund Network Upgrades to the selected bidder. Please confirm if this refund will stay with the Bidder or if they have to be assigned to PacifiCorp Generation.

A105. Bidders will be required to fund the direct assigned and network upgrade costs of their interconnections. The network upgrade costs will be credited back to interconnection customers according to the agreement terms and do not require assignment of credits back to PacifiCorp Energy. The network upgrades will be borne by PacifiCorp. These costs, from Attachment 13, will be used to evaluate the cost effectiveness of individual bids.

Q106. Section 4, page 50 of the RFP states - "Bidders are reminded that they shall bear 100% of the costs to interconnect to PacifiCorp's transmission system." Please explain in detail what is included in these interconnection costs. Does it include Network Upgrades beyond the POI?

A106. The requirements are defined in the proforma version of the Large Generator Interconnection agreement in Section 11.4. Generally, the Interconnection customer will pay for all interconnection costs, both network upgrades and direct assigned costs of the interconnection under terms of the interconnection agreement. Network upgrade costs will be refunded to the interconnection customer either when the project is commercial - in a lump sum, or over time as transmission service is taken.

Q107. You provide distinct eligible online dates of June 1, 2012, June 1, 2013, June 1, 2014, June 1, 2015 and June 1, 2016. Would a commercial operation date that differs from the provided Eligible Online Dates be considered? Would a different date be considered if it was not before June 1, 2012?

A107. The Company will accept different online dates as long as for a given delivery summer the online date is prior to June 1 of that delivery summer (i.e. online prior to June 1, 2014 for consideration for a June 1, 2014 bid. For Bids with online dates prior to June 1, 2012, a notice will need to be received by PacifiCorp from the bidder 30 days prior to the bid submittal.

Q108. System Sale: Can a System Sale bid be accomodated within the RFP structure? As an example, the proposal would be provided a PPA (unspecific to resource) for a term of less than 5 years, the energy from which would be provided from more than one technology, at one delivery point, as base load energy and capacity. Consider this a traditional take-or-pay contract approach.

Q109. 100 MW - Is the 100 MW limit a hard limit? One bidder would like to submit a for 90 mW from multiple units of the same technology at one delivery point, but does not want to use over pressure conditions on the machines to meet the 100 MW limit.

Q110. Dispatch - Must units be dispatchable? If an asset-backed PPA proposal is made it would only be of interest to the Bidder if the Bidder continued to operate it as a base load resource.

Q111. Delivery: If Bidder is using the Western System to connect to a prescribed delivery point, will PacifiCorp allow the traditional pass through of costs from the use of the Western System during the term of the contract?

A111. Per page 49 of the RFP, for proposals that require third-party transmission service to provide delivery of capacity and energy to PacifiCorp control area at an acceptable POD, Bidder is responsible for any interconnection, electrical losses, reserves, transmission and ancillary service arrangements required to deliver the proposed capacity and energy to the bid specified POD. No delivery costs will be allowed to be passed through.

Q113. If capacity payments (ID52) are allowed to escalate at a pre-determined rate (not subject to an index), can the escalation rate be applied to 100% of the Capacity Payment (unlike the indexing option which limits indexing to 40% of payments), where should this percentage be inputted in Form 1, if needed?

Q114. If Capacity Payments (ID52) are allowed to escalate, will a time limit be applied to the escalation, or can it be assumed that they would escalate over the entire contract? Where should the escalation end date need to be inputted into Form 1, if needed?

Q116. I emailed RFPAllSource@PacifiCorp.com a couple of days ago but never heard back. What is the process on withdrawing our bid (if we choose to do that)? What is the notification time or deadline to have our bid withdrawn?

A116. Once the Utah Commission provides PacifiCorp with a response to the motion to suspend the 2008 All Source RFP PacifiCorp will set up a conference call with the bidders to discuss.

Q117. While reduced load from the recession may impact the need for large baseload resources, does PacifiCorp anticipate a need for quick start peaking and load following gas-fired resources to support new wind and other renewable development on its system?

Q118. Why does PacifiCorp believe that project financing for a 2012-2015 commercial operation date is an issue now, when such financing would not be needed until 2010 or later?

A118. It is not the financing but the cost associated with new construction, i.e. the cost associated with materials and commodities required in new construction.

Q119. Why doesn't PacifiCorp continue the process for another 4 months by selecting a short list, then asking for refreshed bids and then evaluating those potential projects relative to the market and economy in mid-summer?

A119. Because at this point in time the costs associated with the proposals are too expensive. In addition, PacifiCorp does not believe it is fair to the market to require bidders to keep their proposals in the 2008 All Source RFP if they have other opportunities they may want to participate in. PacifiCorp will continue to monitor the markets and determine when it is appropriate to lift the suspension.