April 21, 2008
Q&A from the 2008 All Source RFO Participants Conference
1)If a participant submits a Notice of Intent (NOI) can they also pursue bilateral negotiations? (4/21/08)
Yes. The NOI is nonbinding and parties can offer bilateral proposals outside of the 2008 LTRFO. However, PG&E would prefer that proposals come through the 2008 LTRFO.
2)Why are PPAs restricted to ten years when you have indicated that the assets should be designed for 30-year life? How will you be evaluating the cost of purchased assets-will capital be fully depreciated over a ten-year life as well? If not, aren’t you giving an insurmountable advantage to the asset purchase option? (4/21/08)
PPAs are limited to 10years so that they are consistent withthe CPUC’s Decision 06-07-029, which adopted a 10-year cost allocation mechanism for PPAs with non-renewable generation facilities. PG&E is developing evaluation criteria to ensure that PSA proposals are not advantaged over PPAs, including evaluation of the different lives of the asset and contract term.
3)How do we submit the signed PPA with the offer? What if there has been changes to the standard form? Redline and sign? Negotiate and agree to prior to submittal? (4/21/08)
Participants should submit a redline version to the Form Contract and a signed clean copy of the same contract ready for execution should PG&E find the offer acceptable.
4)Please describe what PG&E is looking for in the description of the public outreach plan. (4/21/08)
PG&E is interested in understanding the efforts the Participant has made to work with the community in developing a power plant at the identified location. The more detailed plan a project has to contact local land use planningauthorities and other key community officials to help gain community support, the more likely the community will be to accept the project. Public outreach plans that addressactivitiessuch as press releases to the community describing the project, town-hall type meetings, attendance atchamber of commerce meetings, and outreach to small business are examples ofelements PG&E would be looking for.
5)Will PG&E make land available for a power plant site? If so, what procedures should be followed? (4/21/08)
PG&E is not planning to make any land available for development.
6)Is any division, affiliate, subsidiary, joint venture (JV), alliance, partner or etc. of PG&E submitting an offer into this RFO? Is PG&E actively soliciting any firm to submit an offer to which PG&E looks to partner with? (4/21/08)
PG&E is not planning to submit an offer into this RFO through any division, affiliate, subsidiary, JV, alliance, or partner.
7)Will PG&E be submitting an offer into this RFO for utility owned generation? (4/21/08)
No.
8)If a contracted project from the 2004 RFO fails to materialize, will those megawatts be additive to the total megawatts in the 2008 solicitation? (4/21/08)
The 800-1,200MWsfor this solicitation were authorized in the CPUC’s 2007 Decision on PG&E’s Long-Term Procurement Plan. See CPUC Decision 07-12-052. At this time, PG&E has no plans to add in the capacity for any failed projects from the 2004 LTRFO.
9)Are there any UFOs (Unique Fleeting Opportunities) that PG&E is currently considering? If PG&E acquires a UFO, will it count against the total megawatts in this RFO? (4/21/08)
PG&E is not currently considering any UFO to fill the 2008 LTRFO need.
10)Will PG&E provide a written transcript and list of meeting attendees from the 2008 All Source RF Participants Conference? (4/21/08)
There will not be a transcript of the ParticipantsConference. However, the Presentation as well as the list of attendees have been posted onto PG&E’s website.
11)Will questions submitted to the website be posted with answer on the website? (4/21/08)
All questions that are submitted to the email box will be posted, except for minor, individual questions.
12)How will the actual costs as determined by the interconnection study be dealt with after Offers are submitted?(4/21/08)
The participant needs to internalizethe potential for variations in the transmission costs in theiroffer.This may be a consideration by the participant in the timing of itsInterconnection Request with the CAISO. We encourage participants to reduce the uncertainty by starting the Interconnection process early.
13)Please explain how the Participantand PG&E should deal with interconnection issues if the project's nearest point of interconnection is a substation or line not identified on the proxy list? (4/21/08)
The station that is closest to the project's proposed interconnection point should be used.
14)Is there a process to request additional proxy sites? (4/21/08)
Yes, but it is an annual process linked to the annual renewable resource solicitation cycle and won’t be available in time for this solicitation.
15)At the time the Offers are due, some projects will have an interconnection study completed while others will be within CAISO’s queue. Does the relative position in the queue or the fact that a participant has a completed study impact PG&E’s assessment of the value of an offer? (4/21/08)
Yes. Those furtheralong in the process will score higher on project viability as the surety of meeting their online date is greater. Also having completed interconnection studies provides the participant more cost information to be used in the preparation of itsoffer.
16)Specifically, if a given substation’s capacity has been subscribed by baseload power generation under the CAISO process, does that mean that later peaking and intermediate duty assets will be charged required transmission upgrades when PG&E has expressed preference in this RFO for such assets? (4/21/08)
Transmission access and cost allocation is determined by the CAISO interconnection process. The CAISO process is not modified simply because PG&E has identified a preference for certain types of resources.
17)Please review & explain Table 1. Transmission Proxy Costs. (4/21/08)
The Transmission Proxy Costs table includes three types of transmission network costs 1) voltage support, 2) Peak/Shoulder Period network upgrades, and 3) Night/Offpeak network upgrades. These costs are presented for different levels of incremental generation additions.
18)Is the 1,100 lbs/MWh CO2 emissions restriction only for 60% Capacity Factor (CF) or greater, or for any unit? In other words, are you accepting Offers from standard simple cycle CTs or not? (4/21/08)
CPUC Decision 07-09-039 places the Emission Performance Standard (EPS) cap of 1,100 lbs/MWh CO2 on “baseload” resources. Baseload resources are defined to have a Capacity Factor of at least 60%. Peaking generation should not trigger this standard, but each offer will be evaluated individually for EPS compliance.
19)With regards to Appendix J-6(b), can you please expand upon the new or proposed GHG limits issued by CARB under AB32? We are not aware of any to date. Will PG&E bear the change in law risk associated with AB32? (4/21/08)
AB32 requires reporting and verification of GHG emission limits. SB1368 sets those limits. The California Air Resources Board (CARB) has not yet determined who the GHG point of regulation will be: the LSE or the generator. The CPUC’s recommendation to CARB placed this burden on the generator.
Change of law risk assignment is a contractual issue. We are requiring Participants to provide information in Appendix I1 which includes separate Capacity pricing for PG&E accepting GHG risk and Capacity pricing when the Seller takes GHG risk.
20)For repowered QF facilities, does the minimum offer size (20MW) requirement include existing generation? Ex. Facility was upgraded with new gas turbine/generator with output 17MW greater than the old CT/Generator, but only contracted for the old unit output (28MW). New total = 28 + 17 = 45. (4/21/08)
For repowered QF facilities, the existing generationwill count toward the 20MWminimum offer size. We will want to know both the original MW and the repowered MW.
21)Please explain how the GDP implicit price deflator was selected as an index. How does the GDP implicit price deflator correlate to the increases recently (last 2-3 years) experienced in power plant construction?
Will PG&E consider Offers based on other indices that more closely represent the inflation specific to power plant construction. (4/21/08)
The GDP Implicit Price Deflator is a broad based easily recognized economic index covering the entire US economy including wages, goods and services. To the extent prices have escalated, it will ultimately be reflected in the GDP Implicit Price Deflator. In addition, the GDP Implicit Price Deflator is transparent and the information readily available to Participants. PG&E will not consider Offers using other indices.
Participants should incorporate an increase in power plant pricing into their offer and may adjust the portion of pricing where the Index applies accordingly.
22)Given current commodity price volatility can we use a multiple of GDPIPD? In other words, can it escalate by 2 X GDPIPD or 5X GDPIPD? (4/21/08)
PG&E will accept Offers that use only the GDP Implicit Price Deflator as a component of the pricing. Offers cannot be escalated at a multiple to the GDP Implicit Price Deflator.
23)Although not required, does the offerneed to include a gas supply plan? (4/21/08)
No. For new gas-fired facilities, PG&E will be providing the gas under a tolling structure.
24)The PG&E generation characteristics for a shaping or load following plant does not request fill-in data for capacity at 10 minutes from start. Does this imply that 10 minutes capacity is not part of the evaluation? (4/21/08)
Dispatchability and flexibility are factors in the evaluation of the Offers. However, Participants can define the generation characteristics of their specific asset.
25)How does PG&E define hot start time in 90 minutes as referred to in
D. Facility Ownership: Generation Characteristics, II. Shaping or Load Following Generation: 3. Maximum allowable hot-start time of 90 minutes, including all pre-ignition purges, if applicable, and other permissives, on page 8 of the Solicitation document? Is that meant to be to emission compliance or to 100% capacity? (4/21/08)
Participants can define hot-start in accordance with the capabilities of the equipment used in their offer. However, variations from the preferred parameters will be less attractive.
Hot-start is meant to be from start to 100% capacity.
26)Will PG&E accept Offers with annual hours limited to 4,000? 3,000? (4/21/08)
Yes, but the offer will not be as attractive as anoffer with more hours.
27)For PPAs - Will PG&E accept Offers for capacity in Peak and Shoulder hours only, i.e. 6x16 block? (4/21/08)
Yes, but the offer must be tied toconstruction of a new asset, unless it is a QF. In addition, flexibility and dispatchability of the asset are key evaluation components such that a 6X16 block of energy will not rate as wellasOffers that providecomplete dispatchability.
28)Why does PG&E require financial detail on Appendix K, Tables A&B, for a PPA? If Participant declines to submit that detail, will the offer be deemed nonconforming and rejected? (4/21/08)
Financial viability of the Participant and its sponsor(s) is a key metric in considering ability of the project to get to commercial operation. The information requested in Appendix K allows PG&E to assess the financial viability of the Offer.
29)Whose protocols will you use to determine cost of GHG? (4/21/08)
We have examined the literature from a number of sources but have not made a final decision on the GHG cost to use in the market valuation.
30)If a facility is biomass fueled, but exceeds 1,100 lbs/MWh CO2 is it disqualified from the RFO Process? (4/21/08)
No, a biomass facility is exempt from this requirement.
31)What is the dollar cost per ton assumed in your cost of GHG emissions (4/21/08)
This value has not been fixed yet. We currently assume approximately $10/ton in 2009 and escalated in later years. We will fix an emission cost curve at the same time other input parameters are frozen for thisRFO.
32)Is there a preference for turbine/generator technology? (manufacturer)? (4/21/08)
No. The more proven technology will receive a higher score in Technical Reliability and a renewable technology will do better in support of Environmental Leadership.
33)Describe the significance of project dispatchability when making your selection? (4/21/08)
Dispatchability translates into optionality.The greater dispatchability, the more flexibility and higher value forPG&E, all else being equal.
34)Will evaluation factors from proprietary software be released? How can we submit the best offer to PG&E without these? (4/21/08)
No. PG&E doesnot release proprietary models. Projects which provide high flexibility at low cost will receive favorable market values.
35)Please comment, generically, on the weighting that will be used for the evaluation criteria, i.e. what greatest weight, least weight. (4/21/08)
The final weighting has not been decided. However, Market Value(price) will receive the greatest weight and likely be at least half of the total. The remaining criteria will be given approximately equal weighting.
36)What is the percentage value of ancillary services versus capacity and energy? (4/21/08)
Ancillary Servicesis a small percent of total market value, but we do not have a fixed percentage.
37)If assets are retired or replaced, how does this affect the evaluation? (4/21/08)
If a new facility hastens the retirement of a less efficient or higher polluting facility, this will improve the score on Environmental Leadership. Additionally, to the extent that a current asset is being replaced, PG&E will take into account the improved viability of the project because the site has previously had generation located there as well as the possibility that transmission upgrade costs may be reduced and/or avoided.
38)After the cumulative security posting has been made subsequent to CPUC approval, under what conditions will the security deposit be refunded? (4/21/08)
For a PPA, at any point in time after the Initial Delivery Date, to the extent that cumulative security/collateral posted by counterparty exceeds the Collateral Requirement as outlined in the PPA: Appendix F, the excess, if any, shall be returned to counterparty provided no Event or potential Event of Default has occurred or is in any stage of occurring at any point in time. The executed PPA shall ultimately guide Terms and Conditions of transaction.
For a PSA, shortly after execution by counterparty, and receipt of all documents, in form and substance acceptable by PG&E for successful closing and concurrent legal transfer of ownership in constructed facility, with all appropriate, and financially supported warranty documents referencing PG&E as sole beneficiary provided no Event or potential Event of Default has occurred or is in any stage of occurring. The executed PSA shall ultimately guide Terms and Conditions of transaction.
39)Why have credit requirements increased nearly 50% from the 2004 RFO? (4/21/08)
Market uncertainty, volatility and a changed credit landscape have necessitated a re-evaluation of risk profiles and increased credit requirements.
40)Please describe what can and can’t be escalated from a capacity payment perspective. (4/21/08)
Refer to Section E. Contract Options, III. Indexed Pricing, of the Solicitation Protocol for description of the parameters, which may be escalated.
41)For historical temperature data, may we use periods other than the previous 10 years, e.g. 1971-2000? (4/21/08)
Recent historical data is readily available from the NationalClimaticDataCenter (“NCDC”) at
PG&E would prefer more recent data.
42)Do security deposits roll over to Collateral Requirements or are they additive? (4/21/08)
The Offer Deposit can be rolled over to any subsequent collateral/security posted by counterparty to PG&E prior to and subsequent to CPUC approval (but prior to commodity Initial Delivery Date or facility Closing Date) Consequently, counterparties who have provided a successful offer accepted by PG&E and subsequently approved by the CPUC are expected to have provided upon CPUC approval a cumulative collateral/security amount equal to, at minimum, $100 per KW(either in the form of cash via wire transfer or Letter of Credit in the form of Appendix C) based on the maximum monthly capacity as outlined in Appendix I.
43)What determines 3 year or 5 year rolling term for Collateral Requirements? (4/21/08)
Collateral requirements for assets that have relatively short development and construction time such as simple cycle CTs will be 3 years and collateral requirements for longer lead time assets, such as combined cycle facilities, will be 5 years.
44)Once the $100/KWis posted what if the participant is not able to get permitting? (4/21/08)
Failure to achieve permits after CPUC Approval but prior to commercial operation which results in Termination will subject the Sellerto the Pre-COD Settlement Amount. It is worth noting that this is a change from the Term Sheet requiring payment of the higher of Settlement Amount or Pre-COD Settlement Amount. This change will be made in the PPA and PSA documents posted on May 9.
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