1)Page 11 of the RFO, First Bullet Point Indicates, a Participant Shall Indicate in Its

1)Page 11 of the RFO, First Bullet Point Indicates, a Participant Shall Indicate in Its

July 17, 2008

Q&A from the 2008 All Source LTRFO Mailbox

1)Page 11 of the RFO, first bullet point indicates, “…A Participant shall indicate in its Offer an initial price for each of these components. If the Participant elects to use indexed pricing, the Participant should indicate that the initial prices for all or some of these components will be indexed to the GDP Implicit Price Deflator for the period of time from when the date the Agreement is executed by PG&E through the term of the Agreement.” [emphasis added]

  1. Where in Appendix H-1 and I-2 should a participant indicate the “initial price”?
  1. If inflation adjusted pricing is selected, should the participant only enter an initial price or should each contract year of the Appendix H and I-2 be entered with a value in real dollars (ie: the same as the initial price) which PG&E would then escalate?
  1. Appendix H-1 does not exactly match the “Compensation” schedule of Appendix I-2.
  1. Does PG&E want the Participant to include the VOM cost break-out for duct fire and power augmentation in Appendix H-1 as well as where requested in Appendix I-2? If yes, where in Appendix H-1? If no, is the VOM cost to be shown in Appendix H-1 only the Base Load VOM in Appendix I-2?

For these four items, See Q&A #1 of the Questions After the Workshop on the last page of the set of Q&As posted June 19, 2008.

  1. In Appendix I-1 “Compensation”, is the VOM for duct fire and power augmentation columns intended to be incremental to the Base Load VOM column or are these columns to replace the Base Load column when operating in those modes? Can duct fire and power augmentation costs be entered on a $/hour basis instead of a $/MWh basis?

The Variable O&M costs for duct firing and power augmentation should be shown as incremental amounts, and should be entered on a $/MWh basis.

2)Start Charge

  1. Is Section 4.4 of the PPA the only place where is the start charge to be entered? It is not provided for in Appendix H-1 or I-1.

The Start-Up Rate should be entered in Section 4.4 of the PPA and in the Characteristics tab of Appendix I-1, in the Cold Start Costs, Warm Start Costs and Hot Start Costs columns

3)Capacity Price

  1. Appendix H-1, note 1 indicates capacity price is to be based on capacity at ISO conditions. Should ISO conditions be used to fill out the “Compensation” tab of Appendix I-1 as well?
  2. The capacity and fixed O&M prices that are to be entered in the blanks in Section 4.3(a)(i)-(ii) of the PPA for payment by PG&E is a function of the MCC (as opposed to the capacity at ISO conditions) and the Appendix IV monthly allocations. The capacity price and fixed O&M price in the PPA will not equal the capacity price and fixed O&M price in Appendix H-1 (and, maybe, I-2 depending on the answer above). Is PG&E ok with receiving different capacity and fixed O&M numbers in different sections of the response?
  1. Can ISO conditions adjusted by the Appendix IV monthly allocations be used to calculate monthly capacity payments instead of using the MCC due to the inconsistency it creates between the RFO and the PPA? It will be the same total dollars from PG&E to the project.

Appendix H-1, note 1 is incorrect. $/kW-year values entered into Appendix H-1 should not reflect ratings at ISO conditions. Rather, the $/kW-year capacity prices should reflect the initial Monthly Contract Capacities entered into Appendix II of the PPA, and expectations of future adjustments to those MCCs. The capacity prices in Appendix H-1 and the Compensation tab of Appendix I-1 should match. See also Q&A #11 (ii) to the set posted on May 19.

4)Please provide a sample calculation of the mark to market calculation using actual numbers and specify the source of the “forecasted index” that should be used for the calculation in Applicant’s PPA.

PG&E's forward price curves are proprietary. The following sample is based upon illustrative data. The Excel version is available by following the link below:


Applicants should use their own forecasts for the MIV calculations and for the GDP Deflator.

5)With respect to §3.5(c), Deviation Charges, please clarify whether Seller can be exposed to deviation charges under the contract where instructions from CAISO have the unit at an operating point other than the Schedule submitted by PG&E as the SC. Specifically, it appears that CAISO instructions are not Operational Orders (CAISO is not a Governmental Authority) and reference to Seller’s obligations to CAISO under PGA appears specifically an narrowly limited to Emergencies and reliability needs / voltage support—information that Seller will likely not be able to discern at time they receive instructions from CAISO (as opposed to any dispatch instruction made by CAISO generically).

“Instructed Operations” means (i) an Operational Order, (ii) a mandatory direction of the Transmission Provider or (iii) as required pursuant to the Seller’s CAISO Participating Generator Agreement (explicitly incorporating Section 5 of the CAISO Tariff as in effect as of the Execution Date or any revision thereof) to meet Emergencies and reliability needs including voltage support.

“Operational Order” means a mandate issued by a Governmental Authority which the Seller has no discretion to ignore or avoid to offer or provide a Product or to Start-Up, Shut-Down, curtail or operate a Unit. An Operational Order would include, for example, a mandate issued by the U.S. Secretary of Energy to offer Capacity or Energy or to operate a Unit during an Emergency. In contrast, by way of further example, a legal obligation to test a Unit for the purpose of maintaining its Governmental Approvals is not considered an Operational Order.

“Governmental Authority” means any federal, state, local or municipal government, governmental department, commission, board, bureau, agency, or instrumentality, or any judicial, regulatory or administrative body, having jurisdiction as to the matter in question.

“Scheduled Energy” means Energy generated in response to Scheduled Operations and delivered to Buyer at the Electrical Delivery Point for its account.

“Scheduled Operations” means operation of a Unit as required to satisfy Buyer’s Schedule (including Instructed Operations).

Buyer shall provide Seller with "Buyer's Schedule" which includes Instructed Operations.

For more information, refer to Section 3.1(b)(vi) which states:

"Subject to the reporting requirements of Section 3.5, nothing herein shall bar Seller from complying with Instructed Operations; provided that if Seller receives an Instructed Operation other than through Buyer, it should advise the entity issuing the instruction that such communications are to be made to its Scheduling Coordinator, and in any event, Seller shall promptly report such event in accordance with Section 3.5(b)."

Further, "Seller acknowledges and agrees that Buyer may take whatever measures it elects to protest, challenge, eliminate, institute or modify any Instructed Operation, which may include communicating directly with the Governmental Authority or Transmission Provider, as applicable, responsible for such Instructed Operation."

If the Unit is offering Ancillary Services and the CAISO is moving the unit in real time, then Buyer's Schedule will reflect the generation schedule (also known as the expected energy amount which includes PG&E's energy +/- the CAISO instruction).

6)For a proposal to convert an existing QF contract to the EEI form of agreement, is the offer deposit only required for the incremental amount of capacity?

The Offer deposit should be based upon the amount of gross capacity being bid into the LTRFO.

7)The RFO overview identifies 5 resources which can be offered through this process. One of them is Existing Qualifying Facilities (QF’s) however other existing facilities would have to be repowered to comply with the bid protocol. If a participant has facilities in NP-15 which will not be contracted to deliver energy or capacity to any counterparty at the end of 2011 which have a low number of total operating hours, are already permitted to operate well in excess of 4000 hours, will not be repowered and can be available in 2012 can these units be offered and deemed compliant with the RFO.

No, the participant’s facilities in NP-15 described above would not be eligible for the All Source RFO.

8)Am I correct that if I am unable to obtain Site Control within 8 weeks after being shortlisted (probably because the land owner gets greedy when I continue to negotiate after the short-list date), I will be “rejected” and the Offer deposit returned?

If your Offer is shortlisted and you are unable to obtain site control within 8 weeks after shortlisting, your Offer will be non-conforming. A decisionon rejecting theOffer will be made at that time.

9)Just to clarify - So if a power plant has an MCC of 400 MW for a given month. On a given day, given hour, and projected temperature of say 90°F, the base load scheduled is, say, 390 MW. The actual temperature for that hour comes in at 100°F so the power plant runs below schedule at 387 MW. Heat rate does not change in this example.

For that hour the unit experiences:

  • 3 MW negative deviation.
  • 3 MW MCP purchase from the CAISO for the imbalance energy.
  • A gas payment (revenue to the generator from PG&E) based on 15% of the gas price over the 3 MW gas equivalent imbalance volume.
  • A decrease in the monthly availability calc based on a (prorated) 3 MW deviation for that hour.

In this negative deviation scenario, in addition to paying for CAISO balancing energy to true up the schedule, the generator also gets hit with a decrease in the monthly availability.

Is that right?

The bullet points shown above are correct with the following clarification.

If the daily gas imbalance amount exceeds 1%, then the generator will receive a gas credit based upon 15% of the Gas Index Price - Low over the 3 MW gas equivalent imbalance volume.

The generator may also be subject to penalties.

10)If seller desires to have Gas delivered to have Gas delivered to it other than the Buyer's Gas, it may provide Notice pursuant to Section 3.3(e) for Additional Gas. If such Notice is not received timely, it appears that Seller is subject to a Section 3.3(f) Balancing True-up. However, it is not clear what timeframe constitutes timely receipt of Notice. Please advise.

The timeframe for Notice would depend on the scheduling timeline for the applicable Local Distribution Company and on the pipeline conditions for the gas flow day. In general, Notice would be timely if provided prior to the first scheduling cycle (the day before the gas flow day).

11)Please confirm that you are asking for Net Plant Heat Rate and Net Plant output when one unit is in service on form Appendix I1 when the facility is a simple cycle peaking plant with multiple identical units.

Correct, that is what PG&E is asking for when one CT unit is in service.

12)In Appendix I1, in the characteristics tab, you request a Cold Start Cost, Warm Start Cost, and Hot Start Cost. It would appear from the instructions for that tab that you are requesting the bidder estimate this number based on the start-up fuel submitted and some estimate of a gas price. Is that correct?

Or are you looking for a starts-based cost as outlined in the PPA, Section 4.4 “Start-up Payment?”

The Cold Start Cost, Warm Start Cost, and Hot Start Cost entered into Appendix I-1 should be the Start-Up Rates specified in Section 4.4

13)What phone number shall we use for the Letter of Credit?

For the Letter of Credit, please send it Credit Risk Management to the attention of Kenneth Lock. His phone number is 415-972-5188.

14)At the Bidders conference, my recollection is that there was discussion about removing this requirement that "PPA Offers ... shall include" both GHG options, and that it would be acceptable to offer only one or the other. The latest PPA form is somewhat unclear - Section 9.3 states "[Note: inclusion in Agreement dependent upon Buyer’s Compensation Rate selection pursuant to Section 4.3.]" but it doesn't state that both versions must be offered. (It doesn't state whether Buyer or Seller is making the 'selection'.)

PG&E has decided to leave in place the requirement that PPA Offers must include pricing with Section 9.3 in place and pricing without Section 9.3 in place. PG&E will select which pricing option to use in executed Agreements.

15)We note that a new PPA and Appendices were posted on 7/7/08. It is our understanding that none of the Appendices to the PPA have changed since the 6/13/08 version. Is that correct? For purposes of redlining the PPAs, it would facilitate the process to be able to redline against a single file that includes the PPA and all of the Appendices as a single file (as the 6/13/08 version was set up). Can you email us the PPA and Appendices in a single file (which will probably need to be a zip file as the PPA file size is over 30 MB and exceeds our email server limit)?

The Power Purchase Agreement has been reposted onto PG&E’s website with the July 3, 2008 date. There have been no other changes to the PPA as of that date.

16)For Appendix X to the PPA, the lender consent, we may have missed it, but there does not appear to be a cross reference to this Appendix in the PPA. Where is this used? Also, is PG&E expecting to provide the form for this consent or should we insert a form of consent from our lender?

You are correct; there is no reference to this Appendix in the PPA. If you have a form of consent from your lender, please include it with your Offer. If not, it can be added later.

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