2005 Renewables RFO Questions and Answers

(August 26, 2005)

Q&As 1-27 issued 8/26/05 in response to questions received at the August 18, 2005 RPS Bidders Conference.

1. Is there any chance for a delay or extension on the September 15th deadline? (8/26/05)

No, PG&E must receive both the electronic and hard copies of the Offer documents no later than 3:00 p.m. Pacific Prevailing Time (PPT) on Thursday, September 15th. PG&E aims to maintain a 6-week window between the issuance of the solicitation and the deadline for bid receipt. In its August 4th press release, PG&E had indicated that binding bids are due by September 15th as it is the companys goal to enter into contracts by the end of the year.

2. Can you clarify the bidding and development security requirements? (8/26/05)

No security is required upon bid submittal. Bidders are required to post a bid deposit of $3/kw no later than five (5) business days after receiving notice from PG&E that the bid qualifies for PG&Es shortlist. A $20/kw security deposit for the projects development period is due within 30 days of CPUC Approval of the PPA (as that term is defined in the PPA). The $3/kw bid shortlist deposit may rolled over and applied to the $20/kw project development period deposit. Please see Section X.C. of the Protocol for the complete listing of PG&Es preferred security posting, Article Eight of the applicable PPA, or if offering a Turnkey option, the credit provisions of the term sheet.

3. Please discuss your projections of costs over the next 5, 10, 15 years. A) Key factors influencing your projections, and B) quantity, if possible. (8/26/05)

PG&E does not provide its forward curves as this is confidential and proprietary information.

4. What is PG&Es credit standing/creditworthiness? (8/26/05)

PG&Es senior unsecured long-term debt rating is BBB from Standard & Poors, Baa1 from Moodys, and BBB+ from Fitch.

5. Will PG&E consider proposals that contemplate a COD after 2010, or a phased COD, with some units operating before 2010 and others coming on-line after 2010? (8/26/05)

PG&E will consider proposals with varying commercial operation dates, but strongly prefers CODs prior to 2010.

6. May bidders propose alternate delivery points for the same project? (8/26/05)

Yes, bidders may propose alternate delivery points for the same project. PG&E prefers the delivery point to be NP-15, but will allow bids that propose delivery of the product to SP-15, ZP-26, or any other delivery point in the CAISO Control Area that qualifies as an SC-to-SC transfer. A bid for out-of-state delivery would be a non-confirming bid and considered on a case-by-case basis.

7. Is there a minimum project size? (8/26/05)

To be eligible for consideration in PG&Es 2005 Renewables RFO, all products offered must be at least 1 MW or greater, and dispatchable products must be 25 MW or greater. Bidders may aggregate multiple projects to meet the 1 MW minimum. Any unit aggregations needed to achieve the 1 MW or greater requirement would remain the responsibility of the seller. The aggregation for scheduling, delivery and settlements may occur through the CAISO unit aggregation provisions, or through the sellers own Scheduling Coordinator aggregation process, at the sellers discretion and subject to applicable CAISO requirements.

8. What were the MPRs for 2004 and 2005? How were they determined? (8/26/05)

The CPUC is required to establish the Market Price Referent (MPR) after the closing date of a competitive solicitation for renewables. The 2004 MPR was established by CPUC Resolution E-3942, which is provided through the links below. The resolution describes the derivation of the MPR. For a 20 year contract commencing deliveries in 2005, the baseload MPR was set at 5.99 cents /kWh and the peaking price was set at 11.33 cents /kWh. PG&E cannot speculate as to the 2005 MPR.

Public links:
http://www.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/48242.htm
http://www.cpuc.ca.gov/word_pdf/FINAL_RESOLUTION/48242.doc

9. What does the MPR mean? (8/26/05)

The market price referent (MPR) is a price benchmark that serves two purposes: 1) it establishes the maximum long term contract price that the utility is obligated to pay for renewable power, and 2) it provides that utility payments for contracts signed at or below the MPR will be recovered in rates. If the contract price is above the MPR, application may be made to the California Energy Commission (CEC) for supplemental energy payments (SEP) to cover the difference.

10. Is hydro considered renewable? (8/26/05)

A hydroelectric facility of 30 megawatts (MW) or less (“small hydro”) is an eligible renewable resource. If its generation was owned or purchased by a utility before September 12, 2002, its output will classified as "baseline" rather than be the “incremental” renewable generation. PG&E expects to procure both incremental and baseline renewable resources because both will contribute to PG&E’s 20% renewables goal. If the small hydro facility began operation after September 11, 2002, it is not eligible if it requires a “new or increased appropriation or diversion” of water. The following three CEC Guidebooks provide more detail:

(1) Renewables Portfolio Standard Eligibility Guidebook, which addresses RPS eligibility and certification;

(2) New Renewable Facilities Program Guidebook, addressing SEP payments; and

(3) Overall Program Guidebook for the Renewable Energy Program, addressing program administration.

Links to these Guidebooks are provided in PG&E’s 2005 Renewables RFO webpage.

11. Will PG&E be providing a list of all conference participants? (8/26/05)

No, this list will not be provided.

12. How big is PG&Es RPS group? (8/26/05)

The RPS group is small and select. Experts from various business lines within PG&E form a core group that outsources internally, if necessary.

13. How much energy does PG&E expect to shortlist? (8/26/05)

PG&Es Incremental Procurement Target is 1% of retail load. However, PG&E is not constrained by this amount; we can procure greater or lesser amounts depending on the quality of the bids. Thus, bidders should not be constrained by this amount either. PG&Es total RPS goal is 20% of retail load (PG&E is currently at approximately 13%). PG&E expects to shortlist the number of projects that will enable it to procure at least 1-2% of its retail sales volumes or between approximately 700 and 1400 GWH/Year.

14. How are repowering projects, or projects which terminate Standard Offer (SO) contracts, considered relative to the goal of procuring 700-1400 GWHs/Year? For example, such projects will add less incremental energy to the PG&E system. Does the goal of procuring 700-1400 of incremental make repowering less attractive? (8/26/05)

PG&E expects to procure both incremental and baseline renewable resources because both will contribute to PG&Es 20% renewables goal. Proposals to terminate SO contracts or repower facilities are welcome and will be considered and evaluated with equal footing to other bids.

15. What drives the seasonal pricing for time of delivery factors, in particular the low point in March-May? (8/26/05)

PG&Es seasonal time of delivery factors are based on market information, including the forward price curve for future delivery. The forward price curve reflects market forces. PG&E does not have a proprietary view of its appropriate level. Historically, seasonal hydro flows have led to lower energy prices in springtime than at other times of the year; this may be reflected in the forward price curve.

16. Is evaluation of portfolio fit (20%) as simple as comparing type of offer (e.g. as-available) to portfolio needs? Or will PG&E consider the shape of as-available resources, for example? (8/26/05)

PG&E will consider the shape as well.

17. If technology is certified out-of-state, will we still need California certification? (8/26/05)

Yes. Each facility must be certified as an eligible renewable resource by the CEC in order to deliver power to PG&E pursuant to the RPS solicitation.

18. Can you offer less than the full capacity for a power plant and sell the surplus separately? (8/26/05)

PG&E prefers that the entire output of a power plant be sold to PG&E. PG&E may permit a generator to sell a portion of its output to third parties so long as the terms and conditions of the product schedules and deliveries to PG&E have been specified sufficiently in the generators Offer and the resulting Master Power Purchase and Sale Agreement with PG&E, so that an objective determination of the generators firm obligations to PG&E can be made in advance of the proposed sale to third parties.

19. Will PG&E accept proposals from “hybrid” renewables? What are the contingencies for odd-lot power? Co-fire fuels? New technologies? (8/26/05)

PG&E will only accept proposals from eligible renewable resources as defined by the CEC. Please consult the CECs RPS Eligibility Guidebook for guidelines for hybrid projects. The CEC will allow two alternatives for eligibility of new and repowered facilities that operate on co-fired fuels or a mix of fuels that includes fossil fuel:

  • a. If the facility is certified as a Qualifying Small Power Production Facility (QF) under the federal Public Utilities Regulatory Policies Act (PURPA), then 100 percent of the electricity production from the facility may count as renewable provided the facility satisfies the fossil fuel use limitations specified in PURPA and the facility otherwise satisfies the applicable California RPS standards.
  • b. If the facility is not certified as a QF, then only the electricity generated from an eligible renewable resource will be deemed responsive to PG&E’s RPS solicitation, and may be accepted by PG&E if the output can be tracked to the eligible resource.

20. Will you accept bids that dont conform to the standard terms and conditions? (8/26/05)

Yes. Bidders may submit bids that dont conform to the standard terms and conditions. Such non-conforming provisions will be reviewed on a case-by-case basis. Bidders should note that certain contract terms have been deemed by the CPUC as non-modifiable. These sections are noted in Appendix A of CPUC Decision 04-06-014.

21. If proposing a turnkey ownership offer, do we need to offer a PPA offer as well? (8/26/05)

No, a PPA does not need to accompany a turnkey ownership offer. A PPA offer does, however, need to accompany a buy-out offer

22. Can buy-out option allow for phasing; e.g., PG&E buys gen-tie and later facility? (8/26/05)

PG&E will allow phasing of an entire facility only, not just a part of a discrete project.

23. What if gen-tie can be used to serve a local load and not just be a gen-tie? (8/26/05)

There are two parts to this question depending on whether the transmission facilities in question was identified as part of the PG&E network in the System Impact Study/Facility Study associated with the generator when it was going through the ISO Interconnection Process. If the transmission facility was originally identified as a Network Facility, the facility would be owned by the utility, subject to financing by the developer and the utility’s scheduled reimbursement of the developer over 5 years. If a transmission facility was originally identified as a gen-tie, but later could be used to serve a customer load, then it would depend on PG&E's determination of whether using this particular transmission facility would be the best option from the ratepayer perspective compared to other options available at the time.

24. Do buyout options allow for going forward operations contracts? (8/26/05)

Yes. PG&E will consider going forward operations and maintenance contracts as part of a buyout option

25. Is PG&E open to offer for co-development / co-ownership alternatives? (8/26/05)

PG&E will consider co-development/co-ownership alternatives on a case-by-case basis.

26. In the Transmission Ranking Cost table, what does the “level” column refer to? (8/26/05)

The Levels represent possible transmission capacity available to accommodate potential incremental generation addition before triggering the next level of transmission upgrade. Levels are described in D.04-06-013, Page A-5:

  • “For each cluster, the subject utility shall identify levels of transmission capacity and related costs according to the following order:
  • (i) Level 1-the transmission capacity expected to be available, which may include upgrades identified for projects in the IS0 interconnection queue with completed System Impact Studies and Facility Studies which were included in the base case in the utility's conceptual transmission studies.
  • (ii) Level 2-the transmission capacity expected to become available with the lowest cost (or most cost-effective) network upgrade in addition to upgrades included in Level 1. An additional level shall be created for each next most cost-effective network upgrade, with the number of levels depending on the number of network upgrades needed to accommodate the total amount of generation in the identified cluster.”

27. How will PG&E address assumptions made in the Transmission Ranking Cost Report which are no longer valid; e.g., projects in queue that have dropped out? (8/26/05)

First, the Transmission Ranking Cost Report (TRCR), as directed by the CPUC, is to be used exclusively for the purposes of providing information for developers to structure and submit their bids and for PG&E to rank the bids and develop a short list. The application of any bid adder to a project under the TRCR process does not determine the projects actual responsibility for transmission upgrade costs. Successful bidders must complete the CA ISO Generation Interconnection Process. It is in that process that the Network Upgrades costs would be determined. Changes in assumptions are addressed in that process for individual generation projects.

Solely for the purpose of rank ordering bids in accordance with their least-cost best-fit results, the CPUC has provided the following direction to account for the capacity represented by projects that have dropped out of the CAISO queue:

  • "Before undertaking the second ranking of RPS bids, each subject utility shall adjust its transmission cost estimates for each level of transmission specified in its Transmission Ranking Cost Report, if needed, to take into account any generation projects that have been added to or deleted from the IS0 interconnection queue, any System Impact or Facilities Studies submitted with bids, or any other change to the transmission system not anticipated at the time the Transmission Ranking Cost Report was prepared. The subject utility shall document these changes in its advice letter submitting proposed RPS contracts to the Commission." (CPUC Decision 04-06-013, Attachment A, p. A-8, Item 2.)

PG&E will accordingly adjust the available capacity at each transmission cluster for which additional capacity has either become available or is no longer available, due to one or more of the changes enumerated by the CPUC. PG&E will not re-configure the entire transmission ranking cost report to embed these analyses in a revised report. Otherwise, bidders would have no stable point of reference for project planning. PG&E observed this practice for the 2004 RPS solicitation and will continue its practice for the 2005 RPS Solicitation.

For example, assume Level 1 at one cluster has available transmission capacity (without upgrade) of 200 MW. Before the second ranking (in which transmission adders are applied), if one 100 MW generator in the queue at the same cluster dropped out, then transmission capacity available associated with Level 1 for that cluster would then be 300 MW.