2006 RPS RFO: Questions and Answers

This initial posting has questions and answers from the Bidders Conference.

RPS Pre-Bid Conference of July 20, 2006

1) Question: My understanding is that SEPs (Supplemental Energy Payments) are still only available pending the funds actually being available, which obviously presents enormous financing challenges to developers for those developers whose price is above the MPR.Is PG&E doing anything to help that issue move forward?How can we as a developer push to get this critical issue fixed at the legislative level?

Answer: Yes, we participated in that hearing at the CEC. We have raised the issue with the CEC and the CPUC, basically from feedback that we have received from bidders and projects.There is also a bill in the Legislature for some RPS matters, and we, in cooperation with some other parties have drafted language for that bill that we think would solve the problem that would allow the State to escrow those funds.  We recommend that you also contact the California Energy Commission on that issue because that is an important issue.

2) Question: Does PG&E actually prefer to purchase projects due to credit considerations?For example, a PPA constitutes a liability, so is there a penalty applied to PPAs?

Answer: There is no preference between ownership and PPA.

3) Question: How does PG&E determine remarketing or the cost of a swap?

Answer: We do evaluations at multiple locations and the difference between the values between two locations is the cost of doing the swap.

4) Question: How do you value capacity?In other words, when comparing an as available resource to a firm baseload resource, what is the incremental capacity worth to PG&E?

Answer: The capacity value of a baseload resource is determined based on its contribution to PG&E’s Resource Adequacy Requirements (RAR).  Relative to baseload, as-available resources are derated based upon the provided generation profile.

5) Question: For a project using the TRCR, does the bidder need to estimate the cost of upgrades needed to bring power to a given cluster, assuming the interconnection point is not the same point as the cluster?

Answer: No, the bid evaluation is based only on the Transmission Ranking Cost from the Clusters. For bid evaluation purposes, PG&E will assume that the cost to bring power to the interconnection point is internalized within the bid.

6) Question:In the TRCR example in the presentation, how are transmission costs added to each bid, and at what point is each bid ranked to determine the cost adder?

Answer: In accordance with CPUC Decision 04-06-013, the bids are first ranked on market evaluation and the other scoring criteria excluding transmission costs. The bids are then re-ranked to include transmission costs.The lower cost (or higher value) bid in the first ranking would receive priority on transmission in the second ranking.  So in the example in the presentation with the comparison of Offer A and Offer B, assuming that Offer A is higher value than Offer B, Offer A would receive priority on transmission.

7) Question: Is the transmission cost information made available to the bidder?

Answer: Not information on other bidders. If the question is, will be the bidder know where they are ranked, whether they are A, B, or C, the answer is no.

8) Question: Is the bidder’s ability to perform taken into consideration when allocating transmission costs?

Answer: No.

9) Question: If a solar thermal electric plant offers a hybrid configuration that includes a natural gas boiler, will there be a limitation on (a) the annual gas use and (b) the plant capacity?Are such limits imposed because the plant would need to be a QF under PURPA?

Answer: Under today’s QF rules, if the project is 80 Megawatts or less, then it can use fossil fuels to produce 25% or less of its total production. In such a case, all 100% would count as renewable energy if it were a certified QF.

10) Question: For plants greater than 80 Megawatts, larger than QF, will gas generated energy be eligible for renewable qualification under RPS?If not, how will pricing be developed for the gas portion?

Answer: Per CEC rules, the portion generated by gas is not RPS eligible for facilities over 80 Megawatts. The developer may propose various options, whether all green or green with gas.  And you have the ability to do that through the multiple offer variations.So, if you are above 80 Megawatts and you want to offer a project with some portion of gas-fired generation, you should offer multiple variations, both with and without the gas-fired portion, in order to improve your chances of being shortlisted.

11) Question: Can delivery be expressed in terms of dispatchable one-time period, for example “super peak” and in another form say “as available” for other periods (for example, for shoulder or night)?

Answer: That is not one of our allowed bid combinations, but we do encourage you to bid both the combination, as well as bid them separately. To the extent the project warrants short listing, we would short list it under one scenario or the other, and only one bid deposit would apply.
Generally, the theme is that we are not going to throw out your bid if it doesn’t meet the letter of the rules. Given the time frames that we are looking at, the easier you make it for us the better off you are. So, you will have to make a judgment whether the non confirming bid producesconsiderably more value than sticking by the rules.

12) Question:If the delivery point is not in NP15, how does that affect one’s bid?

Answer: We will accept delivery anywhere inCalifornia and will consider delivery points at the CAISO interfaces and outside the state.  The contracts themselves are set up for NP15 deliveries. You just need to take that into account when you are marking up the documents.

13) Question: Must the technology be commercial at the time of bid?How much historical data will demonstrate if it is viable?

Answer: Various considerations there include: technology, feasibility, whether there is any such technology commercially up and running, whether it is an eligible renewable resource for the CEC. In terms of when the delivery is required, that is governed by the PPA at the time required in the contract.So you can take that into account in your offer if there is more time required to commercialize the technology.The PPAs are subject to performance requirements.  If the evaluation shows that the project is likely to deliver, then we are more likely to sign.We do want to see proven technology but we don’t want to discourage emerging technologies.

14) Question: What is the expected online date, month, and year?

Answer: That is up to you. It is set by the bidder.But realize that we need to get to 20% by the year 2010.

15) Question: On the ownership option offers, Option 2, why would you want a fixed price Operations & Maintenance bid?O&M is most effectively done on a Time & Materials basis.A fixed price O&M contract incentivizes the O&M contractor to do as little as possible.The fixed price structure misaligns the owner’s and O&M contractor’s interest.

Answer: The reason we want a fixed price is so that we can evaluate the offer against other fixed price offers. Ultimately, that dollar amount is negotiable.

16) Question: The 8-hour call on dispatchable power is a restriction for biogas fuel cell technology.Can this window be negotiated?

Answer: Yes.

17) Question: Will PG&E consider under serviced substations not listed in the clusters?

Answer: Yes. You don’t have to site your plants at those 20 clusters or substations.That is mainly for summary bid evaluation information.We certainly have more than 20 substations.The 20 clusters are meant to aggregate points for areas within PG&E’s service territory for evaluation purposes.You can site your plant and interconnect to any substation, and the evaluation will be based on which cluster is the closest.But your delivery point doesn’t have to be Cottonwood, or Midway, or any of those 20.

18) Question: How will deliverability of projects outside of California be evaluated?

Answer: We want to ensure that the CEC certifies you as eligible. We prefer for something to come to the California border; but to the extent it doesn’t, we will evaluate the cost of transmission wheeling from that point of delivery to California and ultimately look at the total cost to the California customer of bringing that power to load.

19) Question: For ownership Option 3, how will that be evaluated vis a vis a full project?

Answer: We would like you to submit your cost estimate on what it would take to construct a facility on the potential site for development. But we will also do an assessment of what the cost might be to develop a project on that property.So, in terms of the evaluation criteria, we would use any or all of the criteria applicable to the site.  The more information you give us, the better position we are in to evaluate the true value of that site or of that project.So, if you do have cost estimates for a project, it is better to give that to us rather than just offer the site with no information.It is in your interest to give us more information.

20) Question: Slide 16 of the presentation provides capacity factor adjustments.  Does this really mean availability factors?

Answer: For baseload and peaking products, capacity factor adjustment may apply. For dispatchable products, it is availability factors that are used for performance adjustments.You are free to offer a combination of peaking and as available—for a peaking and intermittent combination offer.

21) Question: After being short listed, can the seller change its site location without penalty if it is not changing its interconnection or delivery point?(Without penalty meaning without loss of security deposit or expulsion from the short list.)

Answer: It might be allowable to change the site  without a penalty. We would need to consider the impact on the rest of the offer and whether the offer still holds together.We are not looking to disqualify bidders to keep their deposits, but we do expect bidders to stand up to the delivery prices and terms they bid.Otherwise, the other bidders are disadvantaged.

22) Question: Is one month for contract negotiation a requirement or a goal?

Answer: It is a PUC requirement, but it is subject to some modification and we may see some extension of that one month.

23)  Question: Please elaborate on Table 3.1 of the “solicitation goals” and 1-2% of PG&E’s load.

Answer: 1% of our load is approximately 700 Gigawatt hours. At a 100% capacity factor, that translates to 80 Megawatts.For a 20% capacity factor project that translates to 400 Megawatts to supply 1% of our load.So depending on capacity factor, 1-2% of load could equate to 80 to 800 Megawatts of capacity.There is detailed information listed on that in the green books so you can see the breakdowns that show what 20, 40, 60, 80, and 100% capacity factors translate to in terms of Megawatts.

24) Question:  Can we see the forward price curves?

Answer: No.  Those are proprietary. But you can look up forward prices on ICE or any other public source.

25)  Question:  How does PG&E assess the risk of delivery uncertainty?

Answer: Essentially, we require you to live up to your contract.  The contracts have performance provisions and performance requirements and it is up to you to meet those standards or be faced with performance adjustments.

26) Question: How interested is PG&E in solar?

Answer: Very interested.

27) Question: During what period is PG&E long and short?

Answer: We are a summer peaking utility so peak deliveries fit our need profile. Unit-contingent baseload also can meet our needs.As available, or intermittent, is generally a lower value product, but in our 2004 solicitation most of the contracts we signed were intermittent.We need the energy, and we need it going forward.So, ultimately, we are looking for value, regardless of the product type.

28) Question: Are integration costs equal to zero?

Answer: We did not talk about this today, but, yes, effectively, they’re zero, per the CEC. Currently they are zero.

29) Question: Can we see your evaluations for the 2004 and 2005 solicitations?

Answer: No.

30) Question: Will PG&E frown if we don’t offer a buy-out option?

Answer: No.

31) Question: Are transmission upgrade costs prorated per Megawatt?

Answer: Potentially they are. It is a function of other projects tying in at the same point.

32) Question: Can a bidder combine two projects in one bid to overcome the one Megawatt minimum size threshold? Is this acceptable even if the projects are in different locations and different clusters?If one were to aggregate different projects that actually had a different resource type, in the case of wind or solar capacity factors that are different, would it be possible to just submit them under one bid with different prices for the individual projects and then PG&E can pick and choose from the ones they thought were attractive or possibly select all?

Answer: Yes, projects less than one Megawatt each, even if at different locations or clusters, may be combined to offer a total of one Megawatt or greater. If they are different technologies and you give us the ability to pick and choose, we will still allow aggregation as long as the total is one Megawatt or greater.

33) Question: Does PG&E accept bids for less than 10 year?

Answer: PG&E can’t solicit bids for under 10 years, but we can accept unsolicited offers.

34) Question: Does the evaluation criteria give more weight to existing projects (i.e. projects already built, interconnected and currently generating)?

Answer: First, they must qualify as incremental resources. Certainly with respect to category of status of project and technology viability, yes -- existing projects would be scored higher than projects to be developed, because the risk is just not there.But in the terms of market evaluation for existing projects versus development projects, there is no difference.

35) Question: How are existing projects ranked in terms of transmission?

Answer: There is no incremental adder if there is no increase in the project capacity.

36) Question: Is it acceptable to offer a price that has some component that is indexed?

Answer: The rules are that all the pricing has to be fixed, but you can submit a non-conforming proposal. PG&E wants fixed pricing because one of the goals of the RPS program is to de-link fuel price risk from energy procurement and to take that risk out of our portfolio.

37) Question: On a build transfer where PG&E owns the project at commercial operating date, who is responsible for the fuel supply?

Answer: The seller is responsible for the fuel supply. On a build-own-transfer, what we are asking you to provide us with is essentially the cost of the fuel and the cost of O&M so that we can compare the cost of this ownership option with the cost of all the other contracts we are looking at.At the end of day, we may mutually decide that, if we do exercise this ownership option, we will take over the fuel or will take over the O&M.But what we want to get from you, for bidding purposes, is what the costs are of you providing those services.

38) Question: Please provide some examples of what constitutes a dispatchable plant.

Answer: One example, reciprocating engines burning biodiesel. For participants considering submitting biodiesel, PG&E recommends that they familiarize themselves with the California Air Resource Board’s Air Toxic Control Measure (http://www.arb.ca.gov/diesel/ag/documents/finalatcm.pdf), and with the procedures for verification of biodiesel fuels.Such proposals should include a plan for complying with the verification procedures.

39) Question: Is there data available as to the prices that were competitive last year?

Answer: We will not make that available. To date we have signed only one contract that required Supplemental Energy Payments due to its price being above the MPR.

40) Question: Is there pricing for baseload, peaking, and dispatchable that is projected to be in the ball park for this solicitation?

Answer: No. To be determined based on your offers.

41) Question: How can I receive a copy of the green book?Is it available electronically?

Answer: Yes, it is at www.pge.com/renewablerfo.

42) Question: Can you give potential bidders the range of the price per KW that is considered competitive for biomass or any other technology?

Answer: No, we cannot do that.

43) Question: Is there a difference in what PG&E considers competitive per technology or is all renewable energy classed the same when you consider competitive pricing?

Answer: Essentially, it is all going to be value driven and evaluation criteria driven and that is how all the projects will end up falling out of the rankings into the top, bottom, and other group that requires some judgment. It comes down to a combination of pricing and other factors.

44) Question: What percentage is PG&E at right now in renewables relative to the 20% goal by 2010?

Answer: We are roughly at 12% of RPS renewables energy on a delivered basis. We’ve signed another 3 to 4% under contracts for future delivery.

45) Question:  Did that number include the self generation into the portfolio?

Answer: No, that does not include the solar self generation installations that customers have with the utility. PG&E does not get to count that energy for the RPS program.

46) Question: Can we assume that on the transmission cost ranking that you will take a look what’s in the queue first and put that in and then look at the ranking on top of that?In other words, if the first 500 Megawatts will cost so much and then the next 200 Megawatts cost so much, but you notice that there are already 600 Megawatts in the queue for that particular interconnection point, then would you put that in and then draw your conclusions?

Answer: In accordance with CPUC Decision 04-06-013, the Transmission Ranking Costs are developed assuming that all generation projects in the Interconnection Queue are already in the base model. The transmission cost ranking report shows what the available capacity is at each cluster, so think of it as free.Say there is 200 Megawatts available at a particular cluster.So, for the first 200 Megawatts there is no cost adder.If a bidder were to bid a 500 Megawatt project, then the incremental 300 Megawatts would have an adder on it.If there were three bidders to that cluster, the highest ranked bid would be first to get that 200 Megawatts and the three bids would receive an adder in the order of their bid competitiveness.

47) Question: Following up on the last question, if you separately have the interconnection queue that is in the ISO system, are the projects in the queue already included in the transmission ranking cost report?

Answer: If you are in the queue, or if your projects are in the queue and they’ve had done their study done, those are included in the base model. If you are one of those projects and you already have your studies done, you need to identify this information (queue position, studies) in your offer.In that case, those studies will be used rather than the information in the transmission ranking cost report.But if you haven’t had your studies done, then the information in the transmission ranking cost report will be used, and that information assumes that those projects ahead of you in the queue and who already had their studies done, have already gone through and their upgrades are in place.

48) Question:  How do you value capacity as a function of location and base period?

Answer:  Capacity is valued in terms of its contribution to PG&E’s Resource Adequacy.Capacity that can meet PG&E’s Local Capacity Requirement as specified by the CAISO and adopted by the CPUC may be valued higher than capacity not in one of those areas.Capacity that satisfies local requirements also satisfies system RA requirements.Capacity value further depends upon the month and year in which it is available.

49) Question:  How good is portfolio fit if energy is variable?

Answer:  Generally, variable energy’s portfolio fit is not as good as for constant (predictable) energy, but portfolio fitness is ultimately a function of the generation profile relative to PG&E's position.

50) Question:Don’t transmission upgrades penalize solar?

Answer:Not necessarily.It is a function of loads and resources in the transmission system for which hours those transmission upgrades are required -- whether they are required for on-peak or off-peak delivery.

51) Question:Could the asset be pledged instead of a letter of credit or guarantee?

Answer:We have signed about 20 renewable contracts now over the last three years.Every one of them has either had cash or Letter of Credit security or an investment grade parent guarantee.We have not accepted a pledge of the asset, and we would discourage that.The 6-months or the 12-months of security that we require comes nowhere near the overall exposure that we might incur for a 10 or 20-year contract, but it is sufficient to protect us and it is sufficient to motivate the seller to perform.We discourage pledged assets because it is precisely at the time of financial distress that we need protection and at that point the asset may not be worth very much.

52) Question:Does it make sense including transmission upgrade costs in our price?We just wind up giving them back to you after we get the money.

Answer:The prices included in your bid should be your gen-tie costs which are not given back to you.The prices for network upgrades are not included in your bid price.Those get added afterwards for ranking purposes based on the TRCR or your studies.The reason we include those in the overall bid ranking is because they reflect the total cost of your bid to the consumer.And to exclude those would underestimate what the total end price would be even though your bid price does not include these costs.

53) Question:  Variability versus uncertainty. How do you really rank projects based on predictable versus unpredictable generation profiles?

Answer: There is a reliability component and there is an energy value component.So, for the energy value component, we have time of delivery factors which gives you an indication of which hours we value highly and which hours we value less highly.So you give us a profile and we will come up with our evaluation of what that energy is worth.That's the energy part.The reliability part is basically whether we can count on it.If there is a project that we know is going to be there for eight hours, in fact, it is the most valuable eight hours, we will look for guidance from the CPUC and CAISO as to what is the reliability value of that facility and will take that into account as well.

RFO Section I - III: Introduction, Schedule and Goals

No Q&A

RFO Section IV: Eligibility

No Q&A

RFO Section V-VIII: Offer, Information and Communication

No Q&A

RFO Sections IX: Calculation of Offer Price

No Q&A

RFO Section X: Electric Transmission and Interconnection

No Q&A

RFO Section XI: Evaluation of Offers

No Q&A

RFO Section XII-XIV: Confidentiality, Review and Notification

No Q&A

RFO Section XV: Execution of Agreement

No Q&A

RFO Section XVI: Regulatory Approval

No Q&A

RFO Section XVII and XIX: Participant's Waivers and Representations

No Q&A

RFO RPS Misc. Issues

No Q&A