6. Limited Issues Specific to a Plan

We comment here on limited issues specific to each Plan. As we have said before, conditional acceptance of these Plans does not constitute endorsement or adoption of proposed policy measures that have not yet been fully vetted. It also does not constitute endorsement or adoption of each aspect of each Plan.43 Rather, we conditionally accept each Plan, subject to limited required amendments and several suggestions made herein. Each utility remains ultimately responsible for proposing and executing reasonable Plans that achieve RPS targets, including 20% by 2010, subject to flexible compliance rules. We will later judge the extent of each IOU's success, including the degree to which each IOU implements Commission orders, applies the Commission guidance, demonstrates creativity and vigor in program execution and, most importantly, reaches program targets and requirements.

6.1. PG&E

We limit our comments to three elements of PG&E's Plan: pilot program for pre-approvals, development security, and other changes.

6.1.1. Pilot Programs for Pre-Approvals

PG&E proposes a pilot program in which contracts meeting certain guidelines would be pre-approved by the Commission. The guidelines would include that the contract not modify the Commission-approved model contract in the 2009 Plan, the price be at or below MPR, this be a pilot program limited to 800 GWh, and contracts would be submitted to the Commission by Tier 1 advice letter.44

DRA, Reid, and TURN urge that the proposal should be rejected. They argue that the proposal is too large; the Commission lacks standards for evaluating the proposal; and the contracts under the program would not receive effective Commission review.

These disputes will not be resolved here, but in a separate proposed decision that addresses the streamlining of RPS contracting. PG&E's proposal has several elements that overlap with proposals for streamlining contract review processes that were being considered in R.06-02-012 and have now been transferred to this proceeding.45 All these related issues will be considered in a separate proposed decision. PG&E's proposal is therefore not accepted as part of its 2009 RPS procurement plan and should be removed from the Amended Plan to be filed pursuant to this order. If some or all elements of PG&E's proposal are ultimately approved, PG&E may further amend its 2009 Plan at that time.46

6.1.2. Development Security

PG&E proposes to increase project development security amounts. In exchange, PG&E will, in certain situations, limit damages PG&E may collect when there is a default prior to commercial operation.47 In summary, the proposal is:

Date Due

Project Development Security




Date Agreement Executed



30 Days After Commission Approval



[1] For all products other than dispatchable, the $/kW amount is multiplied by the greater of (a) the capacity factor or (b) 0.5.

Default damages are calculated in both 2008 and 2009 by estimating the difference between the value of the contract and the cost of its replacement.48 For 2009, PG&E will limit default damages during project development to the amount of the project development security in three cases. The cases are when the developer is unable to construct the project due to the developer's inability to (a) obtain necessary permits, (b) obtain transmission upgrades or (c) overcome a force majeure event.49

In support, PG&E says this responds to bidder feedback. According to PG&E, counterparties have expressed a willingness to pay higher deposits in exchange for knowing the extent of potential damages upfront. PG&E says this facilitates project financing. PG&E explains that it also helps ratepayers by providing sellers a potentially stronger incentive to complete projects, since sellers have more money on deposit with PG&E that PG&E will keep in the event of default. PG&E reports that the modified requirement is also similar to the credit requirements covering project development for the 2008 long-term request for offers. No party comments in support or opposition.

We accept PG&E's proposal. In doing so, we note that the higher security amounts are due in all cases, even those other than the three instances wherein the damages are limited to the security deposit. By increasing costs, this may generally act as a constraint on projects. We also note that neither PG&E nor any party presents any data to justify the deposit amounts, or alternative amounts.

We reach the same conclusion we essentially have reached every year. That is, we have inadequate data to order any other outcome, endorse PG&E's specific numbers, or adopt the specifics of the particular tradeoff (an exact higher deposit amount in exchange for an exact limit of damages).

Nonetheless, we accept PG&E's proposal consistent with PG&E reporting that it represents the interest of its counterparties. We also accept the proposal noting that PG&E is ultimately responsible for its Plan, and its success at reaching RPS Program targets. As we have said before, if any utility (including PG&E) fails to reach a Program target and seeks to avoid a non-compliance penalty, that utility must make a showing to justify why it should not pay the non-compliance penalty. That showing should include an explanation that its deposit scheme did not prevent otherwise viable projects from at least coming forward for evaluation. (See, for example, D.06-05-039, at 38.)

6.1.3. Other Proposed Changes

PG&E proposes several other changes (summarized in Attachment C). These include: clarifying evaluation protocols, soliciting additional information about supplier diversity, modifying contract terms for more flexibility in construction start date and commercial online date, modifying scheduling coordinator responsibilities, specifying minimum guaranteed annual energy production, streamlining and simplifying the model contract (by combining three former contracts into one), and making conforming changes to STCs. No party comments. We accept these changes, subject to PG&E being responsible for reaching Program targets.

6.2. SCE

We address four elements of SCE's Plan: pre-approvals of short-term contracts, expansion of biomass standard contract to all RPS technologies, credit and collateral provisions, and other changes.

6.2.1. Pre-Approval for Short-Term Contracts

SCE proposes that RPS procurement contracts meeting certain guidelines be treated as per se reasonable and pre-approved by the Commission. The guidelines would include that these contracts be entered into as a result of a competitive process, be limited to 10,000 GWh total cumulative procurement, and generally be limited to terms of five years or less. SCE proposes that resulting transactions under this authority be reported to the Commission via existing procurement plan compliance reports filed quarterly by advice letter.

DRA, Reid, and TURN oppose this proposal. They argue that the proposal would cover a large proportion of RPS procurement and that the Commission would not be able to determine whether certain RPS requirements had been met (e.g., minimum quantity requirement for the use of short-term contracts set forth in D.07-05-028). TURN points out that reasonableness standards for short-term contracts are being separately developed,50 and that SCE's proposal should not be approved until such standards are in place.

We agree with TURN that the proper place to resolve these disputes is in a separate proposed decision that addresses the streamlining of RPS contracting. SCE's proposal directly implicates proposals for streamlining contract review processes that were being considered in R.06-02-012 and have now been transferred to this proceeding.51 All these related issues will be considered in a separate proposed decision. SCE's proposal is therefore not accepted as part of its 2009 RPS procurement plan and should be removed from the Amended Plan it will file pursuant to this order. If some or all elements of SCE's proposal are ultimately approved, SCE may amend its 2009 Plan at that time.52

6.2.2. RPS Standard Contract Program

SCE reports that it voluntarily initiated a program in 2007 offering standardized contracts to biomass facilities with capacities up to 20 MW per project, priced at the MPR, and subject to a cap of 250 MW for total subscriptions. SCE says it did this to help small biomass projects contribute to California's RPS goals and support the Governor's goal to promote energy production from biomass.53 SCE extended this opportunity into 2008. For 2009, SCE says it is proposing to expand the program from biomass to all renewable technologies.

The standardized contracts are available for three categories of projects differentiated by size. SCE summarizes what it asserts are the important differences between the three standardized contracts:





Location Restrictions

Must be an SCE retail customer

Must be within CAISO control area

Must be within CAISO control area

Startup Deadline

Within 18 months of signing contract

Within 5 years of contract signing

Seller provides date

Development Security



$20/kW *

Performance Assurance



Six months of revenue *

SCE concludes by saying (as it similarly did in its 2008 Plan):

Finally, it should be noted that SCE is not necessarily seeking approval of its standard contracts for generators greater than 1.5 MW as part of its 2009 Procurement Plan. [Footnote deleted.] Instead, SCE will file an advice letter, along with a set of executed agreements, seeking approval for any agreements signed pursuant to this standard contract program. (SCE Plan, at 28.)

In assessing this proposal we initially note that the first category (up to 1.5 MW) implements existing requirements. (§ 399.20 and D.07-07-027.) The other two categories comprise SCE's voluntary program. SCE does not provide a copy of the two standardized contracts that are at issue (1.5 MW to 5 MW and 5 MW to 20 MW). SCE refers the Commission and parties to its web page.54

We comment on four elements, consistent with and building on our comments in 2008. (See D.08-02-008, at 43-44.) First, no party provides material comments (e.g., recommending specific changes to one or more standard contracts or applicable price). For this and the reasons stated below, we reach no judgment here on the standard contracts and prices.

Second, SCE does not request acceptance of its standard contracts, or use of the MPR price level. Rather, SCE says it "will file an advice letter, along with a set of executed agreements, seeking approval for any agreements signed pursuant to this standard contract program." (SCE Plan, at 28.) We reach no decision here on the two standard contracts and/or price level. We will make those judgments if and as needed when SCE files an advice letter.

Third, our application of the legislative structure for the RPS Program is to allow each electrical corporation considerable flexibility in the way it meets RPS goals. In exchange, each electric corporation must meet its RPS Program targets, within application of flexible compliance criteria, and penalties apply for failure to meet targets. We accept, reject or modify each Plan before a particular solicitation, but we do so at a reasonably high level.

In this context, what we refer to as SCE's RPS Standard Contract Program (for RPS Projects between 1.5 and 20 MW per project, for a total of 250 MW) appears to be a reasonable application of SCE's business judgment. We accept SCE's RPS Standard Contract Program as part of SCE's 2009 RPS Plan, even though SCE says it is not necessarily seeking Commission acceptance, rejection or modification of these standard contracts as part of its 2009 Procurement Plan, and even though we reach no judgment on the standard contracts. We do this, as we did in 2008, so that such contracts may be judged based on consistency with this Plan.55

We also note that thus far SCE has submitted four projects to the Commission that have resulted from its standard contract program. We treated each as a bilateral contract since it did not result from a solicitation. Each contract also contained changes from the standard contract. Changes potentially reduce the benefits otherwise available from a standard contract approach. A completely standardized approach should eliminate the need, in all but the most exceptional of cases, for additional negotiation and modification.

Finally, we see great merit with increased standardization. We recognize SCE's initiative and innovation with this RPS Standard Contract Program. We encourage, but do not require, the other utilities to adopt the same approach. We are separately examining the reasonableness of the use of standardized tariffs with standardized contracts at a similar price and total program cap.56 We expect to issue an order soon which will address this in the context of what many refer to as the "feed-in tariff."

6.2.3. Credit and Collateral Provisions

SCE says it has (a) eliminated the Reduced Development Security Option, (b) increased its Development Security requirements, (c) eliminated the subordinated security interest provisions in its pro forma agreement and (d) revised its requirement for sellers to post performance assurance. We briefly describe each in Appendix C.

No party objects to these proposals. We have inadequate information upon which to reach a judgment and, as we have said before regarding collateral (and said above regarding PG&E), we have inadequate evidence to affirm any particular numbers. We accept SCE's proposals consistent with SCE being responsible for its portion of program success, and subject to SCE meeting Program Targets.

6.2.4. Other

SCE makes several other changes. These include, but are not limited to: (a) revised insurance provisions to reflect current market conditions; (b) added North American Electricity Council requirements to reflect the existing obligations of applicable generating facilities; (c) added a cap on the expenditures required by sellers to comply with changes in RPS Program requirements; (d) deleted STC 3 (Supplemental Energy Payments) in accordance with D.08-04-009 and replaced STC 3 with an above market funds (AMFs) provision; (e) modified delivery point and other related provisions to take into account the CAISO's planned Market Redesign and Technology Update; (f) modified the definition of Green Attributes in accordance with D.08-08-028; and (g) other improvements to bid solicitation materials to provide greater clarity through improved formatting, structural and grammatical changes.

No party comments on these changes. We accept these changes, consistent with SCE being responsible for it portion of program success, and subject to SCE meeting Program Targets, with the exception of the AMFs term. As proposed by SCE, the new AMFs term may conflict with statute. SCE should consult with staff to develop an improved term.57

6.3. SDG&E

We address three elements of SDG&E's Plan: Imperial Valley-specific solicitation, financial impacts and other.

6.3.1. Imperial Valley-Specific Solicitation

SDG&E says:

In order to ensure the availability of Imperial Valley [IV] resources, SDG&E intends to seek Commission approval to include an IV-specific solicitation within its 2009 general RPS solicitation. The IV-specific solicitation would include special instructions and other relevant information in a separate section of the main solicitation document. (February 27, 2009, Sunrise Comments, at 10.)

SDG&E describes its proposal as "a `sub-solicitation' within SDG&E's general RPS solicitation." (Id., at 11.) SDG&E asserts the sub-solicitation:

... would help to prevent confusion that may be associated with different solicitations being issued at different times and will avoid the burden-to bidders, the Commission and SDG&E alike-associated with conducting multiple stand-alone solicitations. (Id., at 11.)

We accept SDG&E's proposal. Upon Commission approval of Sunrise, SDG&E committed to, among other things, replacing

... any currently approved renewable energy contract deliverable via Sunrise that fails with a viable contract with a renewable generator located in Imperial Valley. (D.08-12-058, at 260.)

Accepting SDG&E's proposal here is consistent with allowing SDG&E to fulfill this commitment. SDG&E may also (along with other utilities) undertake all other reasonable actions to highlight the unique and important opportunities created by Sunrise (e.g., a special bidders conference), and to facilitate development of those resources (e.g., locate a regional office in Imperial Valley).

6.3.2. Financial Impacts

SDG&E's Plan specifically requests that the Commission here:

SDG&E offers nothing to change our previous statements on these points. We have addressed both points in recent orders (e.g., D.07-02-011, D.07-12-049, D.07-12-052, D.08-05-035). In summary, we will take action to address negative impacts on any utility's balance sheet or credit profile when warranted and necessary, and will do so in a manner consistent with the urgency of the matter.

6.3.3. Other

SDG&E identifies several other changes, which are summarized in Appendix C. In short, these include: one team for evaluations, potential use of outside consultants to perform LCBF quantitative analysis, revised description of its TOU cost adjustment, use of average bid prices for its LCBF duration equalization, inclusion of UOG of between 20 MW and 35 MW, pricing form simplification, and improved offer narratives. No party objects. We accept these changes consistent with SDG&E being responsible for it portion of program success, and subject to SDG&E meeting Program Targets.

6.4. PacificCorp

We accept PacifiCorp's 2009 IRP Supplement, but note the need for certain improvements in 2010. We begin with a brief description of PacifiCorp's situation and showing, and conclude with examples of necessary improvements.

PacifiCorp operates in six states (California, Oregon, Washington, Utah, Idaho, and Wyoming). It operates its own balancing authority, and is subject to WECC and North American Electric Reliability Council requirements, but is not part of the CAISO. PacifiCorp explains that it does resource planning on a system-wide basis, and does not procure any resources on a California-specific basis. PacifiCorp affirms its commitment to satisfying California's requirement of 20% renewables by 2010, with the use of flexible compliance and earmarking as needed.

PacifiCorp shows it is actively procuring renewables in order to reach its RPS targets. For example, in 2008 PacifiCorp initiated two RFPs seeking 900 MW of renewable resources by 2011. PacifiCorp reports that its Plan also includes 2,000 MW of renewables by 2013. (2007 Integrated Resource Plan (IRP) Update, Attachment A, at 1.) PacifiCorp also reports a commitment to the Energy Gateway Project to, among other things, provide transmission access for renewable resources.58

We appreciate PacifiCorp's commitment to meeting its California RPS Program obligation of 20% by 2010. Nonetheless, PacifiCorp's 2009 IRP Supplement does not make entirely clear how it will achieve this goal. PacifiCorp must improve its showing for the 2010. We describe several examples.

PacifiCorp's 2009 IRP Supplement shows it intends to procure 93,368 MWh of RPS-eligible procurement in 2010, and 89,799 MWh in 2013 (the end of the three-year flexible compliance period). This is 10.7% and 10.4%, respectively, of its estimated retail sales of 868,999 MWh in 2010 and 866,154 MWh in 2013.59 (2009 IRP Supplement, Item 2, Program Metrics, Attachment A, at 2.) PacifiCorp must do a better job next year of showing how it will reach 20% by 2010 (or 2013 using the maximum flexible compliance), or explaining its basis for not having a plan that shows reaching these RPS Program targets.

Similarly, PacifiCorp's response to several issues identified in the Amended Scoping Memo is: "not applicable." In support of its response, PacifiCorp explains that it operates on a system-wide basis, and not a California-only basis. Even if this is true, PacifiCorp does not adequately explain why it cannot provide responses reflective of its system. These might be, for example, a copy of its system-wide RFP (in place of a California-focused bid solicitation), a showing of how its system-wide procurement plan reasonably includes a procurement margin of safety (to account for potential contract failure or other contingencies), or whether or not the Commission should determine if and when a utility may execute an exclusivity agreement.60

Each IOU was required to show its workplan for reaching 20% by 2010. In response, PacifiCorp discusses a "Revised Protocol" allocation methodology. The methodology is used to allocate costs and revenues. According to PacifiCorp, it is also used to allocate to each state jurisdiction its share of renewables output generated by the utility-owned system resources.

PacifiCorp acknowledges the "Revised Protocol presents a challenge for PacifiCorp in meeting California's 2010 RPS targets." (2009 IRP Supplement, Item 7, Response, Attachment A, at 5.) PacifiCorp states that it "may propose to implement a renewable pilot program that would allow for the intra-Company transfer of renewable resources for California compliance purposes." (Id.) This does not adequately explain PacifiCorp's current workplan for reaching California's RPS Program targets. Whether or not PacifiCorp decides to later propose implementation of a pilot program, PacifiCorp must satisfy California's RPS Program target of 20% by 2010 (or 2013 using the full three years of flexible compliance), and its annual RPS Procurement Plan must explain its plan to do so.

Thus, we accept PacifiCorp's 2009 IRP Supplement consistent with PacifiCorp being responsible for meeting applicable RPS Program Targets. We expect PacifiCorp to do a better job in its next annual RPS showing.

6.5. Sierra Pacific Power Company

Sierra reports that it is currently in compliance with its California RPS procurement obligations, expects to remain in compliance, and is currently sufficiently resourced to meet its 20% by 2010 obligation. Sierra states that it has no RPS solicitation pending or scheduled for California (since it is fully resourced with respect to California), but will issue an RFP to comply with its Nevada-based requirements.

Sierra's 2009 IRP Supplement reasonably addresses its unique, fully-RPS resourced position. We are confident that Sierra will provide more detail in subsequent reports, as necessary, should this fully-RPS resourced situation change.

43 See, for example, D.06-05-039 (at 61-62), D.07-02-011 (at 53) and D.07-012-052 (at 299, Conclusion of Law 63).

44 See General Order (GO) 96-B regarding Tier 1 advice letters.

45 See Assigned Commissioner's Ruling Transferring Consideration of Certain Issues from Rulemaking 06-02-012 to Rulemaking 08-08-009 (April 3, 2009).

46 If unable to include the provisions within the amended Plan to be filed pursuant to this order, PG&E may later file and serve an advice letter to amend its Plan. (See GO 96-B.)

47 The security amounts increase upon commercial operation, but PG&E does not propose any change here between its 2008 and 2009 Plans.

48 See § 5.3 (Calculation of Termination Payment) in PG&E's model contract for both 2008 and 2009. The amount "shall not include consequential, incidental, punitive, exemplary, indirect or business interruption damages." (§ 5.3 of PG&E model contract.)

49 See Solicitation Protocol, § VII, at 23, footnote 8.

50 This was undertaken in R.06-02-012, and is now transferred to this proceeding.

51 See Assigned Commissioner's Ruling Transferring Consideration of Certain Issues from Rulemaking 06-02-012 to Rulemaking 08-08-009 (April 3, 2009).

52 If unable to include the provisions within the amended Plan to be filed pursuant to this order, SCE may later file and serve an advice letter to amend its Plan. (See GO 96-B.)

53 SCE cites the Governor's Executive Order S-06-06.

54 We note from the web page that the contracts are largely similar to the model contract SCE includes with its 2009 Plan, but with some differences (e.g., SCE deletes or incorporates into other parts of the agreement: § 1.11 regarding the "Market Price Referent;" § 3.17 regarding the "Availability Guarantee and Obligation to Make Availability Guarantee Lost Production Payment").

55 Contracts submitted for our consideration that are not part of an accepted Plan may be reviewed by application of other criteria, such as those used for a bilateral contract. Accepting SCE's RPS Standard Contract Program as part of SCE's 2009 Procurement Plan, however, permits consideration of these contracts for consistency with the approved Plan (§ 399.14(d)) while not foreclosing consideration using other criteria, if appropriate.

56 For example, one proposal under consideration is a standard tariff/contract at the MPR price level for a total of 1,000 MW statewide (which is about 500 MW when allocated to SCE). (See March 27, 2009 Ruling on Additional Commission Consideration of a Feed-In Tariff.)

57 § 399.15(d) sets one particular limit, but also provides that "nothing in this section prevents an electrical corporation from voluntarily proposing to procure eligible renewable energy resources at above-market prices that are not counted toward the cost limitation." (§ 399.15(d)(4).) This appears to conflict with § 2.05 of SCE's pro forma contract. (Attachment 2-3 of SCE's 2009 RPS Procurement Plan.)

58 The Energy Gateway Project is a regional transmission project estimated to cost more than $6 billion for more than 2,000 miles of extra-high voltage transmission lines located in Oregon, Washington, Utah, Idaho and Wyoming.

59 A motion is pending regarding reporting treatment of RPS purchases and obligations. The motion addresses establishment of annual procurement targets and flexible compliance, but does not change the 20% by 2010 obligation (or 20% by 2013 using the full three years of flexible compliance).

60 See, for example 2009 IRP Supplement, Items 1.3, 2.6, 6.1 and 6.2.

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