5. 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.48 Rather, we conditionally accept each Plan, subject to limited required amendments and several suggestions. Each utility remains ultimately responsible for proposing and executing reasonable Plans that achieve RPS targets and goals. We will later judge the extent of each IOU's success, including the degree to which each IOU implements Commission orders, applies Commission guidance, demonstrates creativity and vigor in program execution and, most importantly, reaches program targets and goals.
5.1. PG&E
PG&E proposes several changes in contract terms, which we summarize in Appendix D. Unless otherwise identified and addressed in this decision, we accept these and other changes, subject to PG&E being responsible for reaching Program targets and goals.
5.2. SCE
We address four elements of SCE's Plan: modifications to project viability calculator, credit and collateral provisions, shortlist requirement, and other changes.
We directed PG&E, SCE, and SDG&E to use the Project Viability Calculator (PVC) as a tool for standardized comparison of the viability of projects bid into RPS solicitations.49 The PVC, which was developed by Energy Division staff in collaboration with utilities, renewable project developers and ratepayer advocates, is a device that enables the utilities to evaluate the viability of a renewable energy project relative to all other projects that bid into the IOUs' RPS solicitations. The PVC uses standardized categories and criteria to quantify a project's strengths and weaknesses in key areas of project development. The PVC is one criterion in an IOU's bid evaluation, and is not intended to determine the exact merit of a particular project or contract.
SCE suggests modifications to the PVC based on experience with its use in the 2009 RPS Solicitation and recommendations of its IE.50 These changes include modifying scoring criteria and guidelines to increase an IOU's flexibility in applying the PVC to each bid, and changing the role of the IE in evaluating the viability of each bid. SCE asserts that adoption of its proposed changes will lead to a more useful tool, and will help to more accurately evaluate the viability of renewable projects relative to one another.
DRA opposes SCE's recommendations to change the PVC. DRA argues that SCE does not provide sufficient information to justify why the Commission should support any of SCE's proposed changes to the PVC. DRA also disagrees with SCE's characterization of the role of the IE.
We decline to make changes to the PVC in this decision. Neither PG&E nor SDG&E comment on SCE's changes, nor do they raise concerns with the PVC. The PVC was developed by Energy Division staff as a tool for uniform, standardized comparison across projects and utilities. It is reasonable for changes to the PVC, if any, to be made by staff with stakeholder participation from utilities, renewable project developers and ratepayer advocates and applied uniformly. If SCE would like to make changes to the PVC used by all IOUs for RPS solicitations, it should work with staff to initiate the appropriate stakeholder process.
SCE says it is making three changes to its credit and collateral provisions.
First, SCE is increasing its development security requirements from $60 per kilowatt (kW) to $90 per kW for baseload facilities, and from $30 per kW to $60 per kW for intermittent facilities. In support, SCE says this provides reasonable security for SCE customers, and is consistent with industry position on allocating project failure risk between developers and utility customers.
Second, SCE is restructuring its performance assurance requirement to a tiered requirement: 3% of total revenues seller expects to earn in the early years, 5% to 6% for mid-contract years, and 3% to 5% for the remaining years. SCE says its tiered performance assurance amount averages 5% of total revenues over the full contract term, the same as the requirement in SCE's 2009 Plan. SCE asserts that the tiered structure reflects the risks related to different delivery terms while being responsive to changes in both (a) SCE's risk exposure over the contract term and (b) the renewable energy and financing markets. In further support, SCE contends the tiered structure benefits SCE customers (by better reflecting SCE's risk exposure over time and reducing the maximum exposure faced by customers). SCE says it also benefits sellers (by reducing the total capital requirement in early years when access to capital is constrained).
Third, SCE is eliminating the seller's debt to equity ratio requirement. In support, SCE says this credit provision often required a significant amount of negotiation without commensurate benefit. Further, SCE reports that enforcing compliance requires follow-up documentation and verification, thereby complicating contract administration and management. SCE asserts that SCE and its customers remain reasonably protected even without this specific requirement because (a) financial markets impose adequate discipline regarding debt to equity ratios and (b) SCE retains an existing contract provision that prohibits additional debt other than for development, construction and operation of the facility.
CalWEA and LSA oppose the deposit increase to $60/kW asserting it is double the amount required in the 2009 solicitation, and 600% of the amount required in the 2008 solicitation. CalWEA and LSA say SCE fails to show any change in circumstances over the past two years to justify a six-fold increase, and that ever-increasing deposit amounts create an artificial barrier to project development.
As we have said before regarding collateral, we have inadequate evidence to affirm any particular numbers. We are persuaded by SCE, however, that the annual cost of posting a Letter of Credit to cover SCE's proposed deposit level would generally be under 0.1% of the total capital cost of a new renewable energy facility.51 Deposits reasonably balance risk between stakeholders. SCE's proposed level does not appear to be an unreasonable barrier to project development.
We provide utilities flexibility to make many business decisions subject to holding them accountable for results. In that context, we accept SCE's proposals consistent with SCE being responsible for SCE's portion of California RPS Program success, and subject to SCE meeting its program targets and goals.52
SCE proposes in its comments on the PD that it be permitted to amend its 2011 Plan to include a new shortlisting requirement. In particular, SCE says the Commission should allow SCE to add certain interconnection study requirements in order for a project to be eligible to be shortlisted. The requirements are that a project is active in an interconnection queue and has at least completed (a) a Phase 1 interconnection study, (b) a System Impact Study, or (c) 9 of 10 screens in the fast-track interconnection process. In support, SCE says this incorporates lessons learned since the filing of the draft Plans, will provide more certainty around potential network upgrade and interconnection costs, and will permit a more accurate evaluation of such costs in the LCBF evaluation. SCE's proposal is opposed by IEP and CalWEA/LSA. We decline to authorize the change requested by SCE.
SCE makes the request late in the process. Because late changes have been an issue in prior Plans,53 the assigned Commissioner' Scoping Memo scheduled a specific date for final Plan updates. In addition, respondents filed subsequent motions for consideration of Plan changes. SCE should have made its proposal by the date for final Plan updates, or by subsequent motion.
Nonetheless, even if considered now, SCE fails to make a convincing case. The PVC specifically scores both interconnection and transmission. The LCBF methodology permits quantitative and qualitative assessment of both interconnection and transmission. SCE fails to convincingly show that the PVC and LCBF tools result in shortlisting projects that would be rejected under its new requirements. We also note that neither PG&E nor SDG&E join SCE in making this request. We believe all three IOUs can successfully use their PVC and LCBF tools to rank and shortlist projects without the specific additional requirements proposed by SCE.
Improvements in the solicitation and selection process are always welcome, however. We encourage SCE to renew its proposal at an appropriate future time (accompanied by convincing evidence and argument) if SCE continues to believe that these or other requirements will improve the RPS Program.
SCE makes several other changes, which we summarize in Appendix D. No party presents compelling comments in opposition to these changes, particularly when considered in light of our approach of "flexibility with accountability." We accept these changes, consistent with SCE being responsible for it portion of program success, and subject to SCE meeting program targets and goals.
5.3. SDG&E
We address two elements of SDG&E's Plan: Time of delivery (TOD) factors and other.
RPS Plans include time-differentiation of prices to be paid for electricity generated by renewable resources. The time-differentiation is based on TOD factors. In 2009, we directed SDG&E to present with its next Plan both energy only and all-in factors, and make a showing on the reasonableness of its TOD factors. (D.09-06-018 at 48.) We did this because of the wide variation in TOD factors between IOUs,54 and the contention by some parties that SDG&E's TOD factors were energy-only and not all-in (capacity and energy).
SDG&E says in its current showing that:
In all previous RPS RFOs, TOD factors used by SDG&E were based upon energy-only calculations, with no capacity costs included. Because of this, a Resource Adequacy Adder was used to simulate the additional cost of capacity [when making resource choices within the LCBF methodology] ... In future RFOs, SDG&E intends to use the all-in TOD factors ... with capacity costs included in their calculation ... The Resource Adequacy Adder will be discontinued to avoid double-counting capacity costs. (SDG&E April 9, 2010 Further Amended Draft 2010 RPS Procurement Plan at 28.)
SDG&E proposes the following all-in TOD factors:
2011 RPS SOLICITATION TOD FACTORS
PERIOD |
SUMMER |
WINTER |
On-peak |
2.501 |
1.089 |
Semi-peak |
1.342 |
0.947 |
Off-peak |
0.801 |
0.679 |
No party opposes SDG&E's proposal. TOD factors of SCE and PG&E are all-in. Accepting SDG&E's proposal will make the approach to TOD factors by the three IOUs uniform, and will reasonably "recognize the extent of the need for additional capacity." (D.09-06-018 at 48 citing D.06-05-039 at 68.) We accept SDG&E's TOD proposal.
SDG&E proposes several other changes, which we summarize in Appendix D. No party presents compelling comments in opposition to these changes, particularly when considered in light of our approach of "flexibility with accountability." We accept these changes consistent with SDG&E being responsible for it portion of program success, and subject to SDG&E meeting program targets and goals.
5.4. PacifiCorp
Last year we accepted PacifiCorp's 2009 IRP Supplement, but noted the need for certain improvements in 2010. (D.09-06-018 at 66-69.) In particular, we said that PacifiCorp must do a better job of explaining how it will achieve 20% by 2010, and described several examples.
PacifiCorp filed its 2008 IRP on May 29, 2009, and its Supplement on June 29, 2009. (D.08-05-029.) In response to the Amended Scoping Memo, PacifiCorp referred to the 2008 IRP and the Supplement, and filed an Additional Supplement on December 18, 2009.
Among other things, PacifiCorp explains that the RPS need identified in its 2008 IRP is being met by multiple RFPs. The 2008 IRP (Action Plan, Action Item 1), according to PacifiCorp, identifies up to 2,000 MW of RPS resources to be acquired by 2013, including 1,400 MW by 2010, and an additional 600 MW by 2013. PacifiCorp held two RFPs: one on October 6, 2008, and another on July 8, 2009. PacifiCorp also explains that it pursues PPAs with qualifying facilities where the company also receives the associated renewable energy credits (RECs) to meet its RPS requirement. PacifiCorp's August 2009 Semi-Annual Compliance Report (attached to the December 18, 2009 Additional Supplement) shows PacifiCorp's compliance going from an actual APT (adjusted by flexible compliance) of 8.3% in 2008, and forecast of 12.2% in 2009, to 20.0% in 2010.55 Just as last year, however, it remains unclear if the past RFPs have produced sufficient response for PacifiCorp to reach 20%, or if further RFPs are needed and, if so, how much and when (e.g., solicitation of another "x" MW in 2011 or 2012).
We accept PacifiCorp's Additional Supplement but, just as with the IOUs, we do so consistent with PacifiCorp being responsible for its portion of RPS Program success, and subject to PacifiCorp meeting California Program targets and goals. We again direct PacifiCorp to do a better job in its next showing of explaining how it will achieve California RPS targets.
5.5. Sierra (CalPeco)
Sierra reported last year that it was in compliance with its California RPS procurement obligations, expected to remain in compliance, and would be sufficiently resourced to meet its 20% obligation by 2010. Because of this, Sierra stated that it had no RPS solicitation pending or scheduled for California, but would issue an RFP to comply with its Nevada-based requirements. (D.09-06-018 at 69.) Sierra now reports that there are no significant changes to its accepted 2009 Supplement.56
Sierra's 2009 IRP Supplement reasonably addresses its unique, fully-RPS resourced position. We are confident that Sierra, now CalPeco, will provide more detail in subsequent reports, as necessary, should this fully-RPS resourced situation change. We accept the Supplemental Filing consistent with CalPeco being responsible for its portion of RPS Program success, and subject to CalPeco meeting California Program targets and goals.
48 See, for example, D.06-05-039 (at 61-62), D.07-02-011 (at 53) D.07-012-052 (at 299, Conclusion of Law 63), D.09-06-018 at 53-54.
49 D.09-06-018 at 21 and Conclusion of Law 9.
50 June 17, 2010 Second Amended 2010 RPS Procurement Plan at 39.
51 Reply Comments dated January 26, 2010 at 15.
52 Fixed prices for 20 year contracts place a significant risk of bad outcomes on ratepayers. (See, for example, D.10-12-048, Appendix C.) We lack data from SCE or parties to access whether the risk of default by a project late in a 20 year contract is adequately compensated by a reduced performance assurance requirement in the later years (e.g., given the potential for the project to default on the contract but make sales to another buyer at a higher price). As discussed above (e.g., Section 3.2 and opening paragraph of Chapter 5), we provide utilities flexibility to make many business decisions but hold utilities accountable for the results.
53 See, for example, July 27, 2009 ALJ Ruling regarding late changes proposed to 2009 RPS Procurement Plans.
54 For example, for the 2009 RPS solicitation the summer on-peak TOU factor for SCE was 3.13 and for SDG&E was 1.64. (D.09-06-018 at 47, footnote 38.)
55 PacifiCorp's August 2010 Semi-Annual Compliance Report shows adjusted actual APT of 9.1% in 2008, and 10.6% in 2009.
56 December 18, 2009 Supplemental Filing at 1.
