includes a limited volume of procurement associated with new programs, such as the GTSR Program, that reflect the changing needs of its customers. ORA asserts that VMOP is not a sufficient mitigation if GTSR provides SDG&E with undue discretion for using its VMOP to procure excess RPS resources. ORA observes that, in general, the IOUs have some degree of flexibility to specify the methodology for determining their own VMOPs, and therefore the VMOP does not appear to be a meaningful tool for addressing the risk of overprocurement to non-participating ratepayers. SCE proposes to rely on excess RPS generation for its GTSR Program. By doing so, SCE would minimize the risk of overprocurement of GTSR-specific resources. However, as discussed above, SCE’s proposal is not compliant with SB 43 and this decision directs SCE to focus on procuring new renewable generation for GTSR Program. As directed by SB 43, SCE should apply any GTSR overprocurement to the RPS program in accordance with this decision. The IOUs should use the RPS backstop method as required by statute. The clear language of the statute requires that the RPS backstop be used for overprocurement, regardless of whether the overprocurement is the result of customer attrition or “other causes.” This approach is reasonable and efficient. The GTSR Program is small compared to the overall RPS program. Currently, 600 MW would represent less than 6% of current RPS capacity online. Because the GTSR Program is very small in comparison to RPS, transferring overprocurement to RPS would not result in unjust or unreasonable rates for ratepayers. Because it is difficult to calculate all of the net impacts on non-participants, direct comparison of average prices, as suggested by ORA, is not the right tool. No party has identified a reasonable, practicable, definitive method for determining a price difference.
“community” as customers within the same municipality or county, or within ten miles of the customer’s address. PG&E’s suggested definition is approved, but, as many parties pointed out in their comments, other definitions of community may be appropriate or necessary in order to fulfill the intent of SB 43. For example, community for purposes of the EJ Reservation a party could propose the definition of community be expanded to include shared interest communities located anywhere in the service territory. These additional definitions of community for purposes of siting ECR projects will be examined in Phase IV. We direct the IOUs to base their assessment of community interest on the following criteria: (a) documentation that community members have committed to enroll in 30% of the project’s capacity or documentation that community members have provided expressions of interest in the project sufficient to reach 51% subscription rate; and (b) a minimum of three separate subscribers to reflect the “shared” aspect of the program. We agree with CCSF that allowing institutional customers to guarantee subscription levels for new projects may be sufficient to establish community interest. In particular, if the guarantee is from a municipality working to develop ECR projects in its community, then this guarantee is a sufficient demonstration of community interest. PG&E argues that in addition each project must meet a 50% residential enrollment threshold. We agree with PG&E that it is important to ensure that residential customers have the opportunity to participate in ECR projects. We do not agree that the residential requirement is necessary or conducive to developing a successful ECR component of the GTSR Program. Therefore, we require that the IOUs ensure that at least at least one ECR project have a residential subscription of at least 50%.
4.10.2.6. Securities Opinion Parties generally agree that program components like SDG&E’s Share the Sun may result in securities issues and that additional steps should be taken to protect against securities litigation risk. SDG&E cites a recent example of securities litigation involving investments in Hard Rock Hotel condominium units. Plaintiffs (investors in the units) were required to sign a rental-management contract with a different entity. Plaintiffs alleged that this arrangement caused them to unwittingly enter into an unregistered securities transaction. The court agreed that the arrangement resulted in a security. This case clearly illustrates that there is a litigation risk when a group of people are investing in a project with the expectation of a profit. SDG&E recommends requiring a securities opinion from an AmLaw 100 law firm because of the complexity of the law, the importance of getting the securities issues right, and the potential for criminal sanctions. SDG&E argues that the AmLaw 100 requirement is a reasonable proxy for the securities expertise necessary to have assurance that there is not a securities litigation risk. SELC and IREC argue that limiting opinion to an AmLaw 100 firm will create an unnecessary barrier for developers. IREC believes it would be sufficient for a solar provider to declare compliance with the securities laws. SELC would require an opinion from a lawyer in good standing with the California Bar. We agree with SDG&E that the complexity of securities law and the potential for costly and protracted litigation require analysis by attorneys with extensive expertise with securities law. It is essential that participants in the ECR component be protected and that ratepayers do not bear the cost of securities litigation associated with a securities claim related to an ECR project. Therefore,
The PCIA is a Commission-approved charge that was developed to address the potential for cost shifting when bundled customers switch to unbundled direct access service. As described in D.11-12-018, the PCIA is a “nonbypassable surcharge which direct access (DA) customers pay to offset any cost impacts on bundled customers associated with their departure from or return to bundled service.” The methodology for calculating the PCIA was last set forth in D.1112018. The indifference amount is updated annually in each IOU’s Energy Resource Recovery Account (ERRA) proceeding. The PCIA is “vintaged” for individual ratepayers based on the year the customer left bundled service. As proposed by the IOUs, when a customer signs up for the GTSR Program, he or she would be subject to the then-current PCIA charge for that vintage year. Customers who enroll in different years could see different PCIA charges. Each vintage PCIA can change from year to year. For the period beginning July 2014, PG&E’s residential PCIA was set at approximately 1.1 cents/kWh. SDG&E does not currently have a residential PCIA. For illustrative purposes SDG&E estimated a PCIA of 0.017 cents/kWh for GTSR customers. SCE proposes an indifference amount that includes the vintage PCIA and the Competitive Transition Charge (CTC). PG&E and SDG&E collect the CTC outside of the customer generation charge and therefore have not specifically addressed how to include it in the generation charge for GTSR customers. SCE, however, collects the CTC from customers at the same time and by the same process as the PCIA. Thus, the GTSR indifference amount calculated by SCE should include both the PCIA and CTC. All three IOUs are directed to describe in their CSIAL how the CTC will apply to their GTSR customers.
In this consolidated proceeding, parties served testimony and filed briefs prior to the interim RIC adder set in R.11-05-005. In December 2014, parties were invited to brief whether (and how) the RIC adder developed in R.11-05-005 should be applied to GTSR customers. ORA and other parties argue that the interim RIC adder should be used to calculate a RIC charge applicable to GTSR customers from the start of the program. In contrast, SDG&E argues that the RIC adder is intended to be used for bid evaluation, not for allocating the cost of renewables integration. There is no record in this proceeding regarding whether the Commission will ultimately determine that renewable integration costs should be collected from the renewable energy provider or from ratepayers. Because the RIC adder from D.14-11-042 is being used on a going forward basis, there is no methodology for determining the RIC for existing projects. If a RIC charge is applied to GTSR customers on a volumetric basis instead to the power producer, we cannot assume that the RIC charge will collect the full cost of renewables integration for each facility. If a GTSR facility is not fully subscribed, and the renewable integration cost for the facility is to be borne by the GTSR customers, the calculation of a fair RIC would be complex. Aside from SDG&E, the parties have not addressed a circumstance such as this one, where a value has been set for a RIC adder, but the Commission has not indicated to whom or the how the costs should be allocated. SDG&E, PG&E and the Settling Parties argue against applying the RIC charge to GTSR participants that sign up prior establishment of the RIC charge. The cost of renewables integration is an important procurement issue that is still being addressed at the Commission. It is likely that a RIC charge can be calculated in the near future based on Commission directions. In the meantime,
GTSR customers benefit from rate certainty because their rates have less relationship to volatile fuel costs than other customers. Providing assurance of bid acceptance will increase developer interest in ECR projects. 120% of expected annual load is a reasonable approximation by which to set a customer’s 100% of energy demand for purposes of ECR subscriptions. To ensure reasonable rates and fulfill the purpose of the ECR component of the GTSR Program it is necessary to ensure that ECR projects achieve and maintain a reasonable minimum subscription capacity. Setting a lower price for unsubscribed energy from ECR projects will incentivize developers to achieve and maintain reasonable minimum subscription capacity. The lesser of the DLAP price or the PPA price is a reasonable proxy for the market value of unsubscribed ECR project energy transferred to an IOU. Unsubscribed ECR project energy must be transferred with the associated RECs. In the event that RECs associated with unsubscribed ECR project energy are transferred to an IOU at the DLAP price, the developer should be compensated for the market value of the REC, however in no event should this combined amount exceed the PPA price. A method for determining the market value of the REC for unsubscribed ECR energy that is transferred to the IOU has not been considered in this proceeding. ECR projects where customers own or control an interest in the project or company owning the project could constitute a security subject to state and/or federal regulation.