11. Market Elements
11.1. Preferred Locations to Facilitate Interconnections
ED proposes that IOUs make information available on preferred distribution substations based on the available capacity of that substation, updated on a real-time basis.122 This will significantly assist projects to locate in preferred locations, according to ED, thereby avoiding potential distribution and transmission upgrade costs and delays.
Parties generally agree with the need for and desirability of this data, but present a range of views on feasibility and cost.
SCE proposes providing potential project areas (in the form of a zip code and geographic area bounded by landmarks or specific streets), along with an estimate of approximate available distribution capacity. SCE states that it will update this information as often as possible (including prior to each auction). SCE says this is the same as its solar PV Program auction proposal.123
PG&E believes a real time update may require significant investment in communication platforms and resources for system maintenance while not providing significant benefits, particularly if the auction is held only once per year. PG&E recommends a working group to study the issue.124 SDG&E says it is not practical to determine preferred substations and update this list in real-time.125
SFUI says IOUs should provide this data on a real time basis, arguing that many cities and water authorities have their water and sewer distribution maps on the internet for immediate access by construction professionals. FIT Coalition states that Ontario Power Authority maintains two reports with needed FIT interconnection data, updated weekly. FIT Coalition recommends the Commission require each IOU to prepare and maintain an interconnection data report following a specified format, updated in real-time. More specifically, FIT Coalition requests the IOUs to provide the total capacity, allocated capacity, queued capacity, and "available capacity" for all distribution substations and each circuit connected to a distribution substation.126 Recurrent supports ED's proposal with updates as often as auctions occur (not real-time) with information at the zip code level (but not in more detail to avoid a land rush by developers).127
No party argues that substation data is undesirable, or that it is unnecessary for making informed interconnection decisions. The real issues are the type and amount of data, and frequency of updates.
We recognize that it may be infeasible for an IOU to provide information on all substations during the initial rollout of this program given the large service areas of each IOU. Therefore, an IOU may initially focus on what it determines are "preferred" areas. Preferred areas are likely to be those near load where the IOU has a reasonable expectation of surplus transmission and/or distribution capacity.
The data must be sufficiently detailed to be useful. We agree with parties who assert SCE's proposed "project areas" (zip code and area bounded by landmarks or streets) fails to provide sufficient detail. To be most useful to potential projects, IOUs must provide data at the substation or circuit level. IOUs must have this information in order to execute their responsibilities for daily operations, system scheduling, and infrastructure planning to meet current and future demand. For the initial rollout, we adopt the FIT Coalition's recommendation to require the IOUs to provide the "available capacity" at the substation and circuit level, which we define as the total capacity minus the allocated and queued capacity.128 The IOUs should provide this information in map format. If unable to initially provide this level of detail, each IOU must provide the data at the most detailed level feasible, and work to increase the precision of the information over time.
We do not require real-time provision of, and updates to, this information. Rather, we require updates at least once a month. We believe this strikes a reasonable balance between providing timely information to the market and not creating a requirement that is overly burdensome. We require that the information be provided as soon as possible, but no later than 60 days after the effective date of this decision. We also expect each IOU to pursue all cost-effective improvements to provide this data at a more detailed level with more timely updates. In order to facilitate data improvements, each IOU should examine DG interconnection screening tools currently used to screen DG interconnection applications. The IOUs should evaluate how individual project studies could be automated to provide the requested data and a reasonable assessment of a DG project's impact on the distribution system. As renewable DG penetrations continue to increase, new software tools and analytics should be evaluated, benchmarked, and used to keep pace with the expected increasing interconnection requests for incremental small DG units throughout the system.
We anticipate that each IOU will, over time, provide system-wide information. To not do so requires IOUs to continuously determine what are and are not "preferred" areas. That involves judgment better left to stakeholders. IOUs should eventually provide reasonable data on all areas, and let developers, along with IOUs and other stakeholders, decide if it makes sense to interconnect at various locations.
We recently adopted similar requirements with respect to SCE, PG&E, and SDG&E PV programs.129 We therefore expect each IOU to make reasonable initial disclosures, and implement improvements over time. That same approach is reasonable for the RAM. Moreover, we expect the IOUs to simultaneously incorporate data and improvements with respect to their PV programs into the RAM program, and vice versa. Finally, we expect the IOUs to review other utility maps that perform a similar function and to work with parties and Commission staff through the Renewable Distributed Energy Collaborative (Re-DEC) or other forums to order improve the data, usefulness of the maps, and to discuss other issues related to the interconnection of distributed resources.
Finally, to the extent the Commission seeks detailed information concerning SCE's substations and distribution system infrastructure, the Commission should keep in mind that such information is protected by the Critical Infrastructure Information Act of 2002, 18 U.S.C § 388.113. Under that statute, detailed information concerning SCE's distribution system, such as precise substation location, substation design, circuit design capacity, voltage, and load information is Critical Energy Infrastructure Information ("CEII") and must be protected. SCE believes that information for distribution system voltage levels of 115 kV and 66 kV may include CEII and cannot therefore be released publicly.130
The Critical Infrastructure Information Act of 2002 (CII Act) has no bearing on the Commission's decision about whether this information should be provided to potential distributed generation developers. The CII Act distinguishes between submitters and recipients of critical infrastructure information, with the result that the federal statute's prohibition on disclosure of protected confidential infrastructure information applies only when it has been "provided to a State or local government or government agency ..." (6 U.S.C. § 133(a)(1)(E),) See County of Santa Clara v. Superior Court, 170 Cal. App. 4th 1301, 1319 (Cal. App. 6th Dist. 2009). In this instance, the information in question was generated solely by SCE. Because SCE is neither a state or local government agency, nor a recipient of critical infrastructure information from the federal government, the CII Act and accompanying regulations do not apply.
11.2. Qualified Facility Certification
ED notes that for SCE and SDG&E, the Existing FIT contains a requirement that the project be certified at FERC as a QF. ED proposes that there be no such requirement for the RAM.
We agree. The RPS program is not a QF program. (§ 399.15(e).) RAM is not a QF program. We decline to impose a QF requirement on RAM.
This does not prevent a project from certifying as a QF. A project may certify as a QF if it wants, but it need not do so to be eligible for RAM.
11.3. Conveyance of RECs
The Existing FIT provides that RECs are transferred to the IOU in relationship to the amount of the purchase. For full buy/sell under the Existing FIT, the IOU buys RECs coincident with the entire generation output. For excess sales, the seller retains RECs for the electricity it uses itself, and the IOU acquires RECs coincident with the excess energy it purchases. (See D.07-07-027 at 33-35.) ED proposes no change relative to the transfer of RECs. We agree.
The same logic used in our Existing FIT decision (D.07-07-027) to justify transfer of RECs coincident with the purchased energy (either total energy production or excess only) applies to the RAM program. Thus, there is no reason to treat the RAM program differently.
We also decline to complicate these transactions by separating the renewable energy credit (REC) from the energy at this time. A guiding principle in RAM is simplicity, and allowing the separation of RECs from energy adds an additional layer of complication. We may consider separating the REC from the energy in the future, but do not do so here.
122 August 2009 Pricing Proposal at 9.
123 Advice letter 2364-E (process and criteria for evaluating IPP PV offers) resulting from D.09-06-49 (approving SCE's solar photovoltaic program). See SCE Pricing Comments at 7-8.
124 PG&E Pricing Comments at 12.
125 SDG&E Pricing Comments at 7.
126 FITC Pricing Comments at 8-9.
127 Recurrent Pricing Comments at 9.
128 Allocated capacity refers to generators already connected to that substation or circuit. Queued capacity refers to generators in the interconnection queue at that substation or circuit.
129 D.09-06-049 at 40. Resolution E-4299 at 5-7. D.10-04-052 at Ordering Paragraphs 9 and 10. D.10-09-016 Ordering Paragraph 4.
130 SCE Comments on Proposed Decision at 18-20.
