12/6/17

TURN Avoided Transmission Cost Proposal

1.Introduction

TURN appreciates the work conducted by the avoided transmission cost working group (WG) over the last several months. There has been meaningful progress primarily in framing what the issues are, but little in the way of deeper analysis. For example, there has been virtually no use of historical or forecastdata to better understand fundamental issues regarding transmission projects that DERs can or willactually defer. This limits the factual basis on which TURN and other stakeholders have to rely for a very complex topic, and TURN believes that additional fact-finding is necessary to incorporate any type of meaningful value into the DERAC tool that actually improves upon the existing methodology.[1] TURN presents recommendations regarding next steps and TURN’s avoided transmission cost proposal in the ensuing sections.

2.Additional Fact Finding and Coordination with CAISO is Necessary

TURN plans on responding to other stakeholder proposals to supplement the record. However, as noted there is a paucity of information and facts on which the Commission can rely in making its decision on how to develop more granular avoided transmission cost values. Rather than arbitrarily picking methodologies and numbers, the Commission must rely on some record evidence. TURN suggests two possible paths.

First, the Commission could order a study be performed by an outside consultant, with input from the utilities, to address basic gaps in knowledge. Such a study should include at a minimum discussion and explanation on the following issues:

  • The types of transmission projects that can reasonably be deferred by DERs (including discussion of proper deferral screens);
  • The types and value associated with transmission projects that have been deferred by DERs historically(and the accompanying value to ratepayers);
  • How each DER’s load/generationprofile affects transmission projects (or not).

Alternatively, the Commission could set a procedural schedule for litigation that includes expert testimonies and evidentiary hearings to determine a methodology for transmission avoided costs.

TURN recommends the CPUC coordinate with CAISO to develop a process that would allow for the use of relevant and necessary CAISO data from the Transmission Planning Process to help address basic gaps in understanding or data.

In addition to a fact-finding process conducted through a study or litigation as discussed above, TURN recommends that the CPUC coordinate explicitly with the CAISO to ensure that any avoided cost value in the DERAC reflects a reality in which the CAISO actually defers transmission projects through procurement of DERs, better forecasting, and other mechanisms. Ratepayers would be harmed if the CPUC adopts a value for avoided transmission costs that does not in some way influence actual transmission planning and project construction.

3.TURN Avoided/Deferred Transmission Cost Proposal

TURN provides an outline for an avoided transmission cost methodology below. It is based on the WG’s discussions to-date andthe following principles which TURN believes should help guide any ultimate implementation of an avoided transmission cost value:

  1. All values must correspond to revenue requirement reductions for the IOUs and CAISO. Otherwise ratepayers may pay twice for the same project.
  2. Forecast impacts from DERs that are intended to reduce transmission investments must flow through appropriate CPUC or CEC forecasts to impact CAISO TPP.
  3. Values must be determined in an analytical fashion and be based in known fact.
  4. Estimated avoided cost values should be for evaluation purposes only; actual payments to DERs should be based on competitive solicitations so that ratepayers have the opportunity to save money in comparison with business-as-usual.

TURN proposes a deferral value over the initial 10 year CAISO planning period based on the WG’s discussions to-date. The annualCAISO transmission planning process (“TPP”) should be the starting point for planned projects included in the avoided cost calculation. The valuesthat form a basis for the transmission avoided cost should be updated annually and based on the following elements:

  • Deferral values for DERs related to transmission projects planned due to load growth should be based on an understanding of the peak hourly demand of the projectcombined with expected peak hourly reduction from a given DER. For example, a resource that does not contribute to reducing peak load would not be awarded value for a particular project.
  • Only projects identified by CAISO as potentially deferrable by DERs (generically any “non-wires” or “preferred resource” alternative) should be included in the avoided cost value. Projects should be removed if CAISO determinesthrough the TPPthat a non-wires alternative is not feasible. This includes the following two categories of projects:

1)Transmission projects identified by the CAISO as potentially having a non-wires alternative;

2)Transmission projects for which alternative proposals to deploy DERsarereceived by CAISO from an outside entity (PTO, DER provider, etc.).

  • Deferral values should be locational in nature wherever possible, applying to an entire DLAP, sub-lap, or other area of granularity where a project is proposed to be built. In the future, the Commission should base locational values on load-flow models to determine where DERs have the most impact on reducing peak load for a given constraint. Existing load-flow exercises conducted in the TPP or for local capacity determinations may be leveraged to this end.
  • A price cap on Local Reliability Areas marginal transmission costs could be set equal to the costs of generation alternatives, such as market prices for local Resource Adequacy capacity in each area or the CAISO’s Capacity Procurement Mechanism price. A computation of the deferral value of new generation investment could also be applied as a price cap to ensure reasonable deferral value results.
  • Computation of deferral values of avoided transmission investments should be computed using the “NERA Method” which the utilities now use to compute marginal transmission and distribution costs for rate design purposes.

TURN notes the above proposal is just for “planned” transmission projects. The category of “unplanned” projects encompasses two categories of projects – 1) those that would have been planned if not for forecast DERs and 2) projects outside of the ten year planning period. For the latter, TURN believes the current (IOU or system-level) marginal cost values in the DERAC calculator should continue to be utilized. For the former, TURN will respond at the appropriate time to IOU proposals. TURN reserves the right to modify its proposal at a later stage of this proceeding.

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[1]TURN notes that presently the DERAC does include a system-wide avoided transmission value based on each utility’s marginal cost.