Distributed Energy Resource Optimization: Page 4 of 5

Implementation Timeline

For many stakeholders, the adoption of advanced distribution planning tools cannot come fast enough. The number of interconnection applications and associated engineering reviews has skyrocketed in recent years, and the resulting bottlenecks have increased interconnection timelines in California. An automated and clear interconnection process would improve transparency for project developers, minimize uncertainty for customers, reduce strain on utility engineering staff and meet the CPUC’s mandate for dramatically streamlined interconnections. As a peripheral benefit, advanced planning tools would free up bandwidth, allowing IOU interconnection staff to focus on larger, more-complex interconnections.

ICA implementation. With regard to the ICA, the implementation date is well within sight. The CPUC requires that all three major IOUs—Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric—submit full ICA maps to the ICA working group in Q3 of 2018. From that point forward, the utilities will update the ICA maps on a monthly basis using the iterative method.

It is important to note that the initial ICA maps will serve as a general planning tool only—all projects must still submit to and pass through the Rule 21 process. To remedy anticipated conflicts between the ICA and the existing process, the CPUC opened a rulemaking proceeding in March 2018 to begin re-evaluating Rule 21 based on the real-time results of the ICA, with the intent of streamlining the most troublesome screens. This rule-making process is expected to close in late 2018, setting the stage for adoption in early 2019.

Sky Stanfield, the senior special counsel for Shute, Mihaly & Weinberger, a law firm representing the Interstate Renewable Energy Council, cautions that full ICA implementation is not likely to occur before summer 2019: “While the Rule 21 rulemaking incorporating the ICA may end in late Q4 2018 or early Q1 of 2019, full implementation will likely be delayed until Q2 2019, at the earliest.” She explains, “The utilities will need to file advice letters implementing any order from the commission, and there will need to be resolutions approving those advice letters.”

LNBA implementation. The LNBA has a longer timeline for implementation than the ICA. Eventually, the LNBA will likely inform future net-energy metering (NEM) rates. However, the metrics for assessing avoided costs on a per-MW-of-DER basis need significant refining. While the LNBA working group makes it clear that the LNBA does not have any framework or mandate to assign credits to DER providers as a function of avoided IOU upgrades, the work it is now doing appears to be geared toward achieving this goal.

According to the LNBA final report, two future rulemaking proceedings—Net Metering 3.0 and future cycles of the Integrated Resource Planning process—may allow stakeholders to use the LNBA for assigning additional compensatory mechanisms to DER development in areas where utilities can use interconnected DER capacity to avoid future upgrades. The working group notes that recent CPUC decisions have deferred significant changes to NEM incentive levels because “the NEM successor tariff is expected to consider LNBA-derived locational values.” Such statements hint that the LNBA is much more than a planning tool for IOUs. However, only time will tell if and when LNBA data could facilitate additional compensation for DERs.

POTENTIAL CHALLENGES

Anytime regulators introduce a new tool into an emerging market, they run the risk of unintended consequences. The ICA working group has expressed concern, for example, that developers will clog up the Rule 21 queue by using the ICA to beat their competitors to certain sections of the utility grid. Another concern is that developers will hold queue positions by submitting bogus interconnection requests.

While these fears may seem unrealistic at first glance, unscrupulous stakeholders could in fact game the system if policymakers do not put the proper safeguards in place during the rulemaking proceeding surrounding the ICA. One proposed method of managing disingenuous interconnection applications is to shorten the timeline for meeting certain financial and contractual milestones required to keep a project moving through the Rule 21 process. Another idea is to require that developers provide a contract signed by a verified landowner or facility operator to demonstrate that a project is legitimate.

The lag time between the release of complete ICA maps in July 2018 and the full incorporation of the ICA methodology into the Rule 21 tariff is another sore point for many stakeholders. It is likely that in some instances the unofficial ICA map results will conflict with the results of traditional Rule 21 studies. This will present an early test for IOUs and regulators, who will need to examine what is causing the discrepancy. For this reason, DER project developers should use the initial ICA maps as an informational tool only—much as they do the current RAM maps—until the Rule 21 tariff officially includes the ICA results.

Some stakeholders worry that the ICA will fall short of its promise—see an example of a possible use case in Figure 5—as long as a gap exists between policy and implementation. Tony Pastore, the principal at AgEnergy Systems, a company that specializes in helping California farmers integrate solar, energy efficiency and monitoring projects, worries about this potential issue: “I do not see where the utilities are committing to the ICA as a 100% accurate tool to expedite engineering studies. The only thing that will increase interconnection speeds is to have CPUC-imposed timelines with consequences for utilities that miss deadlines. Improving the transparency and accuracy of utility infrastructure mapping may make it easier for utilities to perform interconnection studies, but utilities will not complete the engineering reviews any more quickly unless the CPUC imposes rules on them.”

The gap between policy and implementation is most apparent with regard to the LNBA. No plan is in place to translate LNBA results into compensation for optimally located DER interconnections. This gap will probably lead most of the DER industry to avoid using the LNBA in the short term. However, developers should keep an eye on the LNBA map when considering long-term development opportunities. By the time a project reaches maturity, compensation mechanisms may fall into place that award additional compensation based on location.

Pastore continues, “In California, stakeholders are still deeply at odds, arguing about the value of solar generated energy. Conservative think tanks say that solar customers are not covering their fair share of grid costs and are deeply gouging nonsolar customers. Solar advocates think that the value to solar generated energy is ever increasing, especially with the addition of energy storage to improve resource dispatchability and provide ancillary grid services. Until we can all agree on the value of solar generated energy, both sides will continue to lobby CPUC staff and legislators from their viewpoint. The locational value of DER should be specific, but it also must be dynamic as the grid is always in flux. Modern technology is facilitating better mapping, real-time facility status, instant communications, better monitoring and asset assignment algorithms, and other tools that will allow us to see a clearer picture of the grid. Over time, it will become easier to assign value to the various grid services that DERs can provide, especially as deployment of these technologies scales.”

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