Distributed Energy Resource Optimization
Inside this Article
The way that utilities study distributed energy resource interconnections in California is about to change dramatically. Depending on whom you ask, this has the potential to be a good thing — or a great thing.
At the beginning of a solar project, every customer or potential customer asks two fundamental questions: How much is the system going to cost? How long will it take to complete the project? To their credit, most solar developers do everything in their power to paint an accurate picture of interconnection costs and construction schedules. However, two major variables get in the way of that effort: the utility review and the interconnection timeline.
As I explained in a previous SolarPro article, “Distributed Energy Resource Saturation” (July/August 2017), the solar industry has no tool at its disposal to provide any real certainty surrounding the scope, cost and time frame of utility upgrades. The reality is that it could take 60 days or 2–3 years. The cost of the upgrades could be nothing or could be $2 million. The developer will not know for sure until completion of the utility interconnection study. These wide ranges of uncertainty do not help with financial planning, especially when a client is looking to secure financing for project development.
Here I elaborate on the distribution planning tools that stakeholders in California are developing to streamline distributed energy resource (DER) interconnections and proactively identify optimal locations for DER deployment. The days of anxiously waiting for the Rule 21 process to run its sometimes excruciatingly long course may soon become a thing of the past because of the keen foresight of California’s Distribution Resource Plan working group. It seeks to expedite review timelines based on proposed DER interconnection locations and establish a mechanism for assigning the real avoided utility-upgrade cost associated with these interconnections. For many solar industry stakeholders, the development of these new tools is very welcome news. Furthermore, the distribution resource plans developed in California will likely serve as models for future DER integration throughout the US—and perhaps even in other parts of the world.
Distribution Resource Planning in California
In October 2013, Gov. Jerry Brown signed Assembly Bill 327, the net metering and rate reform bill, into law in California. Section 8 established Public Utilities Code Section 769, which requires investor-owned utilities (IOUs) to develop distribution resource plans identifying optimal DER deployment locations. The California Public Utilities Commission (CPUC) initiated the process for these plans in August 2014 and issued a ruling in May 2016 establishing the Integration Capacity Analysis (ICA) and Locational Net Benefit Analysis (LNBA) working groups, comprised of stakeholders representing the IOUs, the DER industry and ratepayer advocacy groups. While there is synergy between the two working groups, they serve different functions with regard to streamlining and promoting DER integration. The goal of these efforts is to move from a reactive distribution planning process with minimal transparency and public involvement to a proactive integrated distribution planning process, as illustrated in Figure 1.
INTEGRATION CAPACITY ANALYSIS
As detailed in the final ICA working group report filed on March 15, 2017 (see Resources), there are two primary use cases for the ICA: “The first and most developed use case…is to improve interconnection, which includes a more automated and transparent interconnection process and the publication of data that helps customers design systems that do not exceed grid limitations. The second and currently less developed use case…is to utilize the ICA to inform distribution planning processes to help identify how to better integrate DERs onto the system.” The first use case is most relevant to solar industry stakeholders in the short term.
Intent. Interconnecting DER in California currently is a bit like playing Minesweeper on a PC from the early 1990s, which involves a fair amount of guesswork. You might pick a good square (interconnection location) and open up half the board, or you might hit a mine that ends the game (kills the project). The ICA working group seeks to transform this game of chance into a predictable process by identifying optimal locations for solar development and quantifying the available interconnection capacity well before submission of an interconnection application. Consider that it currently takes at least 110 business days to complete a detailed interconnection study under California’s Rule 21 engineering review process. The ICA process, in contrast, will effectively run a detailed study for every node of an IOU’s grid on a monthly basis.
Brad Heavner, the policy director for the California Solar and Storage Association (CALSSA, formerly the California Solar Energy Industries Association), notes, “If the ICA is successful in making project development go smoother, it will avoid the many cases where customers are paying financing costs while interconnection delays keep them from achieving bill savings. Happier customers should lead to more business for solar developers.” He adds, “The ICA will not lead to an overall increase in hosting capacity throughout the state. Rather, we will know ahead of time what the available interconnection capacity is in any location.”
It is tempting to draw parallels between the ICA and the Renewable Auction Mechanism (RAM) program maps the CPUC has made available for several years now. However, there are several key differences. RAM maps are not connected to the Rule 21 tariff in any meaningful way, so there is no guarantee that the hosting capacity indicated in a RAM map will hold true when a project enters the Rule 21 process. In addition, the RAM maps are very broad and only illustrate capacity at the feeder level based on very conservative rules of thumb. Having run into these limitations on several occasions, I and many other stakeholders have abandoned using the RAM maps altogether.
The ICA approach is different. Because IOUs will use ICA results to fast-track existing Rule 21 tariff screening procedures, the hosting capacity values will be much more accurate. In addition, the ICA methodology is far more comprehensive than that used to produce RAM maps.
Heavner explains, “While the theory behind RAM maps is good—showing circuits as red, yellow or green depending on their hosting capacity—the maps have been so inaccurate and out of date in practice that they are barely useful. The ICA takes the theory behind RAM maps and does a much better job in practice by conducting a functional analysis with monthly updates. The analysis will not only be baked into the interconnection application process, but also the maps will include downloadable data on hourly and seasonal constraints.”
Demo A. The Distribution Resource Plan working group mandated that all three IOUs in California test and demonstrate two methodologies—a streamlined method and an iterative method—for development of the ICA tool. On the one hand, the streamlined approach uses complex computer algorithms to draw conclusions on DER hosting capacity at specific points within the IOU’s system. On the other, the iterative approach simulates power flows based on different DER levels at each node on the distribution system. As the CPUC mandates, the IOUs executed Demonstration Project A, or simply Demo A, with the goal of developing a common ICA methodology that works across all utilities.
The IOUs concluded that while the streamlined method uses simpler equations and enables faster computations, the results lack the level of granularity needed to replace major choke points in the Rule 21 review process. Though the streamlined method provides a reasonably good measure of hosting capacity, its results still require confirmation by a standard review process. In comparison, the iterative approach provides a more accurate and thorough assessment of DER hosting capacity but requires much longer processing times. This is because this approach must accommodate millions of iterations to model the almost infinite combinations of DER and load power flows that can arise throughout the system.
For industry stakeholders, a high level of accuracy is necessary to instill confidence in the process and to encourage active use of the ICA. In the end, the ICA working group settled on having all three IOUs utilize the iterative method for development of the ICA tool. The IOUs published the results of their first Demo A test cases on their graphical information system mapping tools in 2017. Stakeholders now have an opportunity to use Demo A and play an active role in its refinement prior to computing the ICA for entire service areas.
As shown in Figure 2, the ICA tool operates based on relatively easy-to-read heat maps that graphically illustrate optimal DER locations by overlaying ICA analysis data on a graphical information system map, accessible to the public via a web portal. The ICA tool assigns a green color to any distribution-line segment that can support a relatively large amount of DER; orange and red line sections represent locations with a decreased ability to support DER capacity. By selecting a line segment, users can access additional data-defining limits for different types of DERs. These specified limits do not rule out interconnections that exceed these limits, but rather set the expectation that larger systems should prepare for longer interconnection review timelines and substantial upgrade costs.
LOCATIONAL NET BENEFIT ANALYSIS
Per the final LNBA working group report filed on March 15, 2017 (see Resources), the LNBA “evaluates DERs’ benefits at specific locations” with the ultimate goal of ensuring that “DERs are deployed at optimal locations, times and quantities so that their benefits to the grid are maximized and utility customer costs are reduced.” The starting point in this effort is the CPUC-approved “Cost-Effectiveness Calculator” developed by Energy + Environmental Economics, which the LNBA methodology enhances to include location-specific values and avoided-cost considerations. The LNBA utilizes much of the same data as the ICA, but its intended use is different.
Intent. At times it can appear that IOUs view DERs as a hindrance rather than an asset. Since the LNBA seeks to quantify the benefits of DERs at specific locations, it may change the way IOUs view DERs. The basic idea is that optimally sited DERs can serve a load more directly than a remote power plant and provide other grid-stabilizing services that will in turn negate the need for costly transmission and subtransmission upgrades. The final LNBA report clarifies that the working group’s primary focus “has been on creating a methodology for identifying opportunities to defer investments that are already in utility upgrade plans within a certain time horizon.” In the long term, the LNBA could also provide a compensation framework for DERs deployed in certain areas.
Sahm White, the director of policy and economic analysis at the Clean Coalition, a nonprofit working to accelerate the adoption of a more efficient energy system, notes that the 2017–18 Transmission Plan recently released by the California Independent System Operator canceled $2.6 billion in planned transmission project upgrades. He explains, “The forecasted need for transmission projects was lowered mostly because of higher than forecasted impacts of distributed solar and energy efficiency. Since the $2.6 billion in savings reflects only the initial capital costs of the planned upgrades, the actual savings to ratepayers are much higher after accounting for the high return on equity payments to transmission owners as well as avoided O&M costs.”
The fate of the proposed Gates-Gregg 230 kV transmission line in Fresno, California, is a good example of how distributed solar power can provide avoided-cost benefits. The California Independent System Operator identified the Gates-Gregg 230 kV line as a necessary reliability-driven project in its 2012–13 Transmission Plan and opened the project for competitive solicitations. In October 2014, the Federal Energy Regulatory Commission approved transmission rate incentives for the project. Barely 2 years later, in November 2016, the regional transmission manager for Northern California noted, “There do not appear to be sufficient economic benefits to support the Gates-Greg 230 kV transmission line project.” The cause of this dramatic reversal was the rapid growth of distributed solar capacity in the central San Joaquin Valley. The California Energy Commission has forecast that interconnected solar capacity in the region will grow to more than 260 MW by 2021 (it was just 60 MW in 2016).
Demo B. The Distribution Resource Plan working group mandated the development of a unified locational net benefit methodology consistent across all three IOUs. Per the LNBA working group’s final report, the LNBA framework needs to evaluate “the full range of electric services that result in avoided costs,” including “any and all services associated with distribution grid upgrades,” whether these are identified during the utility distribution planning process, the circuit reliability improvement process or the maintenance process. In other words, the LNBA must consider any positive impacts associated with incremental DER interconnections.
A May 2016 ruling approved the framework for the LNBA and authorized the utilities to use this methodology in Demonstration Project B, which serves as the beta test for the LNBA methodology prior to a wider rollout. The LNBA working group monitored and consulted with the utilities on Demo B, which uses the approved LNBA methodology to evaluate one distribution planning area in each IOU’s service area. The approved LNBA methodology relies on planned utility upgrades to assess the value of DERs to the IOUs in certain areas. While transmission and distribution avoided costs are most sensitive to location, DERs also provide other system-level avoided costs, such as avoided generation capacity, avoided energy and avoided ancillary services. Demo B leverages an existing CPUC-approved DER avoided-cost calculator to estimate the value of these system-level benefits.
As executed in Demo B, the LNBA results appear in a heat map, with distribution circuits highlighted in an easy-to-read color-coded scheme, shown in Figure 3. The colors correspond with avoided-cost metrics that the LNBA working group has defined, shown in Figure 4. When users select individual circuits, an informational pop-up box identifies the specific avoided cost that DER interconnection in that area would offset, and indicates the date on which transmission upgrade projects are scheduled to go into service. The pop-up box also provides a generalized visualization of avoided-cost and upgrade-deferral values that allows IOU planners to quickly compare and prioritize interconnections at different locations.
While the LNBA’s visual approach is similar to the ICA’s, the data serve a different purpose. LNBA results aim to help IOU planning engineers understand the benefits in terms of avoided costs that result from hosting DERs at specific locations in the system. Installers can also utilize these data to prioritize interconnections in areas where utilities see DERs as a benefit to the overall electric grid. On the policy side, policymakers may be able to use LNBA data to develop programs or incentives targeting specific locations through distributed resource planning processes, such as the Community Choice Aggregation program or the Integrated Distributed Energy Resources proceeding for IOUs.
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.
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.”
ENGAGING THE PROCESS
The ICA and the LNBA are not a panacea. They will face trials and require continuous refinement. However, it is important to acknowledge that the magnitude of this rule-making effort is unprecedented. The boldness of California Assembly Bill 327 is commendable, regardless of any shortcomings in the distribution planning tools. Furthermore, the tools cannot and will not meet their objectives without the involvement of DER industry stakeholders. Both the ICA and the LNBA are still in development; all proceedings surrounding these tools are open forums. Interested parties not only can access Demo A and Demo B right now, but also are welcome to share ideas on how to refine these tools to elevate DER installations.
Industry advocacy is especially important if the LNBA is to realize its full potential as a tool for improving the economic viability of DER interconnections. Heavner at CALSSA notes, “The LNBA may create opportunities to get direct compensation for targeting solar and storage development in locations where it will defer specific upgrades, but whether the value is worth the trouble remains to be seen.” He cautions, “I am not hopeful that the LNBA, as it has been developed so far, will open a lot of new doors.”
This sobering assessment of the LNBA development process underscores the need for stakeholder involvement. The full 30% federal investment tax credit is in place only through 2019; the tax credit steps down to 26% in 2020 and 21% in 2021 before dropping to 10% in 2022. The LNBA could be a vital tool for replacing these dwindling tax credits, but only if solar industry stakeholders put their shoulders to the wheel. The path from planning tool to industry compensation engine will be long and arduous. The DER industry will get there more quickly if more people are involved and calling for this change. Things will move slowly, but new compensation mechanisms are essential to make sure that DER industry growth remains strong.
Regulatory and government leadership, both in California and elsewhere, is also key to ensure that hosting capacity programs are developed and used to support DER development. Says Stanfield, “The ICA and LNBA are likely to serve as a model for other high-penetration markets in the near term; for many emerging DER markets, there will likely be more of a gradual evolution toward adopting these approaches to proactively integrating DERs on the grid.” To help guide state regulators along the way, the Interstate Renewable Energy Council released “Optimizing the Grid: A Regulator’s Guide to Hosting Capacity Analyses for Distributed Energy Resources” (see Resources) in December 2017. Efforts such as these to normalize and standardize hosting capacity analysis are key to grid modernization and achieving high DER penetration levels.
One state program similar in scope to California’s distribution resources planning is New York’s Reforming the Energy Vision (REV). REV partners utility operators such as Avangrid, which serves over 3.1 million customers in upstate New York, with companies such as Smarter Grid Solutions, which provides software platforms that integrate and control high levels of DER penetration. One such collaboration is the Flexible Interconnection Capacity Solution demonstration project. DER customers who opt to participate in this project can avoid massive utility upgrades by allowing Avangrid to curtail DER production when power levels approach predefined critical set points.
Most utility upgrades are designed to manage specific worst-case power flow scenarios that are possible in theory but extremely rare in reality. In effect, the Flexible Interconnection Capacity Solution allows DER to generate normally during most operating conditions and curtail production only during those unusual time frames when grid conditions are approaching worst-case limits. Therefore, the actual cost impact of DER curtailment on the customers’ bottom line is minimal and quantifiable in advance.
Like many DER industry stakeholders, Heavner is ready to see the CPUC take the next steps: “CALSSA has been part of the working group developing the ICA for several years and is helping to lead the charge on integrating it into Rule 21. We are excited that it’s about to get real.” The functionality and financial benefit of both the ICA and the LNBA are largely as yet to be determined. It is certain, however, that these tools represent the future of DER interconnection in California and will play a key role in how the solar industry develops for years to come.
Tim McDuffie, PE / CalCom Solar / Visalia, CA / calcomsolar.com
Integration Capacity Analysis Working Group, “Final ICA WG Report,” drpwg.org, March 2017
Interstate Renewable Energy Council, “Optimizing the Grid: A Regulator’s Guide to Hosting Capacity Analyses for Distributed Energy Resources,” irecusa.org, December 2017
Locational Net Benefit Working Group, “LNBA Working Group Final Report,” drpwg.org, March 2017