Chapter Seven: Next Steps and Future Challenges

Among the most valuable lessons that other jurisdictions or utilities can learn from California’s Distribution Resource Planning (DRP) process is that it is a lot easier to imagine an end goal than to know in advance all of the steps required to reach that goal, or how long the journey will take.   

“The most important outcome from the DRP proceeding is that it provided a framework for asking questions,” observed CPUC President Michael Picker.  “We’ve identified the big roadblocks to implementation, in some areas we’ve gone as far as we can. We need to take stock on the DER Action Plan. I don’t think timelines are what we need to be focused on.”

“California was the first place to try to do these things at scale. It takes longer when you are the first,” concurs Paul DeMartini, author of the “More Than Smart” document that helped California shape its DRP. “Other states are further along now that they know the ‘art of the possible.’  The industry and the tools are farther along and there is a better understanding of what is needed.”

In retrospect, provisions of the underlying DRP legislation AB 327 established expectations that far exceeded what the utilities, regulators and the distribution system were capable of providing in 2015, when the IOUs filed their initial attempts at distribution plans. Only now, five years into an exhaustive stakeholder process to work out fundamentals, is California ready to apply its new mapping tools and refine its market expectations to actually allow DER to be more fully integrated into planning and help inform rate case requests.  

Other states can bypass some of the difficulties that California encountered, agreed several DRP participants.  “There’s an enormous learning curve. Other states can learn from California.  Distribution systems are the same everywhere, the issues are the same. They can use demo projects to work out better ways of doing things and once the demos are done, they can roll them out statewide,” said Sky Stanfield, who represented the Interstate Renewable Energy Council (IREC) in the DRP process.

Stanfield continues, “With the benefit of seeing the evolution of California’s process, other states can define more specifics upfront.  It doesn’t make sense to tell the utilities to do a plan and then work out what needs to be done later if you can provide more specifics upfront.”

Based on the experiences of pilots to see whether DER can effectively displace or defer traditional utility investments, it is clear that, “The easiest, best low-hanging fruit has been fairly large generation displacement,” says Damon Franz (Tesla).  “There are challenges trying to solicit DER for meeting utility distribution needs due to the narrow geographic areas that need to be targeted. It needs to be a streamlined standard offer.  The competitive model is almost anti-competitive when the winner takes all and becomes the sole provider of DERs on a particular distribution circuit.”

Instead of pursuing competitive solicitations for small scale DER or aggregation opportunities, other states should consider a tariff approach, much as California is now developing in the parallel Integrated Distributed Energy Resource (IDER) rulemaking.  

In the current phase of IDER, the Commission signaled strong interest in developing standardized distributed energy resource tariffs, seeking proposals from intervenors and utilities and eventually vetting seven alternative approaches during workshops in early March 2019.  While the IOUs initially resisted the tariff approach, both PG&E and SCE offered proposals for consideration, as did several DER proponents.

Post workshop comments indicate a continuing divide among parties on the value and benefits of DER tariffs.  Those who favor tariff structures argue that it will streamline the procurement process, saving developers months while adding certainty to their efforts.  On the other hand, PG&E and utility union representatives continue to claim that DER tariff proposals for distribution deferral involve substantial risks to reliability, quality, and affordability of service.[1]

Joining these criticisms of proposed tariff ideas was the California Public Advocates Office (CalPA, formerly Office of Ratepayer Advocates), which urged the Commission to continue employing the Distribution Investment Deferral Framework (DDIF) and work towards incorporating DER additions via the utilities’ Integrated Resource Plans (IRP).

The Commission has not yet issued a determination of how it will proceed on the issue of tariffs.

“We need to rely on tariffs because the RFOs are not working,” said Scott Murtishaw of the California Solar & Storage Association. “Once the [IDER ALJ] turns attention to tariffs, things can move more quickly.”

Even with the mixed results of RFOs and demonstrations, most of those interviewed for this project agree that the DRP Integrated Capacity Analysis, the Grid Needs Assessment reports, and the load growth scenarios will be valuable tools as utilities face the need to modernize the electric grid, whether to build resilience against such threats as wildfires, or to prepare for new waves of technological innovation that are bound to come in the future.

With greenhouse gas emission reductions – taken to the point of potential elimination – as a looming state policy, electrification of the energy system will place a greater importance on making the most of the utility network, and may accelerate trends toward removing barriers between distribution and transmission level markets.

“We’re going to have to break down the distinction between transmission and distribution, and that will raise all sorts of issues,” said IREC’s Stanfield.  “We cannot continue to pretend the systems are separate, especially if we want to do DER aggregation. The process started with PVs and electric vehicles.  Building electrification adds another piece. It could radically expand load and the nature of the load.”

The environmental overlay of issues onto traditional utility operations has to be taken into account, added Merrian Borgeson of the Natural Resources Defense Council (NRDC). “We want to see new electric loads that are grid friendly.  If we’re already paying money for stuff, we can choose where we incentivize and move it to places where it provides more value.”

A value of DRP is that it can help bridge those policy goals as long as utility operational needs are met, indicated Bill Peter of Pacific Gas & Electric. “We need to integrate operations with planning and make sure that operational needs are considered in the planning process.“

Other states just beginning their consideration also have the opportunity to start from a more holistic view of bridging those goals, suggested Lorenzo Kristov.  

“One of the missing pieces is bringing local government planning into distribution system planning. What affects our GHG goals has a lot to do with urban planning — things like housing density, land use, building codes and mobility services,” Kristov said.  “How do power system planning and urban planning come together? You can meet local electrification objectives and be grid friendly. The first step is a more transparent distribution planning process and a structure for collaboration between distribution utilities and local governments.  The things that make a difference to greenhouse gas reduction and resilience are at the community level, like zoning and transit-oriented development.”


As this Retrospective stated at its outset, the five year anniversary of the DRP provides a good opportunity to review what has been accomplished and determine what still needs to occur and how best to proceed. 

With regards to accomplishments, these seven articles show how the DRP has introduced new transparency into distribution planning and operations, followed by market signals to DER providers to guide their siting and marketing decisions. At a surface level, these are substantial. But below the surface, this DRP retrospective helps reveal an even greater accomplishment: new shared understanding of the respective interests of the disruptors and incumbents alike. And not only understanding for the benefit of policy-makers, but between participants, too. This mutual understanding may yet be an asset that outlasts the DRP rulemakings, reports, maps, and market mechanisms.

With regards to what still needs to occur, the interviewees core to this Retrospective point the way: 

  • Keep asking questions, evaluating alternatives and pushing against settled thinking;
  • Learn from successes and failures, adapt, and move forward;
  • Test market mechanisms: extend those that works, replace those that don’t; 
  • Anticipate how the DRP will serve the next challenges, like wildfire risk mitigation and electrification;
  • Close the inertial and institutional gaps between planning and operations, transmission and distribution, the State and its communities.

With regards to how best to proceed, not a single interviewee suggested this work is complete; not a single respondent suggested California should quit. On the contrary, this retrospective shows California’s DRP “to do” list remains robust and stakeholders have an appetite to continue pushing forward. 

In sum, celebrate the last five years, bank the insights gained thereby, and buckle-up for the next five years. For our part, Gridworks agrees to host a good party for the ten year anniversary!