“California’s experience put it years ahead of anywhere else, except Hawaii. The whole concept was a paradigm shift, driven by market forces. Penetration by roof-top PV was at the time ‘tiny’, just noise on the system. But the utilities were getting swamped with new interconnection applications. We were just starting to see on the horizon what a high DER future could look like. If you have this amount of PV on the grid, could you get to a place where DER could displace traditional investment?” Ted Ko, Stem
In 2013, Ko was working as a policy advisor for the Clean Coalition, a national non-profit group with a mission to encourage local energy systems and renewable energy. Like many others, Ko recognized the potential for distributed energy resources as an integral component of utility systems.
With the California Public Utilities Commission (CPUC) fully engaged in its various incentive and support programs for renewables, Clean Coalition began working with the state Legislature. According to Ko, as early as 2009, there had been a draft bill to identify the best places on the grid for DER. It went nowhere.
At the same time, another clean energy proponent, the Interstate Renewable Energy Council (IREC) was investigating whether there could be a better approach for DER on the system.
“In 2013, we drafted an integrated distribution planning paper, addressing how to integrate DERs using a more proactive approach,” recalled Sky Stanfield, an attorney with the firm Shute, Mihaly & Weinberger, who has represented IREC in dozens of state proceedings across the country. “We also engaged in the Rule 21 docket on ways to improve interconnection of individual projects and ways to direct projects to more optimal locations,” she said.
With each legislative session, the impetus grew, and lawmakers and stakeholders alike recognized that programs like Net Energy Metering and the Self Generation Incentive Program were growing by leaps and bounds, but there was less assurance that they were as cost-effective as they might be or delivering benefits where they would be most valuable.
During the 2013 legislative session, these concepts were embodied in a new compendium bill. Assembly Bill (AB) 327 (Perea), addressed a number of issues ranging from reforming the existing net energy metering program, and allowing time-of-use rates, to clarifying requirements for all retail electric sellers to acquire sufficient RPS capacity.
“AB 327 was a net metering change bill that became what some people call a Christmas tree bill,” said Ko.
Importantly, the bill added a new section to the Public Utilities Code, Sec. 769, to require utilities to submit to the commission by July 1, 2015, a distribution resources plan proposal, to identify optimal locations for the deployment of distributed resources. Further, these plans should form the basis for utility investment requests in future general rate cases.
The bill specified five elements that should go into the utility plans:
- (1) Evaluate locational benefits and costs of distributed resources located on the distribution system.
- (2) Propose or identify standard tariffs, contracts, or other mechanisms for the deployment of cost-effective distributed resources that satisfy distribution planning objectives.
- (3) Propose cost-effective methods of effectively coordinating existing commission-approved programs, incentives, and tariffs to maximize the locational benefits and minimize the incremental costs of distributed resources.
- (4) Identify additional utility spending necessary to integrate cost-effective distributed resources into distribution planning consistent with the goal of yielding net benefits to ratepayers.
- (5) Identify barriers to the deployment of distributed resources or threats to safe, reliable service.
As soon as AB 327 was signed into law by then-Governor Jerry Brown, it was clear that implementation would require new layers of technical analysis of the distribution system. In preparation, CPUC staff envisioned a series of workshops and working groups to harness the collective expertise of utilities and stakeholders. But this “paradigm shift” as Ko called it, also required a vision to help guide the effort beyond developing the nuts and bolts of the DER plans.
Governor Brown appointed Michael Picker to the CPUC in January 2014. Picker had been Senior Advisor for Renewable Energy for Governor Brown since 2009 and was well aware of the challenges and opportunities that DER presented. After his appointment, Picker became the assigned Commissioner to a new Rulemaking later that year (R.14-08-013) to implement the distributed energy portions of AB 327.
Picker saw an opportunity to break away from some of the traditional regulatory approaches to policy making. He wanted to enlist expertise from beyond the usual proceeding stakeholders, and he turned to a nascent group of thought leaders who were looking beyond existing system constraints. Picker felt the Commission could find traction from a set of ideas being formulated under the “More Than Smart” initiative that had been proceeding informally, in parallel with the legislative development of AB 327. He wanted to use the resulting draft document “More Than Smart: A Framework to Make the Distribution Grid More Open, Efficient and Resilient” as both a process tool and a vision statement for the new rulemaking.
Heading this initiative was Paul De Martini, who had worked on smart grid issues for Southern California Edison but moved on to a more holistic policy approach with the Resnick Sustainability Institute at Caltech. “’More Than Smart’ drew on discussions we did with a number of stakeholders, and the ‘Grid 2020’ paper we did for Caltech. In it we identified a number of gaps if California was to meet its goals,” De Martini recalled. “There were policies in place like RPS and DER adoption. We asked, ‘What did we need to think about differently?’”
When the Commission launched R.14-08-013 in August 2014, it clearly differed from usual OIR documents in that it was just 15 pages and did not include the usual recitations of background or pose a long list of questions to be addressed in the proceeding.
Instead, the core content of the Commission’s order was Appendix B, the “More Than Smart” paper, and instructions to utility respondents and intervenors that the paper “provides both a basis for questions to be asked in this rulemaking and a useful framework from which this rulemaking will establish policies, procedures, and rules for the development of the IOUs’ DRPs.”
Any attempt to briefly summarize “More Than Smart” would do a grave disservice to its author and its intentions. The paper detailed many guiding prianciples and potential actions needed to realize its concepts. Readers are directed to the document.
But the core of the paper was to outline a four-step “life-cycle” process that could help more DER through an accelerated maturation:
- Use distribution planning to ensure that ratepayers realize the net benefits from optimal use of DER at minimal cost of integration into the electric system.
- Move utilities toward “robust, open, flexible and node-friendly electric network designs” that enable innovation.
- Maintain safe and reliable service across the utility system while enabling access to DER and microgrids.
- Develop markets and programs that “create opportunities for qualified DERs to contribute to the optimization and operation of markets and the grid, and reduce the barriers and costs to participate.”
In laying out a conceptual roadmap of activities over a projected three-year span (some being pursued concurrently), the “More Than Smart” concept envisioned a “graceful transformation” of the electric system. “California needs to consider a more advanced and highly integrated electric system than originally conceived in many smart grid plans. This integrated grid will evolve in complexity and scale over time as the richness of systems functionality will increase and the distributed reach will extend to millions of intelligent utility, customer and merchant devices.”
In other words, a new distribution system model for the 21st century.