This article builds on earlier chapters, which can be reviewed here.
The Integrated Capacity Analysis and Locational Net Benefits Analysis efforts were not the only critical pieces to resolving the DER marketplace puzzle. Throughout 2016 and 2017, five other working groups were engaged in hashing out issues from determining market and load growth scenarios to devising the principles for competitive DER solicitations. CPUC staff would synthesize the output of the groups and recommendations into a series of white papers, which were subject to workshops and stakeholder comments, then presented to the Commission for action in decisions and rulings from Administrative Law Judges Peter Allen and Bob Mason.
Two of the most important CPUC decisions related to distribution planning were rendered in early 2018:
Decision (D) 18-02-004 (February 8, 2018) was a highly detailed assessment of critical policy issues especially focused on refining the Distribution Resource Planning process, and providing direction on matching growth scenarios to utility “grid needs assessments” (GNA). These were meant to guide distribution investment requests to accommodate DER placement on the system. Another important element of the decision was to adopt the long-discussed Distribution Investment Deferral Framework – basically the process for identifying opportunities for DER to defer or avoid traditional distribution infrastructure investments.
The Decision ordered the utilities to file two new annual reports, the GNA report by June 1 each year, and the Distribution Deferral Opportunity Report (DDOR) by September 1. (Later, in response to utility motions, these two reports were rescheduled to coincide in a combined annual GNA/DDOR report).
D. 18-03-023 (March 22, 2018) added another piece to the puzzle, in the form of commission guidance for utility “grid modernization” investment requests in their GRCs (or separate Applications). This became another key to providing transparency into the distribution planning process, by requiring detailed explanations for “primary drivers” of grid upgrades, whether it was demand growth, DER market growth, equipment replacements, or other factors.
Utilities were directed to provide a 10-year vision for their grid modernization plans (GMP), that not only justified the proposed investments based on lowest cost and highest benefits, but also would describe whether any of the GMP investments could be met instead by DER.
Importantly, the Grid Modernization decision defined and broadened the scope of technologies that could be components of a utility GMP – adopting a staff proposed categorization of technologies that ranges from system analysis software and grid management systems, to sensors and controllers essential to maintain circuit stability and system reliability.
Although the DER puzzle was by no means completely filled in, the DRP proceeding had pieced together fundamental components and adopted frameworks sufficient to allow for initial attempts to put “non-wires alternatives” to a market test via solicitation pilots.
The IDER pilots have not been as successful as many parties hoped. “They happened but they did not produce as useful outcomes as we hoped,” said Ted Ko of storage developer Stem.
Here are some examples that illustrate the difficulties:
In early 2017, the CPUC authorized San Diego Gas & Electric approval to go ahead with a DRP pilot solicitation that the utility had described in its July 2015 plans. The so-called “Demo C” intended to validate the use of DERs to defer or avoid investments in traditional distribution infrastructure and achieve net ratepayer benefits as estimated by the Locational Net Benefits Analysis.
The original proposal proved problematic, with SDG&E having to substitute new locations for one of its initial circuit upgrades, and provide better technical analysis for others. Eventually, the solicitation commenced and the utility received 14 offers from unique projects – including energy storage, solar PV plus storage and a natural gas distribution unit. None of the bids were deemed to be cost-effective alternatives, and SDG&E asked the CPUC to let it terminate the solicitation in February 2018 [Res. 4934 accepting termination was approved September 13, 2018).
A somewhat more successful pilot was initiated in a parallel CPUC proceeding, the Integrated Distributed Energy Resource (IDER) Rulemaking (R.14-10-003).
Based on directives from a late-2016 CPUC decision (D.17-12-036) the three IOUs in June 2017 submitted advise letters outlining “competitive framework incentive” pilots to test whether distributed resources could defer or avoid system upgrades. Generally, these were proposed distribution circuit deferrals, in which the utilities identified specific line replacements that would be needed by the year 2020.
Southern California Edison offered three potential deferral projects near Palm Springs and Newberry. San Diego Gas & Electric proposed two circuit upgrades in Carlsbad. Pacific Gas & Electric initially identified an upgrade to the Rincon substation in Napa County, but subsequently requested an alternate site because of severe damage to the area caused by the October 2017 wildfires.
SDG&E completed its solicitation on March 20, 2018 and did not receive any cost-effective bids. PG&E was allowed an extension on its solicitation after identifying an alternative site, at the Gonzales substation.
In November 2018, PG&E issued a new request for proposals for the IDER incentive project, seeking DER to displace upgrades at the Gonzales substation. In April 2019, the utility filed advice letter (AL 5531-E) for approval of two energy storage contracts with GCL. A 1 MW lithium ion battery would be used to meet summer evening peaks at the Gonzales 3 transformer bank, and a 1.75 MW lithium ion battery will be used during summer morning peaks at Gonzales 4. The contracts were approved by the Energy Division on June 5, 2019.
SCE completed its solicitation in May 2018, selecting four in-front of the meter energy storage bids totaling 9.5 MW that will defer the proposed substation upgrades for approximately 10 years. These projects are considered the first successful cost-effective IDER pilot projects that would defer capital investment. Additionally, the bids were able to take advantage of Multi-Use-Application rules that allowed for value stacking by procuring multiple services for a single project.
More recently, however, SCE in July 2019, filed an advice letter updating the CPUC on its solicitation for project deferral offers at two locations, Mira Loma and Sun City. SCE requested permission to conclude the RFO without shortlisting any of the offers it received since the bids did not meet the stated need at Mira Loma and were not cost-effective at Sun City (AL 4037-E, July 15, 2019). The Commission has not yet acted on the request.
“The key value learned was how hard this was going to be,” observed Scott Murtishaw (California Solar & Storage Association). “Utilities established requirements that were difficult to meet with DER. The technical challenges of meeting the need with DER and the timelines were really cumbersome.”
“I’m not sure that any of the pilots were successful,” he added. In the SCE IDER solicitation, “All the winning bids were in front of the meter. The barriers included utilities refusal to allow participation [of market support programs like SGIP] and the procurement opportunities with very specific performance requirements.”
Observers pointed to a number of factors and constraints that limited bidders’ success. One of the things for an SDG&E pilot was the utility was insisting on at least two hours of dispatchability rights with 10-minute notification. Any dispatchable resource had to be almost instantly available. That eliminated multiple use applications for energy storage. A PG&E pilot had a 24/7 availability requirement.
“What DERS can meet those requirements?” Murtishaw said.
Former CPUC Supervisor Damon Franz (Tesla) notes particular difficulties with the structure of bids that attempted to aggregate multiple customer sites to defer a utility upgrade. “The way it was implemented through competitive solicitations was impractical,” he said. “The utility identifies a resource to meet a need, puts out an RFO for companies to get customers signed up. The companies sign up customers, submit their response to RFO promising customers some value, but not knowing if they will win the RFO…all under penalty of defaults. It just seems like a vision that makes sense, but the implementation was impractical do to customer acquisition costs and the uncertainty around winning RFOs.”
“There’s potential to produce pilots that could test the ability of DERs to displace utility investments through the deployment of DERs via a simplified, streamlined offering. But it’s easier if you already have the DER deployed, and the utility simply offers an incentive to dispatch them – for example with battery storage.” he concluded.
More successful has been the ability of larger scale DER to compete against utility investments in generation and distribution. In October 2018, the CPUC approved seven contracts that showed energy storage projects were making in-roads against traditional utility investments. The contracts included one 10 MW energy storage contract proposed by SCE and six energy storage contracts totaling 165 MW proposed by PG&E, including a 20 MW Tesla project to provide distribution deferral services (D. 18-10-009).
Despite the mixed results for these and other solicitations, California DRP participants recognize that it is all a work in progress. “There were definitely lessons learned from the demos,” observed Bill Peter of PG&E. “There’s an inherent uncertainty in distribution planning. So the challenge is to provide flexibility in meeting grid needs while still ensuring the requirements are met. While some demos didn’t result in actual deferments, we did learn about what locations might result in more cost-effective bids. Lessons learned from the demos? Location really matters and we need to focus on prioritizing what locations to try to defer.”