by Shayle Kann
December 11, 2015

Shayle Kann and the GTM Research analyst team give GTM Squared members insight into our internal discussion and debate on the latest business developments across solar, grid, and energy storage markets in this monthly column.

Shayle Kann Senior Vice President, Research: Grid Edge team, as you know, the California Public Utilities Commission (CPUC) has been under the gun to come up with a plan for merging the distribution resources plan (DRP) and the integration of distributed energy resources (IDER) into a cohesive whole. They recently held the first official joint workshop to hash out how it’s going to proceed, along with a straw proposal that helps clarify the timeline for certain key decisions over the next 12 months. There's required reading on the subject by Jeff St. John for GTM Squared that we published just last week.

After reviewing the workshop proceedings and Jeff’s article, what did you learn about the plan? And do you think the CPUC is moving in the right direction to systemically remake energy procurement in California?

Steve Propper Director, Grid Edge: To begin with, I think this is one of the first major attempts at combining large-scale integrated resource planning (the DRP proceeding) with utility/third-party and customer-owned assets (the IDER proceeding) into one regulatory conversation. For years, there have been a multitude of proceedings tackling each part of this separately -- there were solar and distributed generation (DG) proceedings, advanced metering infrastructure (AMI) and smart grid infrastructure proceedings, requests for cost recovery on various new technologies pilots, etc.

There was also the infamous Integrated Demand-Side Management (IDSM) proceeding that languished out there and dates back more than five years, without tangible results at effectively merging overall distributed asset portfolio management at the regulatory level.

So it's encouraging to see the CPUC take some more aggressive action and think more holistically about distribution planning and behind-the-meter resources (which, happily, includes demand response and other "non-generation" technologies). It's starting to sound a bit like New York REV, which isn't entirely surprising given recent talk from Albany on a New York-California distributed energy resource (DER) partnership. And, on the whole, the framework proposed by the CPUC makes logical sense from a business planning perspective.

Shayle Kann Senior Vice President, Research: Steve Propper, you say it's encouraging, but will it be effective?

Steve Propper Director, Grid Edge: I'm cautiously optimistic.

First, I think the timeline for 2016 -- while ideal as a grid-edge technology enthusiast -- is quite aggressive. The January workshop to begin integrating in IDER aspects is what I see as one of the biggest challenges. Full agreement on how to measure benefits, assign compensation and get the methodology squared away for the locational net benefits analysis (LNBA) of the future pilots is key to effectively testing the pilot pipeline planned for the rest of the year (some of which don't have technology or vendor selection complete yet). I'm not totally skeptical, but have doubts on the timing given the amount of moving parts and the likely continued disconnect with how much data utilities are willing to share.

Additionally, I think the goals of having advanced workshops by mid-2016 that detail pilot results and begin to integrate other proceedings like interconnection, storage and electric vehicles (EV) is a bit lofty without an unprecedented level of open dialogue and investor-owned utility-regulatory engagement.

I'd be curious to get Ben Kellison's take on this.

Ben Kellison Director, Grid Research: I would say this is a major step forward for the CPUC. The integrated nature of the conversation around integrated capacity analysis (ICA) and LNBA, if done right, could be a major leap forward in effective valuation and procurement of resources based on their value to the network. This would effectively address the value of solar, help determine optimal resource levels, and guide financial resources to more effective locations on the grid, all in one proceeding.

This is a major shift for the CPUC; it has traditionally siloed all of these efforts into individual proceedings, sacrificing integration for faster implementation. This is a major advantage from an efficiency of capital perspective, but it creates a huge risk in the efficiency of negotiation. Workshops over the next year will have to make some major breakthroughs to set up the DRP pilots for success in the coming five years.

The proceeding also hinges on several major technological and data management efforts to remake planning and simulation processes to incorporate DERs. Initial signs of the complexity involved with this process were shown in July with the release of the DRP plans that detailed the three IOUs' methodology to create an ICA. I am interested to see what compromises will have to be made to the vision of the proceeding in order to achieve value and meet milestones.

For instance, will Southern California Edison be limited in its ability to determine the value of a particular resource on a single feeder because of its choice to utilize representational circuits? Will limitations like this force the CPUC to temper expectations to focus on the saturation and value of a resource deployment at the substation level in the short term and push out timelines for more detailed analysis?

Omar Saadeh Senior Analyst, Grid Edge: Interestingly, DRP and IDER aren’t the only CPUC initiatives planned for full implementation by 2018. Two other CPUC initiatives are also scheduled for full implementation in two years: demand response direct participation and the demand response auction mechanism (DRAM). And coincidentally, both initiatives have also been featured in a past Jeff St. John thriller.

On one hand, the commission’s direct participation initiative will require IOU demand response (DR) programs to be integrated as resources in the CAISO wholesale energy market. On the other, the CPUC’s demand response auction mechanism (DRAM) plans to create a competitive solicitation process for DR providers -- in this case, the IOUs -- to get paid today for future energy reductions. It’s essentially an open bidding DR capacity auction, very similar to PJM's structure.

While all this is undoubtedly very progressive, there are still many questions on the table which may ultimately push back some of these deadlines.

Andrew Mulherkar Analyst, Grid Research: I'm not sure that "progressive" fully captures the nature of the CPUC's work here. It appears to me that this effort is critical element of a tectonic shift in how California's electric utilities plan for, procure, and pay for energy resources. The CPUC is looking to transform traditional, centralized resource procurement into a next-generation procurement process that leverages the extraordinary growth of distributed solar PV, controllable loads, energy storage, electric vehicles and energy efficiency.

The integration of the two proceedings will ideally give utilities both a way to value and plan for distributed energy resources (through the DRP) and to actually procure the resources (through the IDER). Now, as eager as I am to see a comprehensive approach here, the scope of the approach is daunting. As Steve Propper points out, the precursor to IDER languished -- and that's despite a relatively siloed and limited scope.

One exciting idea to emerge from the IDER proceeding is incentives that reflect locational benefits. Once fully developed, it's not inconceivable that consumers could receive solar PV incentives just based on the characteristics of their local distribution feeder. Then we can look back and smile at the days when demand-side management (DSM) meant mailing compact fluorescent lamps (CFLs) to any and every customer.

Steve Propper Director, Grid Edge: ​CFLs! I recall a few Saturdays educating customers about lighting with retail partners like Sears, Lowe's and Best Buy.

I agree with previous comments, but as I was thinking about this last night, I can't seem to shake the importance of the CPUC getting the data-sharing and third-party access components "squared" away early on in these workshops next year beyond the A and B pilots, which look pretty straightforward.

I might suggest they make sure to have some experts from the wireless, banking and/or consumer internet worlds playing an active role in these workshops to push some more aggressive thinking in how this can get accomplished. I understand the utilities' trepidation over security and customer data, but I also think you will see third parties and ultimately customers become more active in participating if it's clear what the benefits are related to DER procurement and ongoing distribution-level management.

Also, as the end-user equation within this joint proceeding gets worked out, I'd hope there is also a realistic conversation about the notion of perceived privacy vs actual privacy over sharing more granular data points such as usage data and behind-the-meter DER asset performance. Think about all the apps that are collecting and sharing customer data today...a far cry from 10 years ago without that much ruckus around privacy.

Omar Saadeh Senior Analyst, Grid Edge: Taking a look at vendor prospects, I think potential opportunities will go beyond incumbent vendors -- those with circuit-level modeling or control systems already deployed at the IOUs -- to companies offering utility distribution management support and third party DER fleet management. Think Enbala, Blue Pillar, Smarter Grid Solutions, Spirae, 1Energy Systems, etc. Moreover, it’s not surprising that DER providers like SolarCity, Sunverge and Enphase have been developing grid software that extends beyond asset management. Not to be overly bold, but I’d expect SolarCity’s GridLogic technology to eventually scale beyond just microgrids.

With regards to DR -- it’s really interesting to see how the vendor community is reacting. As utilities become less dependent on third-party program implementation and with continued uncertainty in wholesale demand response markets, companies are clearly taking notice, some even shifting business models. For example, EnerNOC is diversifying away from market-based DR, which it deems to be higher-risk, and into enterprise and utility software-as-a-service -- a move pursued by Enbala not too long ago.

On a bright note, similar to PG&E’s recent DERMS RFP, I’d expect project scopes to be left somewhat open-ended, providing vendors with opportunities to showcase platform strengths and -- very importantly -- expand capabilities while under utility support.


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