New Edison International CEO Pizarro Calls for Greater Grid Investment to Enable Change

At 5:00 p.m. on September 30, Pedro Pizarro officially took the title of president and CEO of Edison International. He replaces Theodore Craver, Jr., who held the role since 2008, and left the office on September 30 as a Jimmy Buffett song played over the office's PA system.  

Pizarro has worked Edison International since 1999, most recently serving as president of Southern California Edison (SCE), the company’s principal subsidiary providing electricity to more than 14 million people across central, coastal and Southern California. Edison International is also the parent company of Edison Energy Group, which oversees a portfolio of competitive businesses targeted at commercial and industrial customers.

GTM recently spoke with Pizarro about how Edison International is setting itself up for success in a distributed energy future, including a $2.1 billion rate request for grid modernization investments. We also spoke with Caroline Choi, SCE’s vice president of regulatory affairs, about the 1.5 million distributed energy resource (DER) customers SCE expects to serve over the next decade and possible benefits they can offer the grid. (Responses have been edited for readability and flow.)

Telling the entire EIX story

GTM: What are some of the features of your new role at the helm of Edison International?

Pizarro: Part of the fun thing about this job is that it gives you a broader perspective of not just the full company, but also the operations, and the strategy, and the people we have. It also gives you the insight on the investors who supply the capital for us to do all of these things for our customers.

My new role includes working with our board and directly with investors that are investing in EIX [the tracker symbol for the stock]; they’re investing in the entire story.

GTM: You recently served as president of SCE, a regulated utility. What are you excited about with respect to the unregulated business?

Pizarro: Right. We’re doing a lot of work inside the utility on what the energy future is, but we’re also planting some seeds outside of the utility and serving customers with new technologies, which gives us a perspective on multiple angles of the industry.

Edison Energy Group is an umbrella organization for a number of new businesses we started about four years ago. Inside of Energy Group, we have, for example, SoCore Energy that develops solar projects for commercial and industrial customers. We’ve created another entity inside of that group, called Edison Energy, that’s aiming to develop a new service offering for large commercial and industrial customers to outsource their energy management needs, so we provide them with energy as a service.

Edison Energy has also acquired a number of smaller companies; for example, we acquired Altenex earlier this year, which has enabled over 1 gigawatt worth of PPAs connecting renewable offsite developers with C&I customers. Another company we recently acquired, Delta Energy, does over $5 billion per year in commodity procurement for commercial and industrial customers. Then there’s Eneractive, which essentially does engineering and building work, controls, energy efficiency, etc.

We also have investments under Edison Energy Group in the water and energy nexus, and Edison Transmission is pursuing transmission projects under FERC Order 1000. I would say these are all early-stage companies, with the bulk of our work and the bulk of growth we’re providing for investors still being at SCE.

GTM: How is the regulated side of the Edison business adapting to new technologies and competitive customer offerings?

Pizarro: The utility is really committed to being one of the most constructive agents in helping transform the grid. We’re certainly influenced by the fact that we’re in California, a state that has established some really important objectives around carbon reduction and fighting climate change. We recently moved from policy objectives to an actual state law…codifying greenhouse gas reductions of 40 percent below 1990 levels by 2030. That sounds like a long time from now, but it’s not. It’s 14 years away, and there’s a lot of work to be done. We have a strong view that the only way to truly meet that target is to reduce greenhouse gases across every sector in the economy. DERs are going to be an essential component of that journey for the state. They also support the policy objective of giving customers choice.

GTM: SCE recently issued a strategy paper offering a vision for what a distributed energy future could look like. What was the main takeaway from that paper in your view?

Pizarro: Hopefully one of the things people take away is that we view the utility grid as an essential tool to enabling the interconnection of DERs. If you don’t have a robust enough grid, the DERs don’t work because you just can’t plug them in. The ability to send power in both directions is key. We don’t want a repeat like Hawaii and have an experience where the utility wasn’t able to keep pace with the amount of interconnection requests they were getting, and you had long interconnection queues for solar customers. So one takeaway from that paper is to make sure we’re making the right investments at the distribution level.

The DSO [distributed system operator] piece is also important, because at the end of the day customers and regulators still hold utilities responsible for ensuring we have the same reliable service, regardless of what the source of power is — whether it’s coming from traditional resources or DERs, we have an obligation to maintain safety and reliability. We believe, given the particulars of the distribution grid, given how dynamic it is (in the paper, we cite 22,000 different switching operations last year), it’s just a tight level of integration needed between the guys out in jeans and boots in the field and control rooms to make all of that work. That’s one of the reasons we believe we need the DSO role, because you need that situational awareness and coordination; you need that tight integration to keep the real-life operation of the distribution grid going.

GTM: In SCE’s 2018 general case, the utility laid out a $23.3 billion rate request from 2016-2020. Does this represent a different type of rate request than in previous years?

Pizarro: Yes, there is a new piece here. Over last couple of years, our annual investment was around the $4 billion mark across our utility investments. At the end of this year, our rate base will be around the $25 billion mark, give or take. […] This rate-base request is different because if we got everything we requested, our total in capital spend would be around $5 billion per year [from 2018-2020]. Of that amount, around $700 million per year ($2.1 billion total) is for grid modernization activities.

The spending falls into two big buckets. One bucket is for spending on computer-based intelligence, sensors and controls at the distribution level. A big part of that first bucket is upgrading our communications networking capability; we call it our field area network. […] There will be thousands of different data points coming in, not only from our services and controls, but from all the DERs that are interconnecting on the grid.

The second big bucket inside of the $700 million has more of an accent on grid modernization. Across our distribution system, we have something like 4,600 circuits. Over 20 percent of those today are older, lower-voltage circuits — 4-kilovolt circuits. A typical modern circuit is 12 kilovolts or 16 kilovolts. If your neighborhood is served by a 4-kilovolt circuit, that means that that circuit just does not have the same level of capacity to be able to integrate not only existing load, but multiple electric vehicles and solar panels and batteries and what not.

When we did our distribution resources plan (DRP) filing last year, our forecast for how quickly DERs will be adopted on a number of the circuits requires us to significantly accelerate when we upgrade those circuits.

GTM: Related to the issue of utility investments and repayments, Commissioner Florio, who is leading the DRP proceeding, recently issued a proposal that would offer utilities a better rate of return for DER projects that replace more expensive capital upgrades. What did you make of his approach?

Pizarro: I’m personally really encouraged that Commissioner Florio has sped up that discussion, because he acknowledges that there are changes are coming. […] If there are really opportunities to defer or displace traditional utility capital and use some distributed energy resources instead, I think the goal is to make sure it’s a level playing field and that there’s an appropriate incentive for utilities.

The main objective is still keeping the lights on reliably and safely. How we get paid for that is we get to ask for recovery of our cost to the rate base. Importantly, we have investors who put capital into the business, and they get an opportunity to get recovery on that capital. In a way, we get paid for a reliability service through the return on invested rate base. What Commissioner Florio acknowledged was that, as part of fulfilling the reliability mission, utilities are going to turn to resources that might decrease their return on that investment, and that actually removes some of the earning opportunity, because that creates an inadvertent disincentive.

We appreciate the objective of recognizing [a new] earning opportunity for utilities, given their broader role. There are probably multiple ways you can do that. […] But we’re generally positive on the tone of the discussion.

GTM: Are distributed energy resources starting to offset the need to make traditional utility investments?

Pizarro: I think that we’re seeing already a displacement of some of the need, not all, but some of the need for traditional generation by distributed resources, mostly by renewables. But I think, increasingly, batteries will play a role in that. I think it’s a different situation, though, for grid investments. […] The SCE grid is a solid grid, but we see that given the dramatic increase in the number of DERs coming our way that we need to strengthen the grid in order to be able to handle that.

There may be some opportunities to defer investments. […] In our general rate-case filing, we proposed a number of pilots to test some applications. So I think that we have some opportunity for deferral or replacement of grid investments. […] But the larger story is that there’s a pretty significant need for investing in the grid to make sure that we have the electric highway running so that the DERs can ride on that highway.

GTM:  What about energy storage? SCE is aggressively deploying energy storage technology; how do you see it benefiting the grid?

Pizarro: I think it’s fair to say that storage today remains expensive in comparison, say, to ramping a natural-gas-fired plant up and down. However, we’re starting to see some of our large C&I customers on the Edison Energy side…where, let’s say, they have a high demand charge from their local utility. It may well pay to install enough battery storage to shave that peak down and avoid paying demand charges. That's a good thing for them and probably a good thing for the local grid.

On the SCE side, we are pursuing energy storage really aggressively. I think the pace of how aggressively we’re pursuing it is set by the mandates with the 580 megawatts of storage we need to have on-line by 2024.

Living with 1.5 million DER customers

GTM: Caroline, how do you see DER’s benefiting SCE’s grid? And if you do expect benefits, how soon will they be realized?

Caroline Choi, SCE’s vice president of regulatory affairs: We certainly see distributed energy resources continuing to play a role on the generation side. Our preferred resources pilot (PRP) is a pilot that is intended to avoid generation out in the Orange County area. It’s the use of energy efficiency, demand response, and renewable resources like rooftop solar and storage to avoid the need for going out with a [request for offers] for a peaker plant in that area.

The PRP is a near-term project. We kicked that off in 2014. The idea is to make a decision next year around whether or not these resources are having enough of an impact that we can avoid going out with RFPs. Because of the time frames needed to get generation engineered, sited, and then built, we'd have to go out in 2017 for that RFP if we still saw a need. I think we are seeing a real benefit from the resources. But a lot of these PRP contracts will be coming on-line next year, contracts that we have signed last year and earlier this year. That's what will really be telling.

The PRP is about using DERs for generation. Using DERs for distribution grid services, we have identified eight pilots in our general rate case that we filed September 1…where we're looking to utilize DERs to defer traditional utility spending, hopefully. We'll see if we get our general rate case approved. That's obviously very early in the process. The distribution resources plan also has pilots that we will be launching as soon as next year. Those are also intended to demonstrate the opportunity for DERs to offer distribution grid services. I think we'll see some pretty early learnings as soon as end of next year.

GTM: How fast are you seeing customers adopt DERs?

Choi: When we look ahead to what kind of distributed energy resources we see on the grid, there’s obviously a lot of rooftop solar. We’re getting applications that average out to 5,000 a month. When energy storage prices come down, we’ll see faster adoption of behind-the-meter energy storage. In our service territory, we have a number of customers adopting plug-in electric vehicles, but not at the pace we need. So we need to accelerate that.

If you look 10 years out, you could have 1 million to 1.5 million customers with different types of DERs on the grid. It’s pretty amazing and exciting. The faster that happens, the closer we will be to achieving the state’s energy and climate goals.

GTM: You mentioned the fast pace of distributed solar deployments. When will SCE hit its net metering cap under the old NEM policy and switch to NEM 2.0?

Choi: We project hitting our 5-megawatt cap in mid-2017.

The commission came out with a decision earlier this year with NEM 2.0; it’s mostly a continuation of the current retail NEM program, but it’s mandatory that solar customers go on a time-of-use rate when 2.0 comes into effect. The utilities filed applications for rehearing that were denied, so I believe that this decision will stand. The commission said that they would be looking at a successor to NEM 2.0 around 2019.

The commission has also ordered the utilities to put residential customers on default time-of-use rates, which will go into effect in January 2019. We are initiating…large-scale pilots, and working on the marketing and education and outreach to customers to educate them about the changes that will be happening in a few years. That's still underway.

GTM: Will the time-of-use rate have a new structure or different hours?

Choi: We just filed in December to amend the current time-of-use periods. Right now the peak is defined between essentially 12 p.m. and 6 p.m., but it is seasonal. We are keeping the seasons in our proposal and shifting the peak to between 4 p.m. and 9 p.m. We are the last utility to file a change in the time-of-use period. Both SDG&E and PG&E have also filed. Our proposal lines up with theirs.

GTM: During the NEM 2.0 discussions, SCE argued that retail-rate net metering causes a significant cost shift. One Edison analysis estimated that non-solar customers could see their bills rise by $39 per month by 2025. Describe the issue you see and how time-of-use rates can help.

Choi: The commission just kept the retail rate for NEM 2.0. We proposed a different mechanism for customers that were selling power back to the grid. A big driver, as you've heard from others, is the cost subsidy. Almost a third of our customers are on an income-qualified rate…a discounted rate for their bills. They primarily are not the customers adopting rooftop solar, but they are paying for the grid costs associated with it.

I don't know if time-of-use rates solve anything. They’re just more reflective of where the use is, and where the peak actually is now occurring in our system. We can certainly see from our load curve that the peak of our system usage has shifted to later in the day as a result, mostly, of rooftop solar [being used] in the middle of the day. I think time-of-use is definitely going to change behaviors…because there’s going to be a new price signal.

GTM: Pedro, is there anything I haven’t asked that you would want to add?

Pizarro: Again, the main message is we want to make sure that we keep the grid robust and ready to handle as many DERs as customers want to interconnect. We really believe in customer choice. We also believe in the utility and want to have the grid ready. We believe in choice outside of the utility, and want to help customers achieve that on the competitive side across the country. Frankly, it makes me excited about my life over the next however many years I’m doing my job.

from GTM Solar


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