September 4, 2014 - From the September, 2014 issue

Carla Peterman on CPUC’s Evolving Energy Regulations

Appointed to the California Public Utilities Commission by Governor Jerry Brown in 2012 after serving on the California Energy Commission,
Carla Peterman is an authority on energy policy in the state. She recently sat down with MIR to talk about electric vehicle regulation and energy storage, among other topics. Peterman provides an optimistic perspective on both of these areas, taking into account market responses to adopted CPUC’s regulations and initiatives.

Carla Peterman

“[CPUC] initiated a new proceeding...focused not just on supporting electric vehicles and minimizing their impacts to the grid, but also on identifying the benefit to the grid from electric vehicles, capturing those benefits, and providing them to ratepayers.” —Carla Peterman

Carla, you were appointed to the California Energy Commission by Governor Brown in 2011 and two years later to the CPUC. Share how your regulatory responsibilities have evolved. How has energy regulation changed?

Carla Peterman: I think that the agenda is the same for the most part. There is continued focus on low-carbon energy, and helping California meet its greenhouse-gas goals in 2020 and 2050. We continue to move forward, particularly on our 33 percent RPS target.

What has come about in the last few years is an increased focus on low-carbon transportation. In 2012, the governor set a target of 1.5 million zero-emission vehicles on the road by 2025. The governor’s office, together with state agencies, developed a ZEV action plan that laid out specific tasks for each agency to help meet that target.

In terms of my portfolio, I have increased the work on alternative transportation at the Public Utilities Commission that I began on the Energy Commission. For a few years, I’ve been chair of the California Plug-In Electric Vehicle Collaborative, which is a public-private voluntary partnership focused on advancing electric vehicles. We’ve also initiated a new proceeding at CPUC focused not just on supporting electric vehicles and minimizing their impacts to the grid, but also on identifying the benefit to the grid from electric vehicles, capturing those benefits, and providing them to ratepayers.

Give us a sense of how the markets have reacted to these regulatory initiatives.

I think the market is responding well. At the CPUC, we’ve gotten a positive response from utilities and automakers. We’re specifically interested in looking at vehicle-grid integration opportunities and how we can start to measure the benefits.

This is happening at the same time that, as a state, we’re seeing increased levels of renewable energy. That is great, but it’s resulting in challenges with resource integration because these renewables are intermittent. We’re starting to see times when there’s excess solar power and excess wind. Electric vehicles are increasingly being viewed as a solution for this excess generation, using it to power our cars.

How are the state’s utilities, and others, adapting to meet the regulatory expectations that you’ve just shared?

We’re still in the early stages. The utilities have brought forward different pilots for vehicle integration, which the commission has supported. Southern California Edison has one, for example, with the Department of Defense to have electric fleets on their LA airforce base. Those fleets will provide demand response and ancillary resources to the grid and the Independent System Operator (ISO). PG&E has a second-life battery pilot to see what benefit those batteries provide to the grid.

You can see a timelier example in terms of market reactions in our energy storage work. That’s another area I’ve led on at the commission. We as a state, through the CPUC, adopted first-in-the-nation targets for energy storage—1.325 gigawatts by 2020 last fall. When we first set out the proposal, there were questions about whether it would be possible and whether there would be market interest. We’ve seen tremendous interest already.

We’re in the process of working through the utility applications for the first solicitations this fall. Southern California Edison, as an example, has already done a solicitation for 50 megawatts of energy storage, on the commission’s orders. They had over 500 bids, which is a lot of industry response.

Similarly, once we put out our targets, California ISO has received thousands of megawatts of bids into their transmission queue for energy storage projects that are interested in bidding in to the utility storage procurement. We’ve seen other states now include energy storage in their solicitation plans. We also saw Tesla providing information about opening up a gigawatt battery factory to support electric vehicles and customer-side storage. So we’ve seen real growth in that area and a big market response.

Your mention of Tesla compels a question about the multi-state competition (California, Arizona, Nevada and New Mexico) for their planned new battery manufacturing facility.  Is it important that Tesla site their plant in California? How significant would a breakthrough in batteries be for the CPUC?

I think a breakthrough in producing batteries at scale will be critical for lowering the cost of batteries, and therefore electric vehicles and energy storage. These batteries can be used as customer-side storage. They can be used on the distribution system and on the wholesale system. California is supportive of a diversity of storage technologies.

Energy storage is one of the tools we generally use in support of energy management, but it’s not the only one. We have seen greater focus in California on batteries, and then a number of other storage technologies. The cost is a significant barrier. To the extent that Tesla or another company is able to start manufacturing batteries at scale, they can be used for both of these purposes. I think it will be good overall for the electric industry.

Does the CPUC or CARB have a benchmark regarding market penetration of electric vehicles?  How many EVs are presently on the road in California?  

We’ll have at least 100,000 electric vehicles by September in California. We’re in the nineties now. That will be an exciting marker.  

Watching the sales trends is my favorite part. Compared to last year, are sales increasing continuously? We’re seeing that.

In 2015, a number of automakers are planning to have a next-generation version of their cars. Going forward I think we’ll be seeing more models and more choice for customers.

Regarding the nexus of energy and transportation, what new policies or initiatives are now on CPUC’s agenda that our readers ought to follow?

This next proceeding will last for 18 months. We are looking at vehicle-grid integration: What is the resource? What is the opportunity? How would utilities acquire vehicle-integration resources? What would be some of the programmatic structures for doing that at the CPUC? There’s a focus on institutionalizing these opportunities into actual regulatory programs.

We’ll also be looking at demand charges, which have emerged as a potential challenge for fleets seeking to charge in the absence of scale. We have a particular interest in supporting fleet and mass transit EV adoption. 

We’re also going to focus on education and outreach. We get a lot of feedback from the electrification community that customers just don’t understand their electricity as a fuel, and the cost-savings they can have from driving electric vehicles. Depending on where you are in California, your average cost per gallon would be a dollar if you had an electric car (although it can be less than that, for sure), compared to $4-5 for gasoline. Customers aren’t aware of that. They’re also not aware of the electric vehicle rates that the CPUC has established to help them save money.


Finally, we’re looking at how to develop safe, reliable, affordable infrastructure for electric vehicles—and what role the utility can play in supporting that build out.

VerdeXchange 2014 hosted a panel this past January titled “Rethinking Utility Regulation to get from Megawatts to Gigawatts.” Could you predict for our readers what the business model might be for investor-owned utilities in a post-33-percent world?

I can’t predict at this point, but I’ll say it does need to account for a number of considerations—more so than it currently does. It needs to be able to facilitate distributed generation, because we’ve seen a significant amount of interest in this area. Solar PV systems are coming in at prices where, even with the absence of a state subsidy, there’s still demand—because there are also supportive incentives at the federal level in terms of the tax credit.

In accommodating distributed generation, the business model needs to account for bidirectional power flow. It needs to account for new technologies that can help with energy management, such as energy storage, as well as new distributed load from transportation electrification. It needs to be flexible. The cost structure must cover the investments needed for infrastructure, particularly the distribution and transmission lines.

Moving on, this summer the Nevada PUC released new rules that cut incentives to install solar projects in the state by more than half. Does this portend like changes in regulations and subsidies in California?

I’ll comment on this broadly. We are seeing the cost of solar PV come down, and a declining need for incentives. That is a positive because the industry is on a path toward sustainability.

Our California solar direct incentives have declined over time according to schedule. I think in some utility regions there aren’t incentives available anymore, but customers still purchase solar PV systems.

We also incentivize solar PV through other mechanisms, such as net metering. We passed a decision last year that extended the current net metering policy through 2020, or through a certain percentage of power that is net metered (whichever comes first). The commission, directed by AB327, is now determining what the net metering policy should be going forward.

That legislation provided direction to the PUC on net metering—to continue supporting the renewable energy industry and keep it on a sustainable path, but also to appropriately reflect the cost of solar PV systems on the grid. We’ll have to consider all those things in our decision going forward.

We recently carried an interview with Berkshire Hathaway Energy’s Jonathan Weisgall in which he touted the need for energy imbalance markets that allow management of the grid in a regional, multistate manner. Does the CPUC agree with his premise?  

Since we don’t have a direct role in the energy imbalance market, we are observing what’s happening at the California ISO.

As an energy commissioner, I worked on a renewable action plan for the state—suggesting recommendations to help us reach our 33 percent goals and beyond. We published that as a part of the 2012 Independent Energy Policy Report. One of our recommendations was regional coordination through something like an energy imbalance market. Regional coordination can help with renewable integration, because you’ll have a diversity of resources that you’re balancing over a greater service area. 

Moving to California’s cap and trade program: Transportation fuels are coming under the program, as you well know, and there’s an apparent pushback from some in the state legislature. Given close coordination among CARB, the Energy Commission, and the CPUC, could you comment?

Transportation is responsible for about 40 percent of California’s greenhouse gas emissions. In order to meet our greenhouse-gas reduction goals, we’ll need to reduce the carbon in the transportation sector.

Does such pushback portend a change in the political environment in California, which to date has been supportive of AB 32’s emissions-reduction goals?

I honestly don’t know, but I don’t think so. To be frank, there have always been folks who have questioned the cap and trade program, including legitimate questions around costs and benefits. I don’t think that is new.

We have AB 32, which sets targets. We have other legislation that supports low-carbon transportation, such as AB 8, which passed last year to extend and increase the amount available for incentives on low-carbon vehicles, fuels, and infrastructure. I view the legislature as being supportive of greening those sectors. We’ll see what happens, but I’m continuing to move forward with my initiatives. 

Are investor-owned utilities also pushing back? What are the state’s utilities most worried about the CPUC mandating in furtherance of AB32?

There’s a general concern—whether it be from utilities, consumer advocates, or even as a commissioner—about the cost of the initiatives, the cost-benefit, and over what time period they will yield benefits in the longer term. I often hear the concern about rate impacts and affordability. We need to be mindful of transitioning some of those costs, as well as educating the public on why we’re doing these things. 

Lastly, when you again participate in VerdeXchange’s VX2015 in January, what do you envision will be on your policy agenda?

On energy storage, it’s expected by the end of the year that we’ll have a decision and direction from the utilities to go ahead with their first solicitations. In 2015, the first storage solicitations should be complete. 

There are active discussions happening among different stakeholders on an interim target for GHG reductions by 2030. We have our 2050 goal, and the state agencies are doing various analyses to determine our 2030 targets. 


© 2017 The Planning Report | David Abel, Publisher, ABL, Inc.