California is a proving ground for the clean energy transition. The state’s grid operators have been among the first to grapple with how to manage the growth of utility-scale solar and wind power, distributed rooftop solar, electric vehicles and battery storage.
The entity charged with keeping the lights on in much of California – and increasingly also across the western US – is the California Independent System Operator (California ISO), a non-profit public benefit corporation headquartered east of Sacramento, the state capital.
In conversation with Energy Monitor, Elliot Mainzer, California ISO’s new president and CEO, discusses how to manage the growth of renewable energy, the cause of rolling blackouts in August 2020, and the benefits of deeper grid integration across western America. Mainzer joined California ISO in September 2020 after 18 years at the Bonneville Power Administration, a federal agency created to harness and market electric power from the Bonneville Dam on the Colombia River between Oregon and Washington.
A preliminary report on the blackouts in California released in October 2020 found “a series of factors” contributed to them, including a “climate change-induced extreme heat storm across the western US” and a failure to secure adequate resources to meet power demand in the early evening hours.
California aims to make all of its electricity carbon-free by 2045. What role will California ISO play in that transition?
Our first and foremost responsibility is to ensure the transition to a clean, decarbonised grid happens reliably and efficiently. We see ourselves as a prime partner to policymakers in the state and work with utilities across the western US – we are problem-solvers trying to get the right people to work together. It is a really exciting time. Even with the challenges we have had, everybody is focused and enthusiastic to figure out how to make it all work.
What lessons did you bring with you to California ISO from the Bonneville Power Administration?
I worked at the Bonneville Power Administration for 18 years. It was a tremendous education. The footprint of the utility was so big – spanning four states – that we pretty much experienced every dimension of power system change over the last 15–20 years. One of the earliest wind power growth spurts happened on the Bonneville system in 2007–09.
I got exposed real early to a lot of issues California and the western US more broadly are grappling with at larger scale today: energy capacity, and flexibility and ancillary services, and figuring out how to migrate to a system with much greater dependence on inverter-based resources [variable renewables, for example]; the development of new scheduling protocols; intra-hour scheduling; the development of state-awareness tools; and figuring out how to deal with the periodic curtailment of renewable resources.
There is also an interesting analogue to the institutional framework here in California. Bonneville owns and operates the transmission grid and has principal responsibility for system reliability, but the dams that comprise the federal Columbia River Power System were owned and largely operated by the Army Corps of Engineers and the Bureau of Reclamation [a federal agency managing water resources]. Their operations involved a lot of non-power constraints: fish protection, navigation, irrigation or flood control. Managing all this involved a very complex and important set of relationships. It wasn’t always perfect. Tough issues would arise, but I learned the importance of sitting down and trying to work well with others.
Institutionally, California is very similar. The ISO manages the grid and has that fundamental real-time responsibility for keeping the lights on, but the California Public Utilities Commission [CPUC] establishes the rules around resource adequacy, planning and procurement. The California Energy Commission plays an important role too with load forecasting and longer-term resource planning. We have to collaborate and put our heads together to figure out how to have a truly integrated resource adequacy framework for California, all the way from load forecasting down to real-time dispatch.
Is there an inherent tension between the high penetration of renewables and grid stability?
It is not necessarily a “tension” per se. It is a challenge and it is requiring us to rethink many elements of our traditional operations. We are moving away from dispatchable resources to a much more variable fleet, a much greater dependence on Mother Nature and inverter-based resources. It is not easy, but we are moving quickly and learning a lot. The next few years will be a period of profound innovation.
The next big experiment we are going to conduct, already in the next 12 months, is to see what a significantly scaled up battery fleet can do for us. We are going to have close to 2,000MW of battery storage on the grid by next summer. We are going to get a chance to see exactly how well it can perform during that peak of the system.
We have a very different dynamic because we have so much more solar energy on our system, at utility scale and behind the meter. The original definition of ‘peak’ has changed: that typical peak, which would historically be around 5pm, has migrated further into the evening, after the sun has set. The sun sets faster than the load declines. That peak further into the evening is creating a big operational challenge for California.
This summer it will be essential the battery fleet is fully charged and ready to provide dispatchable capacity back into the system during that late evening peak. The solar energy industry and developers want to be part of that reliability solution. We are all focused on having a good outcome this year.
Behind-the-meter [anything that happens on the user’s side, rather than on the grid] resources will be an area of tremendous innovation. They are potentially a huge resource that can be optimised with the distribution system, and with the right resource packages, bid into wholesale fleet operations. Our market designers are trying to devise rules that incentivise the kind of behaviour and capacity the grid is going to need.
Do you have a definite answer on what caused the August 2020 blackouts, and what is California ISO doing to prepare for more extreme heat and increased power demand this summer?
Our final root cause analysis is getting close to go to the printer, but I don’t think it will be materially different from the preliminary report.
The CPUC has primary responsibility for resource adequacy planning and procurement in the state and has opened an emergency order instituting a rule-making to see what additional steps they can take before next summer. There is not a ton of additional capacity they are going to bring in that wasn’t already planned and built.
The big things we are going to focus on are: battery optimisation; making sure planned outages are moved out of that season to the maximum extent possible; working with other utilities, particularly in the Pacific Northwest, to ensure interconnections are in great shape for imports; and firming up contractually some imports from adjacent regions. There is interest in potentially trying to get a little bit of additional capability out of the existing natural gas fleet.
The differentiator in terms of mitigating the extent of the blackouts was a big push on the demand side. You are going to see significant mobilisation with consumers to get the system set up to be as responsive as possible.
How do you get the balance right about where to site microgrids and how much capacity should be behind and in front of the meter?
You are going to see an interesting differentiation on behind-the-meter resources.
Certain resources, by virtue of their capabilities or commercial agreements with their host utilities, or their Community Choice Aggregators, are likely to stay nested within the distribution system and provide local benefits, reliability, service and distribution system optimisation. They will probably decide that the added cost of taking additional steps to get access to the wholesale market isn’t worth it and that they are already making good money on the retail side.
Other entities, which are potentially linked into networks with sophisticated aggregators, will be able to harness enough capacity with enough time differentiation to pull it in when the grid really needs it. OhmConnect’s recent announcement of $100m of investment, to basically build a big demand response power plant, is one example of this.
We will have to make sure nodes exist between transmission and distribution systems for these aggregators to move capacity between the two. Demand response and distributed energy resources will be a big part of the solution and you are going to see us working closely with technology service providers and investor-owned utilities to figure out how we can optimise capacity.
Much of the energy storage coming online is lithium-ion batteries that are dispatching up to three or four hours at a time. Does California need longer-term storage?
You are going to see profound innovation in storage over the next 10–20 years – stuff we can’t even imagine today. You are certainly going to need longer-duration storage.
Whether you are going to have massive storm systems coming through, snow and rain and precipitation, dust or fires, there are going to be times when the natural resource is not sufficient and you are going to need to be able to ride through. There are not a lot of solutions other than being able to bank it somewhere or finding some other forms of zero-carbon power production.
I am watching the big majors getting into green hydrogen. There is a lot of focus on the electricity system, which is appropriate, but it is fascinating to see if we can come up with other fuels that can store power. If you are able to run a turbine with hydrogen made from carbon-free resources and you can figure out how to bulk that up and how to transport it, how to get it onsite, boy, that is very interesting.
Can you describe why California ISO’s Energy Imbalance Market (EIM) was needed, what it does, and the benefits it has brought to consumers and grid operators?
Back in 2014, the ISO said, ‘Hey, we have got a very efficient, well-run, real-time market here. We can extend that out to other entities and set up a Western EIM, a short-term balancing market where folks can bid in and buy out on a very short-term basis to take advantage of either more valuable sales or buy cheaper.’
The utility PacifiCorp took up the offer and proved the business case. Over recent years, a significant number of additional utilities have signed up, including public power utilities Salt River Project and Seattle City Light. If everything goes according to plan, Bonneville Power Administration will join next year.
This market has given utilities the opportunity to optimise their resources more efficiently with each other. It has created much stronger working relationships across the West and produced more than $1bn in benefits for their customers. Now there is a conversation about potentially expanding the market into the day-ahead timeframe, similar to the markets that exist in other parts of the country.
Has the success of the EIM lessened scepticism in the western US about deeper grid integration?
There is definitely significant potential. The EIM opened a new frontier of trust and partnerships with utilities across the West. If the West is going to embrace a true day-ahead market or beyond, there will need to be additional governance changes of the California ISO, and California will have to come to grips with that and be willing to go through some level of letting go.
There is work to be done inside California to make sure the business case for that broader expansion works well for utilities inside the state, and that others in the regulatory and political sphere are comfortable with the changes.
Senior correspondent, US, Justin Gerdes is an experienced energy journalist based in the San Francisco Bay Area.
Senior correspondent, US, Justin Gerdes is an experienced energy journalist based in the San Francisco Bay Area.