Is California Mapping the Grid of the Future with its DRPs?

Aug. 7, 2015
California’s largest utilities recently filed their Distribution Resource Plans with state regulators, laying out grid modernization efforts designed to enable the deployment of ever-increasing amounts of solar and other distributed energy resources. What needs to happen for this process to be successful? T&D World IdeaXchange Xperts voice their opinions.


First New York utilities responded to their state commission with their plans on Reforming the Energy Vision.  Now California utilities have filed their Distribution Resource Plans (DRPs) with the California Public Utilities Commission (CPUC). Meant to enable ever-increasing amounts of distributed energy resources (DERs) and serve as a roadmap for grid modernization, the DRPs were in response to a CPUC rulemaking initiative that stated, “Distribution planning should start with a comprehensive, scenario-driven, multi-stakeholder planning process that standardizes data and methodologies to address locational benefits and costs of distributed resources.”

In the previously mention T&D World link, Southern California Edison President Pedro Pizarro commented, “The DRP is our game plan to build a state-of-the-art power network that is essential to assure reliability, power quality and customer choice of new technologies and to further reduce greenhouse gases.” 

I believe that truly significant change starts with big audacious goals, but here is the question: With such transformational goals in mind, what will need to happen for the California DRP process to produce the results envisioned?


We have had a number of articles on the subject in TDW's IdeaXchange dealing with the future of distribution operations, distributed energy resources (DERs) penetration and economics (with the 1978 PURPA parallels), and the impact on current utility business models to list a few. Many suggested watching New York and California, particularly because of the recent visioning by their utility commissions and energy industry leaders, and their increasing DER penetrations due to policy and rate drivers.

Well, here we are with California's DRP. Will the DRP be successful and meet goals? I would bet on it based on California's policy drivers and rate economics. But I want to narrow my comments to the "law of unintended consequences," assuming my colleagues will add other color to the subject. DRP proposals are fraught with the use of the economic lingo, "avoided costs." We have already debated the avoided energy costs and net-metering issues before and I mentioned prior the parallels with PURPA (1978). What I want to focus on is specific to distribution infrastructure.

A 1957 Chevy in mint condition is hard to beat. How about a 1970s vintage Corvette? Some (few) even like 1960s vintage Corvairs. Like Pavlov's dogs, salivating is the response from car buffs when they go to historic car shows, me included when thinking about my 1969 Pontiac Grand Prix with the Q-Jet carburetor that required direct injection from a fuel truck. Yes, it had an 8-track tape system, too. Enough salivating. Now envision our digital age with this analog nostalgia.

Our distribution system in the U.S. is perhaps tops on the grid-aging list, with mainly run-to-failure components still in operation that deserve placement in the Smithsonian. The system needs to be upgraded to the digital age with full visibility not unlike the transmission visibility by grid and market operators. Avoiding or delaying the replacement of this aging infrastructure because of lower demands on the system with DERs will yield an 8-track logic plug-in to a smartphone world.

I am happy to say that the electric utility industry has increased its capital spending to replace the aging grid. Is this enough? According to Edison Electric Institute (EEI), T&D spends annually are nearly $40 billion with about $20 billion dedicated to transmission. EEI goes on to project needs by 2030 of $900 billion total, placing the annual number near $60 billion on average. Most of this increase I assume will be dedicated to aging distribution needs. I "guesstimate" that there are over 5 million miles of overhead distribution in the U.S., with most of these assets having been around a long time. Adding to the replacement burden are aged substations and extremely aged urban underground networks.

It is a daunting task to modernize and transform distribution to enable the grid of the future for U.S. consumers. Let's make sure that "avoided" infrastructure costs are "true" costs that do not delay this modernization. Let's make sure that modernization is not simply a one-for-one replacement process. We do not need 8-tracks any more. We need to build in 21st century automation and account for DERs and other consumer choices. And let's make sure we add visibility for distribution system operations that may transform to distribution level market operations. I think you get the picture.

Yeah, some say older transformers are better than newer ones, but older transformers will fail. My 69 Grand Prix is long gone, but for some reason, I recently found that I kept the 8-track tapes. Go figure.


The "next generation" distribution system envisioned by the CPUC and the New York PSC will require a "next generation" distribution engineer.  In order to plan and design around the legacy system while maintaining a safe, reliable and affordable flow of electricity to customers, our "next generation" distribution engineer will need to understand the following:

  • Basic power flow
  • Telecommunications 
  • Protection & control
  • Renewable and DG integration
  • Demand Side Management/DR
  • Storage (utility and private)
  • Advanced technologies
  • Customer service principles 

Just as the Home Area Network engineer did not exist prior to the DOE grants for the smart grid, this "next generation" distribution engineer does not exist today. To deliver the transformational vision of California and New York, we need to cross train a whole new generation of young men and women to plan and design our "next generation" distribution system. And, we need to start now. 


I’ve always said that a utility, or actually every company, should prepare a holistic strategic plan before spending any money on technology and deploying this technology in the field. Breaking down the internal silos and working holistically as one company team is critical to realizing the maximum benefits for every dollar spent. Having a strategic plan minimizes the risk of stranded assets, because there is a follow on step, per the plan, at the completion of every project. The CPUC required by law for the three IOUs in California to prepare holistic smart grid strategic plans and submit them in 2011. Every PUC should have done the same thing with the IOUs in their jurisdiction. Additionally, every municipal and cooperative utility should have a holistic automation strategic plan. I coauthored a book titled "Automating a Distribution Cooperative, from A to Z" for the NRECA CRN that was published in 1999, and included a chapter on how a cooperative utility prepares a holistic automation plan.

Now, the CPUC required the California utilities to prepare a Distribution Resource Plan (DRP). For the California DRP process to produce the results envisioned, the plan first has to be holistic, bringing together each and every group within the utility to work together. I’ve been in workshops with IOUs where the renewables group rarely talks internally with the smart grid or grid infrastructure group. Don’t the renewables need to be integrated into the grid? Shouldn’t these groups be working closely together? You would think so but in many cases they are not. The process of preparing a holistic plan helps to bring together the different groups in an organization to think as one and work as one team.

The distribution system of the future will be very different from today and operate in a way that is different from the way it was designed. With the integration of renewables, the distribution system will have two-way power flow, varying fault currents due to DG, protection settings not matched to fault currents, stress on voltage regulation equipment, safety issues (opening the upstream device doesn’t guarantee a dead line), and possible congestion. The impact of high penetration of rooftop solar, for example, on the distribution system results in new applications of power electronics, such as power electronics-based load tap changers, low-voltage network dynamic grid edge controllers, and “smarter” inverters with increased functionality and external control capability.

Policy makers should not be able to set policy until an operational analysis is done to determine the changes in the grid or infrastructure needed to support the policy changes. For example, what changes are needed to the grid to support an IOU reaching 33% of their generation to be from renewables? Are the required grid changes even possible? Who will pay for it?

It is important to note that variable generation (renewables) cannot replace base load generation. As more and more renewables are added to the grid, what is being done to address their intermittency and at what cost?

The advent of smart grid emphasized for all of us to think of the big picture and not be “stuck” at the device or system level. We are transitioning from devices and systems to integrated holistic solutions. A solution is a set of technology components, not necessarily from the same vendor, that are integrated with each other so they interoperate successfully. The integrated holistic solution provides the maximum benefits for each investment to the utility, because for each investment the possible benefits to every group in the utility are considered. For example, when the smart metering group buys the AMI communications infrastructure, consider the needs of the distribution automation group. One communications infrastructure, properly specified and planned, can support the needs of smart metering and DA together.

At a recent ADMS (Advanced Distribution Management System) workshop at DOE NREL, the consensus of the industry experts was that 70% of the costs of an ADMS are integration costs. The technology components themselves (smart meters, AMI communications, DMS, OMS, GIS) provide value, but the far greater value proposition is when these components are properly integrated with each other. In fact, the measure of a utility’s grid resiliency is the technology components they have invested in (especially the functionality of each component) and more importantly how well these components are integrated with each other.


To make the DRP work, all of the stakeholders have to be willingly engaged. There will have to be give and take from every one of them.

For the solar leasing companies, they will have to figure out how to help balance the distribution of capacity across the phases of each circuit. That may mean that they have to lower their standards for customer credit scores and change their standard agreements to not be a second mortgage on homes. This will allow customers from  broader customer demographics to install solar but will have major impacts on their business models. However, if they want to continue to install more solar, they have to be willing to help balance the placement of solar, so that the phase imbalance does not become a huge issue.

The regulators have to think about what capital spending is required and support the spending. In many cases, the existing voltage step downs and reduction in size of conductors on circuits mean that at the end of many laterals, the carrying capacity for distributed generation is much less than it is near the substation, but in many cases, the space to install photovoltaic and small wind is much larger as you move from dense urban areas to rural areas. This is one example of changes the regulator needs to think about and probably support. Getting the hosting capacity up all the way to the end of the circuit is important if you want to maximize distributed generation. The regulators need to think about how they would develop a program that would put, say, 1 kW of solar on each and every roof that houses a residence, for multi-dwellings 1 kW per residence to the limits of reasonable space available for installation. The regulators have to think about how subsidies from one class of customer are now flowing to other customers, and work to remove these subsidies in a prudent fashion, so that inequity does not grow to be a barrier to using the grid.

Inverter manufacturers need to embrace California’s Rule 21 for advanced inverters and interconnects and help drive the development and certification of these inverters. They need to work with labs like UL to get certification testing developed and to push to initial UL testing for safety, there are other tests that need to happen to make sure the devices interoperate with other manufacturers and the installed communications systems.

Environmental groups need to recognize that solar does not generate at night, and that the storage requirements, if solar is going to be California’s primary generation, will be massive. Batteries alone will not solve the problem in an economically prudent fashion, so they need to think about other forms of storage and determine locations and types they are willing to support. If carbon reduction is the primary goal, then they have to bend on some of their other wishes. CA-OSHA also has to give on some of their rules for safety and create pragmatic rules for storage for operations and maintenance.

Consumers have to be willing to ACTIVELY engaged in demand response programs, whether it is picking an installer/aggregator to handle the programs for them, or installing their own devices and managing them, or just manually taking actions day in and day out in a consistent fashion, or choosing to allow the utility to handle the program for them.

Building owners have to think carefully about how they make their facility more energy efficient. The DRP expects to provide power to everyone for everything, but the cold reality is there will be days when the power may not be there. The cheapest kilowatt-hour is the one you don’t have to make, and energy efficiency needs to be a clear priority. Commercial building standards for retail are a good place to start, there are low-cost methods to reduce energy losses through the building envelope, and those need to be driven into building codes, and owner’s minds.

Banking institutions have to take a step back and think about how to value energy upgrades, doing a better job of rating the improvements and pricing loans and mortgages.

Real estate brokers and contractors need to include energy features in listings and make them important selling features. It may be that buildings that don’t meet minimum standards cannot be sold.

There are other stakeholders whose role we could discuss, but I won’t here. Instead I will focus on the stakeholder that most people want to assume is the only actor – the utility.

The utility has to become an integrator, making hosting capacity for storage, generation and demand response available on the existing grid. They have to completely rethink the topology of the grid, improving the paths that exist for two-way power flow. They have to instrument what has been a mute grid, with communicating sensors. They have to operate the grid 24/7, making the best economic decisions not just for customers who own assets that provide services to the grid, but for all connected customers. They need to teach installers, bankers, architecture, builders and others how the grid really works, and what is good for the grid (and in many cases, these stakeholders) and what is not. They need to realize that this is a huge undertaking and will impact the way the company operates, is organized and is funded a non-trivial change to their business.

From what I see from the three largest utilities in California, they are working to meet their stakeholder responsibilities, the question in my mind is can the other stakeholders step up and work with each other to meet their responsibilities? 

About the Author

John H. Baker Jr. | Energy Editor, Transmission & Distribution World

John Baker is a proven utility executive, strategist, engineer and executive consultant. He is the energy editor for Transmission & Distribution World, writing a monthly column entitled “Energy Transitions.” He is also president of Inception Energy Strategies, an executive consultancy serving the utility industry. He has particular expertise in strategic business models, new energy technologies, customer strategies and smart grid. He has given numerous domestic and international presentations on smart grid and other utility of the future topics.

Prior to starting his consulting practice, John served from February to November 2011 as the director of Utility Systems Research at the Pecan Street Project, a research and development organization focused on emerging energy technologies, new utility business models, and customer behavior associated with advanced energy management systems. In that role, he led the development of both a smart grid home research laboratory and a utility-side smart grid research project.

John was the chief strategy officer at Austin Energy from October 2002 to February 2011, creating the organization’s strategic planning function in 2002; helping set its sustainable energy direction; establishing key collaboration agreements with the University of Texas’s Clean Energy Incubator; leading a cross-functional effort that examined solar technologies and related financial structures, resulting in the development of a 30-MW solar plant; and leading the utility’s participation in the development of the Pecan Street Project.

Over the course of his 35-plus-year utility career, he also served as vice president of customer care and marketing, director of system operations and reliability, division manager of distribution system support and manager of distribution engineering.

John earned his BSEE degree from the University of Texas at Austin and his MBA from the University of Dallas.

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