Will IDSOs Come to a State Near You?

The call for Independent Distribution System Operators (IDSOs) has been going on for some time, and former FERC Chair Jon Wellinghoff and James Tong, vice president of strategy and government affairs at Clean Power Finance, have been among the most vocal proponents. As reported in an August 2014 Utility Dive article, Wellinghoff and Tong are calling for the creation of IDSOs to manage the planning and operations of the distribution network in a manner similar to the way ISOs and RTOs currently manage the transmission system. The article says such an arrangement will allow “solar and other distributed energy resources (DERs) to add more value to the bulk system and cause less stress” and will “ensure new services get delivered efficiently.” 

In my May Energy Transitions column, I wrote about the efforts underway in New York and California aimed at transforming the utility business model in those states. While there are significant differences in the approaches taken by each state, both are pursuing some form of an IDSO. 

Here’s the question: What are the opportunities and risks surrounding the implementation of IDSOs, and will they answer to the challenges being posed to the distribution grid by solar, storage, electric vehicles and other DER technologies?

DOUG HOUSEMAN

Ah, yes, the old idea of an independent operator of distribution. How very 1990s. BCG, McKinsey, Anderson Consulting and other large management consulting groups were all pushing the idea of separation of the industry into three groups for each asset:

• An asset owner – someone who could passively invest in infrastructure and collect based on the invested capital.• An asset operator – someone who would handle the day to day operation of the assets (e.g., generation, transmission, distribution, etc.)• An asset maintainer – someone who was responsible for keeping the assets running.

The problem quickly became how did you separate the operator from the maintainer and how did you conduct planning with two different entities – the owner and the operator. For transmission, this was much easier than for distribution back in the 1990s, and if anything, the tangle between operator/owner and operator/maintainer has only gotten worse for distribution.

The last estimate that I saw for an IDSO that was done off a reasonable architecture and reasonable requirements was in the neighborhood of $200 million in new capital investment, similar to what it took to stand up a small ISO. That estimate was done almost 20 years ago, and I have not seen an estimate since. So let’s look at what an IDSO needs to know to be able to operate:

They have to be able to forecast, not just for the whole system, but phase by phase, circuit by circuit. So they need a complete distribution model, with connectivity and the location of each source, and load profiles for each transformer at a minimum.

Since they are taking on the permission to site new sources, they also need to be able to do all the planning, modeling, simulation for each site and look at not only the static effects of a new source, but also the dynamic effects.

Then to balance the system, they need to have and understand all of the demand response programs and be able to trigger those programs by phase, location on the phase and circuit

They need to know when the circuits are close to overloaded, or over voltage, and be able to either curtail, change the tap changers/voltage regulators, or turn on/off demand.

When there is a storm, they have to know where the outages are, when they should be repaired and potentially what the priority is for dispatch and repair. They then also need to no do remote switching activities when there is a crew live on a location without giving the crew warning.They have to be able to estimate how much the new/upgraded services will be and then work with both the asset owner and the regulator to get approval for the upgrades. Who deals with the regulator saying no?

They will have to track carbon and emissions from various sources on the grid, and report them appropriately to state and federal agencies. The big question is are they responsible for any fines or penalties if they exceed limits, and if not who is?

They need to know which customers are in good standing and who has to be shut off, so that they can mix this into the forecasting model; not just residential customers, but commercial and industrial customers too.

They need to track in some level of near real time the largest consumers and producers and use that to correct their forecasting models and update demand.

They need to be able to buy and sell power on the whole sale market on behalf of the people who have not chosen an alternate supplier and don’t have any generation of their own.

They need to work with local officials for new housing and other developments. Providing information on what is available for local infrastructure and the costs to improve or add infrastructure locally – both for new sources and new consumption.

They need to be responsible for cyber and physical security, and for monitoring the state of security. If they are not, who is?

They need to be responsible for the state of the communications system that brings back data from the instruments in the field and sends commands to equipment in the field. If they are not, who is?

They need to design and socialize new energy-efficiency programs and demand response programs to meet the planning needs of the grid. If they are not at least responsible for design, then who do they rely on to design the programs that will allow them to operate the grid.

I have 40 more slides from the 1990s that show the needs and interfaces for an IDSO.

In short, in the 1990s, a few of us figured out that creating an asset owner at the distribution level meant that the only thing that remained with the owner was a check book. All the engineers, accountants (save the capital ones), billing, linemen and warehouses had to transfer to the asset operator, or the number of interfaces between the asset maintainer, the asset owner and the asset operator would be a bonanza for the likes of IBM and Capgemini. Adding to the problem now is that far more can and will be controllable in the future on the distribution grid, meaning that with this expanded perimeter of people and systems that there are far more avenues of attack than exist today.

So, sure, let’s pony up a few hundred million dollars per state, and build a new state-monitored group to run the distribution grid. Oh, so they are going to run the grid for the munis and coops, too, right? And do the ISO/TSO/RTOs get to the keep the transmission connected customers or do they transfer to the IDSO?

The reality in the 1990s, a far simpler time, was that IDSOs did not make economic sense and a better choice was to craft excellent regulatory rules at the state level to encourage the behavior that the state commission wanted to see. It turned out to be far cheaper to write and enforce rules than to create whole new organizations.

But, then again, I am not the one who said that “there is no such thing as baseload, it is a fictional construct” and that “we never need to build any new generation, we can do it all with demand response” (quote from a speech John Wellinghoff gave to the New York Economic Club a few years ago), so maybe I don’t know what I am talking about here. Since I believe in both new generation for the future, and I believe that baseload is a useful way to look at the grid.

MICHAEL HEYECK

In July 2014, I authored an entry to a "grid architecture" draft white paper as chairman of the Transmission Subcommittee of DOE's Electricity Advisory Committee. The excerpt I wrote relevant to the topic is below.

"Distribution will advance in visibility, control and network ability. One can imagine the emergence of grid operators at the distribution level more actively interfacing with transmission grid operators and markets. Aggregators can reach the resources at the roof-top level and have them play in the greater market enabled by a more advanced distribution grid interfacing with the breadth and scope of markets enabled by transmission. Demand response will lose its limited definition and be able to engage in more than just demand reduction (enabling more affordability to customers).

The transformation at the distribution level would be extraordinary. There are about 5 million miles of distribution in the United States and each feeder would advance in voltage regulation, visibility, automation, and networking ability. The technology is available today, but there is a need for a next generation grid operating system at the distribution level that interfaces seamlessly with the next generation EMS by transmission grid operators. Add the marketing side of the equation, and one can see the transaction velocity not unlike financial markets today."

The opportunities for the development of distribution system operators (DSOs) are plentiful, but its relevance to the grid must be reliability and customer focused. Certainly, DERs and demand response face some challenges perceived or otherwise, but the opportunities to have DERs and other demand elements play a broader role in grid reliability and markets by their large numbers can be a benefit to customers by, for example, bringing price points for each DER installation down to more affordable levels.

DSOs can help manage the technical challenges and opportunities of smart grid elements and aid the needed transformation of distribution (essentially as a starting point an extension of today's distribution dispatching function). Certainly, market development can enable smarter and broader uses of consumer level devices and other demand options.

I have not inserted the word "independent" with DSOs because I wanted to separate the geographical and operational (wires) needs from the market opportunities that require the independence and broader vision. Can aggregators (and utilities if allowed via proper separation) work virtually to interface in one or more grid market places via transmission? Aggregators may own and lease the DERs to the benefit of consumers and may not be geographically bound. Other demand options provide even more market opportunities.

In other words, let's not limit our vision on IDSO concepts or hierarchy in the grid and market sense. Certainly, the independence function is key to play in the marketplace, but one can imagine many options, including an added function to current grid operators. Perhaps this can be a useful starting point, especially given the infrastructure already in place.

Regardless of how IDSOs develop, and it may serve consumers well to have many types develop over time, the grid and market interface must be well defined and transparent, and the benefits to consumers very clear. Let's not develop IDSOs in reactive mode. Let's develop IDSOs with a vision of the grid and consumer working together in a broader sense enabled by the broad reach of transmission, grid operators, and market places.

The 21st century utility model will emerge from opportunities such as these. It is true that today's utility business model may appear to deter DER development. It is also true that DER developers may appear to see utilities as barriers given such items as interconnection standards and connection fees.

However, let us not create impediments to grid investment as we did when ISO and RTO models were in their infancy and transmission investment declined due to the uncertainty of the business model(s) that will result. Let's start with the infrastructure and marketplaces we already know (e.g, RTOs). Of course, this requires a remedy to the demand response issue of state vs federal authority (re: FERC Order 745).

MANI VADARI

Before wholesale deregulation happened in the early- to mid-1990s, all utilities worldwide were vertically integrated with full control of the entire electric chain (all the way from generation to consumption). This approach worked for several decades while the electric system in North America was undergoing its largest expansion ever. And then FERC orders 888/889 happened!

With the two FERC orders, two main actions happened:

1. Generation of the energy was considered deregulated, meaning that a utility should separate out all of its generation and trading functions into an independent entity separate from the rest of the utility,
2. Transmission was considered a monopoly and also ordered to be independent from everything else so that use of transmission needed to be procured through open and transparent mechanisms, and a system called OASIS (Open-Access Same-time Information System) was born.

When the FERC orders came in, everyone said that electric industry deregulation could not work. It  was thought that blackouts and energy shortages would ensue. Barring a few exceptions of Enron-led gaming as in the California markets, it is fair to say that electricity markets have worked well and have been successful in working through several major policy changes across the country. However, it was key to note that much of the deregulation (with the exception of Texas) happened at the wholesale (transmission) level.

So, why can’t this happen to distribution?

Transmission vs. Distribution

While much of this is quite obvious, it is still important to state it here that transmission and distribution, for the most part, are quite different. Here are some high-level points of difference and why they matter.

• Transmission, for the most part, is networked whereas distribution if radial. This means that with transmission, there are multiple ways to get power to a specific location, unlike distribution where each location only gets power from one source.
• Much of the existing generation is still very centralized  – large centralized generation that pump in energy directly into the transmission system. 

This means that the lessons learnt from wholesale deregulation cannot be applied to distribution,  right? Wrong!

So, what is changing?

With New York and California leading the way, it is very clear that the next area of change is to see more supply from the distribution side of the grid.  This was necessitated by the retirement of several large centralized generators due to EPA and other rulings.

• The newer sources of power are also from renewable sources meaning that they are intermittent in nature and generally cannot be dispatched.
• Newer mechanisms such as microgrids are coming into play, which can almost be defined as smaller grids within the existing distribution grid. These grids have the ability to be somewhat self-sufficient in energy supply-demand under some circumstances.
• The advent of AMI and better sensing mechanisms in the field is allowing distribution utilities to control demand in ways that were considered not possible before.

So, what about the Independent Distribution System Operator?

Real changes are coming to the distribution system, as well. If the state of New York has its way — and all the signs are there that it will — we will have the beginning of a distribution system (and market) operator. New York is calling it the Distribution System Platform provider, or DSP, and has set up a stakeholder-driven process to put it in motion. For starters, it is expected that the existing utilities will run this operation. This is an acceptable situation for now because the number of independent participants are still small in number and small in terms of amount of energy pumped into the grid.

However, if and when:

• The number of independent participants — people who own generation that delivers power into the grid — goes up and/or
• The number of microgrids capable of some level of independent operation goes up and/or
• Retail providers start aggregating customers and/or providers to be able to deliver significant amounts of power into the distribution grid
• Or others - then

We should at least have a conversation about making this DSP (or a different name) independent.  And this should not be just considered a New York state issue. It is fair to expect that every state will be moving in this direction at some point soon. Everyone is watching New York.