Last Friday, New York regulators kicked off the implementation phase of their ambitious electric market reforms, issuing an order that designated utilities as Distributed System Platform (DSP) providers. That news, along with some recent grid edge scholarship, has meant that the distribution network has been in the headlines a lot lately. Whether it’s smart grid tech, distributed generation, or microgrids, a lot of the action in the utility sector these days is happening past the substation.
With all this new technology, regulators, researchers and power companies alike are trying to find ways to create a market on the distribution grid, so that all the devices and services that exist there can be bought, sold, and their values optimized. That basic idea is the underpinning of new regulatory regimes from New York’s REV to California’s Distribution Resource Plans.
On its face, it may seem like an easy task. But setting up a market on the distribution grid isn’t as easy as devising a framework and letting prices set themselves.
The reason? We don’t know how to value all the resources on the distribution grid yet. That was the key takeaway from the grid decentralization panel at the ARPA-E conference last month. After the discussion, Utility Dive got the chance to catch up with Doug Kim, director of advanced technology at Southern California Edison. He told us the nature of the resources on the distribution system makes it more difficult to assess their values.
“When you’re looking at very small size resources like DERs and you put them in the system on the distribution grid, depending on where you put it the value of that resource is going to be different,” Kim said.
It's all about location, location
Kim offered energy storage as an example. Put a battery on a feeder with users who generate a high peak load for a short time, and storage has a huge value in lopping off the peak demand times. But on a more robust feeder, with bigger wires and transformers, the battery’s value would likely not be the same.
“The granularity of the information that you need for that grid — especially a distribution grid that is very dynamic and can be reconfigured — could be very different, very complex,” he said. “So, how do you have a value that’s assigned to a specific resource? That’s the problem that we have to think about and figure out how to do it.”
Right now, SCE has other tools to attempt to monetize the distribution system as much as possible. Feed-in tariffs and demand response programs, Kim said, are both examples of early efforts to assign values to distribution grid resources. But more and more, they’re not enough.
“Those have served us really well until now,” Kim said, “but as we start having more and more of these dynamic resources, we have to think about how do you value those things different and better, and we don’t have the answer yet.”
That answer had better come soon, as utilities are under more and more pressure to find new sources of revenue on the distribution grid. At least, that’s how Duke Energy framed it last month at the DistribuTECH conference when they announced their “coalition of the willing” microgrid project.
“We’re losing kWh to decreased demand, so there’s got to be other ways that we start to look at to make money [on the distribution system], because we are still a shareholder-owned company,” Jason Handley, director of smart grid emerging technologies and operations at Duke, told Utility Dive.
The regulator’s role
Cameron Brooks, president of the energy research firm E9 Insight, agrees with Kim’s assessment of the problem, but says we can’t lay the blame at the feet of utilities for not yet monetizing the distribution grid.
“From a regulatory point of view, this is a new challenge that regulators haven’t really been asking too many detailed questions about,” he said.
“This is making it too simplified,” Brooks continued, “but in the past regulators could sort of trust that utilities were doing the kind of planning that they needed … There weren’t all these different factors of distributed energy resources and consumer owned resources.”
In addition to the New York REV proceeding, Brooks points to California as one of the places making significant strides in monetizing the distribution grid. Early last month, the Public Utilities Commission issued an order directing each of the state’s IOUs to develop distributed resource plans (DRPs) and file them with the PUC by July 1, 2015. The regulators wrote that the DRPs should reflect three parallel goals:
- Modernize the distribution system to allow for two-way energy flows and services
- Enable customer choice of new technologies and services to reduce emissions and improve reliability
- Increase opportunities for DERs to realize benefits through the provision of grid services
Unlike New York’s REV proceeding, the CPUC’s order warns that the state is not trying to turn utilities into platforms for distributed generation, while walling them off from owning DERs. Instead, the document reads, the goal of the proceeding is to “begin the process of moving the IOUs toward a more full integration of DERs into their distribution system planning, operations, and investment.”
The order also calls for California’s distribution system operators to take an expanded role in the electric system through coordination with CAISO and “by acting as a technology neutral marketplace coordinator and situational awareness and operational information exchange facilitator.” As former FERC chair Jon Wellinghoff pointed out to Utility Dive, that recognition of the need for an independent operator on the distribution grid could lead regulators to set up independent distribution system operators in the future.
The CPUC’s Feb. 6 order includes a lengthy appendix meant to guide utilities in setting up their distribution resource plans. It calls on the IOUs to establish uniform standards for testing their distribution grids’ capacity for DERs, as well as directing them to figure out a locational cost/benefit analysis for the distribution grid — exactly the issue Kim is struggling with at SCE.
The “unified locational net benefits methodology,” the CPUC wrote, must be consistent across the state’s three IOUs and directs utilities to address the locational value issue head on. The DRPs submitted this summer must include DER value components for avoided costs on substations, distribution lines, distribution voltage, transmission capital, and large-scale renewables integration, among many other factors. This locational benefits methodology should also be able to be integrated into long term planning initiatives run by CAISO, the CPUC, or other state institutions.
Additionally, each utility will submit three 10-year DER growth scenarios that comply with California renewables mandates and map out where they expect distributed generation to grow in their service areas. That could prove to be the biggest challenge for utilities, due to the lack of reliable distribution planning models and the fact that customers, and not the power companies themselves, make many of the decisions surrounding the installment of distributed generation.
"Learning because it’s happening”
If the CPUC requirements seem like a tall order for utilities, that’s because they are. At ARPA-E, Kim lamented the fact that a reliable distribution system modeling tool doesn’t yet exist, making it more difficult for utilities to predict what will happen in the future beyond the substation. And another “cool thing to have,” he said to the entrepreneurs in the room, would be a software that allows a utility to control all the devices on a distribution grid “as a unified whole.”
But even if the solutions to monetize the grid aren’t here right now, Brooks says utilities and their regulators would have been forced to find them soon anyway because consumers and companies are making big investments on the distribution system.
The situation isn’t much different than the conversations that happened in the 1990s when some states were looking to deregulate their electricity markets, Brooks said. There were challenges then, but regulators in successful states adjusted and set up functioning markets. It’s learning by doing, he told Utility Dive, but more than that it’s “learning because it’s happening.”
“If you were to go back a few decades, people were talking about ‘What’s the value of a generating plant and how’s that going to affect the transmission network?’” he said. “It’s kind of similar concerns and challenges around how you do this kind of dynamic modeling … it’s not something that can’t be done. It’s just something we haven’t done in the past.”