Changing regulatory model could offer big benefits

By Karen Haywood Queen

Published Sept. 17, 2015/Smart Grid Today

EXCLUSIVE Revamping the current US utility regulatory model to create a network of distribution system operators (DSOs) to control the grid would open the market for solar PV, energy storage, energy efficiency programs, EVs and DR, Michael Rutkowski, managing director within Navigant’s energy practice in the firm’s Chicago office, told us recently in an exclusive interview.

“Having the grid be essentially ‘plug and play’ for all these types of distributed energy resources would enable consumers to also be ‘prosumers’ – producers of energy,” he said. “Such a system would provide equal access to the grid, essentially serving as a gatekeeper to allow those new types of services to become more available. It would offer flexibility and more choices for consumers,” Rutkowski said.

But such a change also would pose challenges for pricing, cost recovery and reliability, he added. He emphasized that both he and his consulting firm remain neutral on the issue and weigh the pros and cons on a case-by-case basis since individual utilities could try to make the case for a DSO within their own service territories.

Former FERC chairman Jon Wellinghoff, who now represents clients in a number of emerging energy fields for Stoel Rives law firm including distributed solar PV, proposed such a model, we reported in March (SGT, March-7). Wellinghoff outlined a system on the retail side where state-regulated distribution utilities would continue to own the distribution grid but would transfer operations to independent DSOs akin to the ISO/RTOs on the transmission side.

If these DSOs wanted to be involved in another energy business, they could create a separate division, Rutkowski said. Consumers could choose among different billing and pricing structures and could better control their energy costs. Discussion of such a change is in the early stages, he added, but “there has definitely been a lot of discussion and debate on the topic.”

As pricing and financing costs for solar and other distributed energy drop and prices for energy in some regions rise, more scenarios are arising where such models might make sense, Rutkowski said. “The cost trajectories of a number of these distributed energy technologies are getting to the point that within a number of years, they’re projected to be at grid parity, at which point the economic conditions would exist for customers to capture savings over their current service,” he said.

Since energy prices vary widely from state to state, some areas will have more financial incentives to make changes. For example, residential power is 30¢/KWH in Hawaii compared with 9¢/KWH in Louisiana and Washington, according to July statistics from the US Energy Information Administration. “It’s a region-by-region story in terms of making it work,” Rutkowski said. “States with relatively high retail rates such as Hawaii and California (17¢/KWH) are at or near the tipping point where new technology produces savings for customers,” he said.

“On the other hand, in some regions we already have very low cost energy being delivered to consumers. For example, Idaho has very low electric rates (10¢/KWH for residential customers), and it could take a while before the business case can be made that DER (distributed energy resources) will provide net cost savings to consumers. But there are other benefits to distributed resources such as reliability of supply at home that some consumers might be willing to pay for.”

Proper design of the pricing structure will be important in any regulatory model, he added. “The one thing you hear about the most as it deals with net energy metering for solar PV is, ‘How do we ensure that the costs of the distributed grid are being fairly and appropriately attributed to the customers that incur those costs?’ ” Rutkowski said. “The tensions lie in the possibility that one customer class could be subsidizing another customer class. If those pricing structures are not designed appropriately, ironically, low-income customers could be subsidizing higher income consumers. “It gets very complex. That’s where the devil’s in the details – in the rate design.”

Under the current market design, this issue already came up in Australia, Hawaii, Nevada (SGT, Aug-3) and elsewhere as utilities and PUCs worked on how to fairly price the energy PV customers sell back to the grid (SGT, March-6). System reliability is another concern under a DSO model, he added. “If the market transition isn’t set up right, there could be a risk where electric grid reliability is hurt. “If the utility is in a position where it is not recovering its costs, then it may not be able to make investments to maintain reliability and maintain the system. Without that backbone of reliability, you could have longer and more frequent outages.”

Grid security is another issue that should be considered and included in any plan to set up DSOs, Rutkowski said. With more participants in the market, there is more risk for security incidents, he added.

Another question for consideration is whether utilities themselves could serve as those DSOs or whether the DSOs should be independent. On the pro-utility side, “some utilities would say, ‘We know our distribution grid and we’re in the best position to manage it. We know where investments are needed and where and how third parties can access it.’ “In performing that service [as a DSO], utilities should be able to recover costs,” Rutkowski said. But if utilities served as the DSO, the independence between owning and operating the grid would be lost, he added.

“It has to be a well-planned and well-orchestrated transition. Utilities need to be integrally involved in the process.”