The power of distributed energy resources to transform customers’ lives depends on the readiness of the grid, but making the grid ready will be pricey, according to one utility's new vision for tomorrow's distribution system.

With a modern grid in place, Southern California Edison (SCE) will be capable of delivering a full spectrum of distributed energy resources (DERs) to customers within a decade, according to a new white paper from the utility.

In one version of the future utility-customer relationship that such a grid would make possible, customers might have a fixed monthly bill and long-term contract not unlike a cell phone service and the utility would provide, in addition to electricity, a suite of distributed resources, Julia Hamm, president of the Smart Electric Power Alliance (SEPA) said at a recent conference.

In that future, more energy-smart consumers could choose to shop for private sector vendors to provide the solar, storage, and smart technologies — and they would be able to, Hamm said, because any vision of the electricity sector’s future should include choice.

“We want this future,” Southern California Edison (SCE) President Ron Nichols said of Hamm’s description at the Solar Power International Conference. “We need to have a grid that can make that work.”

But getting to that new grid is no mean task, he added, because utility systems are complex.

SCE made over 22,000 changes to its distribution system in 2015 and the emerging DER future, which will include the addition of 1.5 million DER by 2025, will accelerate that work, Nichols said.

SCE’s modernized grid, detailed in the white paper “The Emerging Clean Energy Economy,” will ready the utility to be its territory’s Distribution System Operator (DSO).

As DSO, SCE will deliver the new technologies coming from private sector DER providers in support of the California’s ambitious climate goals, according to the utility’s new General Rate Case (GRC) for 2018 to 2020, filed alongside the white paper.

If approved by the California Public Utilities Commission (CPUC), the GRC would bring SCE’s capital expenditure for 2016 through 2020 to $2.3 billion.

With so much money at stake, the CPUC must be certain the investment will be worth rate increases to SCE customers of 2.7% in 2018, 4.2% in 2019, and 5.2% in 2020, said Spokesperson Mindy Spatt of The Utility Reform Network (TURN), the state’s influential ratepayer advocate. How regulators evaluate and rule on the proposal could set the stage for future grid modernization proposals in California and beyond.

SCE's distributed resource vision

Consumer advocates and the private sector have long complained of utilities’ "lack of transparency" but in this rate case SCE is not “leaving its logic in a black box,” Hamm said.

By releasing its white paper so close to its GRC filing, “it is laying the groundwork for more constructive conversations with stakeholders about its proposals.”

The SCE white paper follows Xcel Energy’s “Our Energy Future,” a 2015 position paper that utility executives credit as the foundation for a recent solar settlement in Colorado.

“Like Xcel,” Hamm said, “SCE is describing its vision and why it wants what it is asking for. I would love to see more utilities willing to do that. It is not an easy process.”

The goals of this white paper and of the GRC are perfectly aligned, said Caroline Choi, SCE vice president for regulatory affairs. They also align with the climate and clean energy goals of California legislators, policymakers, stakeholders, and the public.

The investments in the SCE distribution grid will enable technologies that give the utility visibility of the DERs on its system, she said. It can then use them to optimize grid operations.

Like the GRC, the white paper identifies the need for expenditures where there will be load growth and where markets can be enabled by using DERs to supply grid services.

“Initially we see the biggest potential for DERs where we see load growth because we know we will have to make investments to meet that anticipated load,” Choi said. “Is there, instead, an opportunity for DERs to help us?”

Solar-plus-storage is likely to proliferate sooner than other DERs because customers want it and private sector vendors are already offering it, Choi said.

Because the utility’s plan is intended to protect and support the growth of the private sector, DERs supplied by third party providers to meet customer demand are likely to be the first DER the utility will be able to use to meet load growth, she added. Those DERs can be cost-competitive with intended utility solutions if they are located properly on the distribution system, she said.

When third parties cannot or do not deliver cost-effective DER solutions, SCE may soon have another option. A bill passed at the end of last month mandates the state’s three IOUs develop and own 500 MW of behind-the-meter storage, so long as it does not “unreasonably limit or impair the ability of non-utility enterprises to market and deploy energy storage systems." Regulators will ultimately make those determinations if the bill is signed by Gov. Jerry Brown (D).

An upgraded grid will also allow the utility to drive DER market growth by using new circuit-level visibility of the system coming from the utility’s distribution resource planning, according to the white paper.

“We can see where there will be opportunities and go out with Requests for Offers (RFOs) to see what DER or portfolio of DER could avoid or defer a utility capital expenditure at that location,” Choi said.

Beyond solar PV and storage, DER portfolios could include demand side management, energy efficiency, demand response, and, eventually electric vehicles “which would be mobile storage,” Choi said.

If a DER solution that is bid in response to an SCE RFO meets the system need and costs less than the utility solution, “we would choose the DER solution to avoid the utility capital expenditure and that capital could be used somewhere else,” she added.

PRP leads the way

SCE’s recent second round RFO for its Preferred Resources Pilot (PRP) got “a robust market response” and led to contracts for 125 MW of DER expected to be online in 2019 and 2020.

“The multiyear PRP study is designed to determine whether these preferred resources — including solar, wind, battery storage, energy efficiency and energy conservation — can be used to offset the increasing demand for electricity,” according to the utility.

For the new round of the PRP, SCE will get 35 MW of battery storage from Convergent, 15 MW from Hecate, 10 MW from NextEra, and 10 MW of solar-plus-storage from NRG. It will also get 40 MW of demand response from energy conservation and battery storage from AMS, 5 MW more from Swell, and 10 MW from NextEra.

As the pilot project gives way to more typical utility resource procurement, “you need the right rate structures,” Choi said. “The prices we pay should reflect the locational and time value these resources provide to the distribution grid and the flat tiers we have today don’t do that.”

A simple transparent mechanism could “identify the wholesale, distribution, and societal value of energy injected into a specific part of the grid,” according to the white paper. “The DSO could update these mechanisms on a regular basis to reflect the economic fundamentals of the system and the experience of competitive markets, so that compensation reflects local system needs and market values.”

There would need to be “a gradual transition” from today’s retail rate net energy metering to “location- and market-based pricing,” according to the white paper. The new structure would support California’s environmental policies, protect customer access to DER, and “maintain equitable cost allocation among all customers.”

All customers will benefit when DER compensation “aligns with actual benefits and costs to the grid” because today’s largely volumetric rates do not reflect the utility’s fixed costs, the white paper adds.

Getting the rate structure to reflect those costs does not have to be done with fixed charges, Choi stressed.

“Customer rates must evolve so that all customers of the grid make an equitable contribution to maintaining it, while not disadvantaging existing customers who presently rely on DERs,” the white paper explains.

SCE is making plans to successfully implement CPUC-mandated flattened rate tiers in 2017 and time of use (TOU) rates in 2019, Choi said. Both are movements toward rates SCE endorses.

TOU rates can give customers incentives to use electricity in "the right way,” Choi said. “We just filed our first TOU periods shift in 30 years. Summer peak is now weekdays from 4 p.m. to 9 p.m. instead of from noon to 6 p.m. because of the increase of solar generation in the middle of the day.”

The SCE white paper is a good example of a plausible overall vision, SEPA’s Hamm said.

“It may not be the right vision for every utility but I applaud them for making their vision public," she said. "It is a starting point for a constructive conversation with stakeholders that can lead to a common vision and then the steps needed to get to the vision.”

What the billions would buy

If solar and DER advocates are excited about SCE's plan, consumer watchdogs are less so.

“We are really concerned,” TURN Spokesperson Mindy Spatt told Utility Dive. "This is an unprecedented increase in rates at a time when we know many people can hardly afford housing. When you add up the three years’ costs it looks horrific.”

TURN does not want the utility to compromise on safety or reliability, she added. “But we know Edison is capable of making proposals that cost consumers more than it gets them,” Spatt said. “Just because something is shiny, new, and modern doesn’t make it cost-effective.”

In SCE’s GRC filing, the utility is "trying to balance two broad objectives," said GRC Director Shinjini Menon. "The first is the maintenance of the system and the replacement of out-of-date equipment. The second is to get our grid ready for the new reality of distributed energy resources.”

Even if DER were not a factor, the utility would still require funding to maintain and upgrade aging infrastructure built as long ago as the 1950s, Menon said. But the spending will allow SCE to handle the coming increase in DER interconnection requests without compromising safety and reliability.

The GRC proposes a revenue requirement for 2018 of $5.885 billion and includes a $222 million increase over present base rates as well as increases of $533 million in 2019 and $570 million in 2020. It would bring total 2016 to 2020 distribution system investment in assets to $17.8 billion.

The investment will accelerate programs already in place for “traditional transmission and distribution and information technology” and to build a “next generation electric grid,” according to supporting materials for SCE’s GRC filing.  

The grid modernization that would cost $2.1 billion in 2018 would build in four new capabilities, Menon added. It will require: upgrading, automation for real-time monitoring and control, new telecommunications capabilities with fiber-optic cable and wi-fi, and new software for grid management by system operators.

The new grid would also enhance reliability by addressing technology obsolescence, such as the inadequate 4 kV circuits that make up 22% of SCE’s 4,600-circuit distribution system, the filing reports.

The upgraded grid will also be capable of automated monitoring and control of grid equipment in real-time and of delivering the information to system operators in real-time through expanded fiber optic and field area networks, SCE promises.

Finally, the utility wants to add technology platforms to do distribution system forecasting, planning, and management. These capabilities will make the system ready to integrate DER where customer demand is high and where DER can provide grid services that could avoid or defer bigger capital expenditures.

Automated, two-way grid the goal

SCE’s 1990s distribution automation is based on circuits that have limited visibility, according to the GRC filing. Today’s automation technologies are allowing utilities to move toward “faster self-healing distribution systems” that are “rapidly locating faults and reconfiguring the system.”

Most substations on today’s system can only channel one-way power flow from the utility to the customers but the CPUC’s landmark Distribution Resource Planning (DRP) order requires the state’s investor-owned utilities “to modernize the distribution system to accommodate two-way flows of power,” the GRC points out.

“The grid was built for central generation with a specific design and it was built to respond to a late afternoon load peak,” Menon said. “Now, in addition to centralized generation, generation can come from anywhere along a circuit.”

To accommodate the two-way flows and keep the system reliable for non-DER-owning customers, it must be modernized, she said.

The process “is not a simple matter of deploying one or two technologies because DERs impact multiple planning and operations functions,” SCE's filing reports.

SCE’s modernized grid will “dynamically optimize grid operations and resources, rapidly detect and mitigate disturbances, integrate diverse generation sources (on both the supply and demand sides), integrate demand response and energy-efficiency resources, enable consumers to manage their electricity use and participate in markets, and provide strong protection against physical and cyber risks,” it adds.

One of the first steps, already ongoing, is the replacement of the “obsolete” 4 kV circuits over the next two to three decades, Menon said.

“They are more susceptible to outages and, because they do not match other circuit voltages, it is difficult to transfer load, so the outages last longer,” she added. The GRC funding will continue a “steady-state replacement” of the 4 kV circuits over the next ten to twenty years.

SCE engineers have identified two types of circuits that should be upgraded, Menon said. One is those that are performing poorly. The other is those where high DER penetration is anticipated​ and where DER can act as non-wire alternatives and defer expenditures on capacity projects like transformers or even substations needed to provide grid services.

A pilot will evaluate the potential deferral of eight load growth projects through the use of DER and a modernized distribution system that would otherwise cost ratepayers $40 million, the filing reports.

The utility would not choose between DER technologies but would require the DER to demonstrate three characteristics, the filing adds. One is availability, or being accessible when required by the grid. The second is dependability, or being able to do what is promised. The last is durability, or having a clearly defined asset life.

“It is implicit in the filings that we are going to be working with DERs provided by people who are not us,” Menon added. “This system work is to be ready so that when companies like ones we have contracted with through our earlier DER projects begin building more DER we can galvanize that economic activity.”

Each DER in the proposed pilot would be evaluated for its cost-effectiveness at responding to load growth “across a range of characteristics including climate zone, customer, and geographic diversity,” the filing reports. A specific target of the pilots would be the evaluation of DER impacts on transformer life, it adds.

“Our request is a balance of both drivers,” Menon said. One investment tranche will upgrade the utility’s worst performing circuits to the same standards as the high DER penetration circuits.

A second tranche of spending will target DER integration identified by the utility’s engineers where either penetration will be high and circuits are at their loading limits or where non-wires alternatives would defer or avoid capital investments in transformers or substations, she added.

SCE wants to invest in both ways, meet the needs of the grid, maintain safety and reliability, and manage the rate impact of doing those things, Menon said. “A lot of the rate case is about balancing all those things.”

SCE filed its general rate request on Sept. 1 in docket number A.16-09-001. It proposes that a public workshop be held on October 15, with public testimony to be held from April through August 2017, and a final decision in January 2018.