GTM's second-annual Grid Edge Live conference drew more than 500 attendees to Rancho Bernardo, Calif. to talk about a pressing issue facing the world’s utility and energy industries: how to manage the emergence of a distributed, low-carbon, customer-enabled energy future.

This challenge looks different, depending on which side of the meter you’re standing on. In terms of the grid edge, that’s the divide separating the 60-plus utilities in attendance at this year’s conference and the companies building the energy equipment and grid gear, writing the software and developing the algorithms, and creating the networks and business models for enabling this future.

Much of this new energy infrastructure is being built behind the meter, from the edges up, as we heard from representatives of companies with customer-centric energy offerings like SolarCity, Stem, Nest, Lowe's and Time Warner Cable. But utilities are still responsible for making sure these edge-of-network systems fit into existing infrastructure and economic models -- or finding ways to change them if they don’t.

Here’s an overview of what we heard and learned, and where we’re keeping an eye out for the next developments on the grid edge frontier.

Grid-edge technology from the microgrid on up

Microgrids are an important way to manage the technical integration challenges implicit in the emergence of the grid edge, which is why Greentech Media dedicated a pre-conference session day to the subject. According to GTM Research analyst Omar Saadeh, U.S. microgrid capacity is set to grow from 1,283 megawatts in 2015 to 2,855 megawatts by 2020, achieving a market value of more than $3.5 billion.

Byron Washom, strategic energy initiatives director for UC San Diego, has led the development of the university’s cutting-edge microgrid, and hosted a tour of its facilities prior to Tuesday’s session. To date, UCSD has found the primary value of its microgrid in the ability to keep the campus running during blackouts or grid emergencies, he said -- the same priority that’s driven microgrid development at military bases and critical industrial and commercial facilities.

“If this industry is going to advance at the speed of the market pull, then...standards have to emerge,” he said during a Tuesday panel session. That's why UCSD is working with standards groups like the SunSpec Alliance and Underwriters Laboratories, and getting funds from ARPA-E to test advanced energy storage systems.

The distribution management systems software platforms used by utilities to operate their low-voltage grids are built on grid models that use data that isn’t standardized from one utility to the next, Oliver Pacific, chief technology and strategy officer for Spirae, said in a Wednesday panel session. “That’s something we don’t talk enough about: data being stranded at the model level,” he said. “The utilities should push the industry on that. […] It’s a huge engineering lift to bring all that data together and build a good dynamic model. There are national labs that are helping utilities get this done.”

Cutting-edge renewable integration and the IOT

Last week saw the launch of a few of these cutting-edge integration projects, as David Danielson, the Department of Energy’s assistant secretary for energy efficiency and renewable energy, noted in a Thursday presentation.

The first features U.K. startup Smarter Grid Solutions’ software to monitor and control renewable power generators, customer-sited energy storage and demand response assets, and grid equipment -- a class of technology known as distributed energy resource management software.

The second featured Siemens and Accenture joint venture Omnetric Group’s test of an open field message bus, or OpenFMB -- a technology to allow in-field energy assets to interact to solve grid-edge problems that central utility control systems may not be able to handle. It’s one of the emerging standards for different companies’ devices to use to make grid-edge integration simpler, cheaper and more effective.

As technology standards start to come into play, utilities and the companies building grid-edge systems will have a chance to figure out how to share the data each is collecting with the other. That could enable something like an “internet of things” for the energy sector to emerge.

Of course, that’s not going to look quite like the mainstream conception of the internet of things for the consumer, Geoff Sharples, energy and industrial IOT strategy director for Intel, said in a Wednesday panel session. When it comes to critical grid systems, “the internet of things really right now is not appropriate for real-time controls,” he said.

“As folks get to work with the data, they’ll need to figure out just how they’re going to manage it, and what they’re going to optimize for. It’s a matter of figuring out what the technology can do," said Sharples.

Searching for the right rate reform

Distributed solar power will continue to get cheaper and cheaper, even if policies supporting it are eroded over time. Distributed battery-based energy storage, though still far behind solar PV on the cost curve, is expected to become cost-competitive in many markets by the end of this decade.

All of this change is happening at a pace that far exceeds the timescales for traditional utility investment and planning. That puts lot of pressure on them to find new regulatory structures and business models to become a part of this transformation, rather than be left behind by it. As Elisabeth Brinton, vice president of corporate strategy at Pacific Gas & Electric, said in a Wednesday panel, “business-as-usual cannot continue, so it’s about recognizing that disruption is actually an opportunity.”

But for every example of utilities applying forward thinking to the grid edge, there exist counterexamples of utility resistance, noted Steve McBee, president and CEO of NRG Energy’s newly formed NRG Home business unit, during Wednesday’s panel.

His company’s solar installation business still struggles to get new customer PV systems approved and interconnected in a timely fashion, he said, and “one of the reasons is that there’s a lot of foot-dragging from a lot of utilities to make that happen, and it hamstrings the growth of the industry.”

Of course, utilities have their reasons to be leery of unchecked solar growth, at least under existing net-metering rules that erode their energy sales revenues. Barbara Lockwood, general manager of regulatory affairs and compliance at Arizona Public Service, noted in a Thursday session that her utility is seeking state regulator permission for charging solar-equipped customers up to $21 per month in fixed charges. That move has drawn intense opposition from solar industry players, although Lockwood said “solar prices have come down to the extent that it’s still affordable and economical.”

On the other hand, APS also offers alternative demand charge-based tariffs that allow homeowners to avoid those charges. APS has also launched a 200-home pilot project testing solar, energy storage and home energy management systems in what Lockwood described as a "rate laboratory.”

Shayle Kann, senior vice president of GTM Research, asked a Wednesday panel whether “smart, unbundled rates” could help balance the economics for solar PV, energy storage, plug-in electric vehicles and other grid-edge systems between utilities and their customers. Early examples of this exist, like APS’ demand-charges-for-residential rates, or the EV-charging rate being proposed by San Diego Gas & Electric.

Of course, new residential rates are tricky to create and involve a drawn-out political process at the state regulator level, noted Raiford Smith, vice president of corporate development and planning for San Antonio, Texas utility CPS Energy. Even a municipal utility like CPS, which can ask its city council to approve changes, may have trouble putting more complex rate structures into effect. Eventually, utilities might try to push for a simpler set of rates, like the flat-rates-plus-extras that telcos have created for cellphone users, he said.

Bidding distributed energy resources into wholesale markets

Other avenues exist outside of comprehensive rate reform to align utility and distributed energy incentives. One alternative is to allow distributed energy resources to play into wholesale grid markets, as California is set to start allowing next year, and which New York and Texas are also mulling.

“These assets are already there -- it’s not a question of how much you have to pay for it,” Ameet Konkar, senior strategic initiatives director for Enphase Energy, said of this concept. “The question is how you can into that marginal value, which may become more competitive compared to what a generator can provide.”

The challenge here is to create an as-yet-untested structure for monitoring, metering and paying a collection of aggregated energy assets for their contributions to the grid. “I’m not sure we’re going to agree that they can switch every hour, and we can keep track of that, and be sure we get what we paid for,” Joel L. Mickey, director of market design and development for the Electric Reliability Council of Texas, Texas’ grid operator, said of these kinds of innovations.

DERs as an integral part of utility costs and benefits

Somewhere between the concept of distributed energy resources (DERs) as grid market players and smart, unbundled rate structures lies another idea: creating utility grid-planning regimes that consider DERs as an integral part of their future costs and benefits. That’s the route that New York’s Reforming the Energy Vision process is contemplating, as is a regulatory proceeding now underway in solar-strained Hawaii.

California is also on the forefront of this change. This week, the state’s big three investor-owned utilities are set to release distribution resource plans (DRPs) that make a place for DERs in their ongoing, multi-billion-dollar distribution grid investment plans.

This is a multi-step process, starting with assigning various grid values that DERs could provide, then creating rules for how utilities and DER providers will share data to identify specific values to specific portions of the grid. Eventually, the DRP process is meant to create a structure to actually compensate them for those values.

Just how that’s going to happen -- and how far this week’s DRPs will go in this process -- isn’t clear yet. “There are a lot of new folks out there entering the space who will have a lot to offer,” Russell Ragsdale, grid modernization manager for Southern California Edison, said in a Wednesday session. “The DRP is a great first step for outlining that framework of where we want to get to.”

But the need to calculate DER value in lieu of traditional utility capital spending isn’t limited to solar vanguards like California. “In the future, we’re going to see a shift. […] Instead of installing the bigger transformer or the bigger wire, I may be installing a solar system or a battery system,” Jason Handley, director of smart grid technology and operations at Duke Energy, said in a Wednesday presentation.

“We’re not sure when the adoption curve is going to take off,” he said, but one thing’s for sure: Duke Energy isn’t willing to wait for it to happen, lest the utility face the same kind of distributed energy-driven economic disruptions that have befallen Germany’s big utilities or Hawaii’s big investor-owned utility HEI.

“We’re going to build headroom into our systems, today and into the future,” he said. “If we get behind, we’ve seen examples of that in other countries and in Hawaii, and it’s harder and harder to catch up.”