Partnering for success: Utilities leverage innovative vendor relationships at the grid edge

A new study reports on opportunities utilities could seize to expand distribution system technologies

A new high-level look at distribution system innovation makes one thing clear: Utilities that find and work with innovative private sector players benefit from reaching out.

The paper builds on earlier reports about technologies changing the distribution system, including energy storage, demand response, data analytics, advanced metering and solar-plus-storage. From a burgeoning database, the researchers highlight nine cutting edge projects that reveal an enormous range of distribution system innovation possible for utilities to access through private sector partners.

“We initially named the series the Grid Edge 100, but we now have thousands of vendors in the database,” said lead author and GTM Research Grid Edge Analyst Andrew Mulherkar. “We picked 120 vendors the team believes are especially well-positioned in the market, but you can’t distill the list of vendors to a manageable number anymore. It is a very large ecosystem.”

The new report is “a lens on activity across the industry, from AMI in Texas to communications in South Carolina, to microgrids in California,” Mulherkar said.

Variety seems the only continuous theme in the third Grid Edge 100 installment covering eight “sub-markets” serving the distribution system. But the increased diversity and number of vendors has only expanded opportunities for utilities to form partnerships to benefit their systems, their customers, and their own bottom lines. 


Benefits of AMI

One of the more mature technologies profiled is advanced metering infrastructure (AMI), Mulherkar said.

“There are about 55 million AMI meters installed and 40% AMI penetration, and there is another 30% [Automatic Meter Reading (AMR)] penetration. Utilities are very comfortable with the technology and now it is just a matter of making a viable business case for the technology.”

Utilities see AMI as a pathway to lower operational costs, making managing outages more efficient, and assuring a new revenue stream. Despite financial and policy drivers, the paper reported, the market is still not thriving, due largely to two significant barriers.

First, large utilities face upfront costs for deployment that “can easily reach hundreds of millions of dollars or more.” Demonstrating the benefits of this expenditure to regulators can be problematic. Second, the benefits in deregulated markets can go to utilities or private sector sellers, but could spur disputes over who should bear the cost of deployment.

Some innovative vendors have overcome these barriers with flexible smart-grid-as-a-service offerings to reach lower price points for capital investment, the paper reports. Others are using fully managed models, in which the vendor owns and operates the entire system, or hybrid models, in which the vendor owns, hosts and operates the associated software and could own and operate the AMI network infrastructure.

Some approaches have brought costs down to “a third or less of the upfront investment of owning the AMI system,” the paper adds. An example is CenterPoint Energy's effort in Texas.

CenterPoint’s unique success acting as a utility provider in the deregulated Texas market is a landmark demonstration of AMI benefits, GridWise Alliance Executive Director Steve Hauser recently told Utility Dive.

Drivers behind CenterPoint’s effort were the opportunity to better manage outages, earn assured revenues, and cut the costs of meter reading and other field services, the paper notes. The deployment was backed by a $150 million U.S. Department of Energy Smart Grid Investment Grant.

Through April 2015, CenterPoint documented $24 million in annual consumer savings from service fee reductions, alongside 11.4 million electric service orders executed, restoring power to 1.2 million customers without phone calls, and a 50% to 60% truck-roll success rate. And it used AMI data to develop internal algorithms that identified 3,000 potential theft cases per month.

What worked for CenterPoint Energy included careful pre-planning and several efforts to reach and educate stakeholders, the researchers concluded.

To prevent glitches, CenterPoint had its communication infrastructure in place three months before the deployment, giving time to pre-test critical services. It also posted door hangars for its customers, launched a smart meter website, and opened an Energy Insight Center for customers.

As a result, only 0.01% of its customers opted out of its AMI rollout, the GTM paper reports.

CenterPoint’s next step, according to the paper, will be to feed its AMI data to a distribution management system to streamline its operations.


Storage on both sides of the meter

Though energy storage is a developed technology, "the vast majority of U.S. utilities don’t have the same experience with energy storage that they have with AMI,” Mulherkar said.

Where AMI deployment is standardized, energy storage installations are still mostly one-off deployments, he added. And while AMI vendors are established, there is a lot of venture capital investment in energy storage.

Policy is helping drive the market, but utilities are also beginning to discover energy storage, the paper reports. They are beginning to understand how it can help to defer transmission and distribution system investments, and realizing how its ability to smooth voltage and support power quality can be vital to integrate various renewables on the grid. 

Southern California Edison’s 2014 procurement of 261 MW of storage is the biggest utility acquisition to date, but independent power producers are building installations to sell capacity into wholesale markets, with the PJM Interconnection leading so far.

Leading in-front-of-the-meter vendors in these markets include ABB, AES Energy Storage, and S&C, the paper reports. But these same names are moving into behind-the-meter energy storage, which is expected to have a higher annual value build by 2020.

“Aggregated behind-the-meter energy storage is increasingly able to provide the same grid services as front-of-the-meter storage,” the paper reported. Behind-the-meter energy storage can also capture additional value streams, including backup power and energy bill savings for end users. Leading providers in aggregation software include GE and NEC Energy Solutions.

Early efforts by Australia's Ergon Energy are especially noteworthy because the power company — which has both a T&D utility and a retail electricity provider — uses networked residential storage, Mulherkar said. That makes it possible to provide value streams both to the regulated distribution utility when it uses batteries in wholesale markets and for system balancing, and to the retail electric provider in offering new services and products to customers. 

Ergon Energy, the deregulated player, owns 33 solar-plus-storage systems and customers pay monthly fees for their use. They are SunPower 4.9 kW solar PV systems and 5 kW/12 kWh Kokam batteries with Schneider Electric and Sunverge supporting electronics.

The best practice illuminated in this case is the advanced supporting electronics that interface with the regulated utility. That makes the stored solar-generated electricity available for system purposes such as peak load management, energy trading, and customer retention. At the same time, customers have saved an estimated 10% to 20% on their bills and have the storage available for backup power.

Microgrids breaking in

The maturity of the microgrid market is “a notch below” the energy storage market, Mulherkar said. “Deployments are still highly customized one-off deployments. Though they have demonstrated benefits, funding still comes largely from grants.”

The market is expected to grow 267% between 2015 and 2020 to an $829 million annual market for 2020, the paper reports. Drivers include resiliency-focused grant programs, research institution funding, and military-led and vendor-led pilots.

But microgrid growth faces significant barriers, Mulherkar said. “Upfront and financing costs can be high, reliability and resilience benefits are somewhat difficult to quantify, and legacy regulations about utility franchise rights and public rights-of-way make entry difficult for non-utility players.”

The market is beginning to shift as microgrids become part of grid modernization, the paper reported. As efforts to build resiliency expand, microgrid technologies will advance and become standardized, leading to policy corrections like those being considered in New York, Maryland, Illinois, and Connecticut.

This incremental process will eventually lead to better microgrid value propositions and market acceleration, Mulherkar believes. Hawaii and California are likely to lead.

The non-standardized state of microgrid implementation has opened the door to competition between over 100 vendors and service providers, the paper reported. Services include modeling, controlling, and optimizing operations. ABB, GE, Schneider Electric, Siemens, and Toshiba are the big names, but startups like Power Analytics, Princeton Power, Smarter Grid Solutions, and Spirae have found places, according to the paper.

The University of California at San Diego (UCSD) microgrid shows what a the technology can do and is the closest thing the market now has to an example of "best practices."

The 42 MW microgrid serves “12 million square feet of buildings, with twice the energy density of commercial buildings on average,” the paper reports. Its central gas turbine cogeneration system provides over 85% of the campus electricity and over 95% of its heating and cooling.

The 3.8 million gallons of thermal energy storage (TES) “enables optimization of the cogeneration system, permanent load shifting, and demand response,” the paper added.

“[The microgrid] has grown iteratively over more than eight years and they continue to add to it,” Mulherkar said.

The project benefited from $25 million in capital incentives and $72 million in energy efficiency programs from the California Public Utilities Commission and over $5 million in California Energy Commission R&D funding. It saves the university about $850,000/month in energy costs. 

The system is connected to the San Diego Gas and Electric grid and is the utility’s biggest source of demand response. But, in an emergency, it can disconnect from the grid and sustain critical campus loads including from its hospital, police stations, and laboratories.

What a utility needs to know

The paper’s case studies demonstrate there are, for these eight emerging technologies, best practices that produce real benefits, Mulherkar said. “There can be reluctance to work with newer vendors but the utilities in this space have found ways to do it successfully.”

Utilities hesitant to move ahead with their own investments in the the eight grid edge sub markets — AMI, Communications, Demand-Side Management, Distribution Automation, Energy Storage and Fuel Cells, EV Integration, Micro-grids, Network Operations, and Soft Grid efforts — now have a new option. The best practices and reliable vendors featured in the GTM report can offer ideas for similar programs, Mulherkar said.

For instance, Florida Power & Light took on cutting edge distribution automation technology with third party provider Sentient, and Commonweath Edison tackled home energy reports and energy saving recommendations with Oracle, Opower, and C3. They all delivered promised benefits, Mulherkar said.

“There is a big opportunity for utilities to partner with vendors to leverage things their customers are doing independently,” Mulherkar said.

“Energy storage, for instance, is penciling out for C&I customers and is beginning to pencil out for residential customers and a lot of that is happening independent of utilities," he added. "There is significant potential for partnerships between utilities and designers of these products.”

Filed Under: Transmission & Distribution Solar & Renewables Energy Storage Distributed Energy Efficiency & Demand Response Technology Corporate News