Electric cooperatives have a long history of integrating distributed generation (DG) sources. But if you want a glimpse of the future of DG, you’ll find it in the wooded hills and valleys of northern Vermont, where Vermont Electric Cooperative is already living with challenges many co-ops will eventually face.
Vermont Electric, based in the town of Johnson, has wind generation, community solar, rooftop solar, and hydroelectric power all feeding into its system. “Eighty percent of our load is coming from renewable resources, if you include hydro,” says Christine Hallquist, Vermont Electric’s CEO. “And we’re greater than 95 percent carbon free.”
The DG on Vermont Electric’s system includes 10 MW of net-metered solar, which equals 12 percent of the co-op’s peak load. All those inputs required the cooperative to adapt rapidly, both technologically and in communicating with members about what these changes mean to Vermont Electric’s costs and rate structure. “In the broadest sense, there are two distinct challenges,” Hallquist says. “One is public outreach, and the other is engineering.”
Many co-ops are likely to find themselves adapting to similar circumstances in the coming years. The rapidly growing presence of DG on the grid is leading to changes in everything from power quality standards to the way electric bills are calculated. “We’re moving into a different world,” says Jim Spiers, vice president of NRECA’s Business and Technology Strategies (BTS) unit.
That world involves integrating more DG into an evolving energy landscape in ways that best serve co-op members while also maintaining the reliability and integrity of power systems. In the end, Spiers say, it’s all part of the cooperative’s role as a supplier of “energy services”— providing members with options, guiding them to the best decisions, and deploying the necessary portfolio of technologies to meet those needs.
To help co-op engineers and other employees prepare for this future, NRECA is offering a six-hour online course that deals with the technical and policy issues a co-op is likely to face as the pace of interconnection picks up. “Our push is to get people to think ahead of the curve,” says Gary Pfann, NRECA director, staff and executive education. “Don’t wait until you need it. Be prepared ahead of time.”
The course addresses DG interconnection standards, operations, and maintenance concerns like safety and voltage regulation. It also includes materials on DG contracts and rates. To bring it all down to earth, “numerous case studies are used as learning tools to highlight realworld issues and solutions,” Pfann says. “These studies include cases dealing with wind, landfill gas, cogeneration, as well as small to large solar arrays.” (Visit the Conferences and Education section of Cooperative.com for more information.)
Obvious Challenge: Intermittence
The obvious challenge that has been part of DG from the beginning involves the intermittent and variable nature of sources like solar and wind. The generation is there when it’s there, not necessarily when you need it to be. This characteristic becomes markedly more significant as its presence expands on a system.
For example, Vermont Electric’s renewable portfolio is impressive, but as Hallquist explains, “Here’s the challenge: Yes, we have about 12 percent of our peak, about 10 megawatts, coming from net-metered solar, but it only produces about 2 percent of our annual energy requirements.”
Distributed generation also isn’t distributed evenly throughout the cooperative’s system, which adds to the complexity of managing it. “The engineering becomes critical. We’ve got one of the most technically advanced control centers of all the co-ops, and we have it there for a good reason,” Hallquist says. “One hundred percent of our substations are on SCADA; all our meters are smart meters; and we’re constantly looking at feeder-by-feeder voltage levels where we’re getting saturated by distributed generation. It really is an important challenge to look at where they’re all located.”
Inertia and Stability
Delta-Montrose Electric Association, based in Montrose, Colo., is another cooperative on the cutting edge of the DG revolution. Like Vermont Electric, it has community and rooftop solar and hydroelectric power, in this case from an irrigation canal project. It also has coal mine methane generation. When all this DG is running full steam, “it can amount to upwards of 20 percent of our annual peak demand,” says Jim Heneghan, Delta-Montrose’s renewable energy engineer.
“We ended up with three hydroelectric generation plants that all feed off the same irrigation canal. It’s all fed back to the same substation, and that generation regularly and frequently exceeds the load at that substation,” Heneghan says. “So we have had to wheel that generation.”
Having significant DG from renewable sources comes with another complication. Solar and, to a lesser degree, wind power lack the “inertia” that comes from traditional generation sources, such as natural gas turbines. Rather than cycling down or up, it can jump precipitously from on to off, complicating the task of maintaining a reliable system.
When Vermont Electric added a significant amount of power from a new wind farm in its area, it ended up integrating a large flywheel, or synchronous converter, which creates a lot of inertia by spinning into the system to smooth out power fluctuations. “We put the wind power in one side of the flywheel and then take it out on the other side,” Hallquist says. “That introduced the inertia and stability we needed.”
As DG grows, managing the interplay of fluctuating distributed generation, system load, and power quality is going to require co-ops “to perform a level of grid analytics that wasn’t necessary before,” says Andrew Cotter, an NRECA BTS program manager. “And a lot of the co-op distribution and transmission system models aren’t dynamic enough to handle that at this point.”
Over the longer term, Cotter sees incorporating more sophisticated dynamic system modeling and analytics, such as NRECA’s Open Modeling Framework, as one of the most important advances co-ops and other utilities will need to make to handle the growth of DG.
Tucson Electric Power, an investor-owned utility in Arizona, now has nearly 12,000 rooftop solar arrays in its system. Ted Burhans, the company’s renewable energy resources manager, notes that a lack of visibility into that DG is one of his biggest challenges.
“We don’t really have eyes into what those [arrays] are doing, and that’s really hard,” he says. “With traditional grid operations, you know what every single generator is doing. Here, you’ve got close to 12,000, and they’re all generating something every single part of the day, and it just shows up on the system. The impact on system frequency voltage is just compounded because of the sheer numbers.”
Distribution utilities are going to need greater control of the DG on their systems to ensure safe operation and to maintain power quality, says Robert Harris, NRECA principal for transmission and distribution engineering.
Some utilities with high DG penetration have started turning to “smart” inverters, particularly in Hawaii, where interconnected rooftop solar is widespread. These inverters allow two-way communication, including remote control of settings, and provide data on power quality and other key factors of DG.
“Control of the [power] inverter, in my opinion, is going to become a significant issue,” Harris says. “If co-ops don’t have control over the settings on the inverter and the ability to monitor it, then it can have an impact on their system operations.”
DG’s growth is already leading to changes in the regulatory standards that govern its interconnection into distribution systems. Harris says the original standards were written with tight parameters for voltage and frequency, with power tripping if either fluctuated outside the range. “At the time, most of the concern was about potential safety risk and power quality risk that small generators could create for distribution systems,” Harris says.
But Germany, which was leading the world in promoting renewable distributed generation, started to see problems caused by tight power-quality standards. Too much DG could suddenly drop off lines, which meant the grid had to fall back on conventional sources that could no longer easily handle the load.
The North American Electric Reliability Corporation (NERC), which develops and enforces grid reliability standards, became concerned that the same could happen in the United States as DG grew, Harris says.
The principal standard regulating DG interconnection is IEEE 1547. “They started pushing to get 1547 modified so the voltage and frequency standards were opened up,” he says. In 2014, an amendment to IEEE 1547 made the changes optional, but a significant revision to 1547 now underway is expected to make them mandatory.
The revised 1547 standards are also adding “interoperability” into the title, recognizing the need for distribution systems to be able to take greater control of DG. In addition to smart inverters, other hardware is being developed to help, says Mike Casper, NRECA senior manager, generation and fuels. “One of them is a meter collar between the bubble and the meter box that allows new communications and new data to be provided to the co-op,” he says. “It enables a lot more control and operation.”
The Role of Storage
The DG “game changer,” as Delta- Montrose’s Heneghan puts it, would be “economically viable storage,” which would address the variable nature of DG. Advances are being made in battery design, and products like Tesla’s home battery system or a saltwater battery system by Aquion Energy, which Vermont Electric is testing, are bringing down the cost of home storage. Water heaters and electric cars will also provide in-home ways to store power for later use.
NRECA’s Cotter notes that battery storage is “where solar was 10 years ago” but is advancing even more rapidly and, along with DG and an emphasis on energy efficiency, is expected to play a big role in the future. “The long-term challenge is putting all three tools together, understanding how they play with each other, and then building business models around them,” Cotter says. “That’s a pretty big departure from the traditional utility planning model, and it’s where we’re headed.”
Educating members on the significance of these changes and what they mean to co-op operations will be as important as the technological shifts.
‘Run Their Bill to Zero’
Around the United States, solar-power vendors have sold photovoltaic systems as providing essentially “free energy” that can liberate consumers from the grid. In reality, of course, the grid remains essential to providing the reliable power, day and night, that Americans count on.
That means the cost of maintaining the grid, from transmission lines to distribution systems, is still there. But in some states, regulations intended to promote the growth of renewable sources of power have created a situation where consumers selling DG back into the system can take advantage of the periods when the sun is shining to avoid paying most or all of those costs.
“The way the net-metering rules are written in Vermont, our members can bank their credits for one year and can use their DG to run their bill to zero, including wiping out their monthly meter charge,” Hallquist says. Solar developers have been sizing rooftop systems to help consumers accomplish this, she adds, but these consumers still count on access to the grid when the sun isn’t shining.
The situation has left the cooperative in a difficult situation. “If you look at our grid maintenance costs, our studies show that we need to recover $40 [per meter] each month,” she says. The costs are built into the co-op’s rate structure and meter fee. But with net metering, state regulations mean that members who do not have solar are, in effect, subsidizing grid maintenance for those who do.
In Colorado, Heneghan says Delta-Montrose’s board of directors was able to add a monthly base charge of $25 to help recoup fixed costs. But as DG grows, he says, it will become essential to ensure co-op rates and member agreements take into account the full implications of depending on DG resources.
‘Have an Honest Discussion’
Hallquist says making sure consumers understand how DG affects their cooperative is the final part of the puzzle, but it’s one where co-ops have a historic advantage. “We have a high level of trust with our members,” she says. “So all we need to do is get out there and tell the truth and be very positive and supportive … and have an honest discussion about what the issues are.”
As part of that effort, NRECA has updated its toolkit that provides members with templates for interconnection agreements and deals with other procedures to make sure both smaller and larger DG can be successfully integrated into a distribution system in a way that’s beneficial both to the members and the co-op. (Visit Cooperative.com to download the toolkit.)
NRECA’s Spiers notes that it’s all part of the co-op effort to make sure they are providing the energy services their members need. “The objective is to put every co-op in a position where they can find the right solutions for their member-consumers,” he says.
Heneghan believes the growth of DG plays to the strengths of electric cooperatives. “The co-op community has always prided itself on reliability and service, and I think we’re still going to be able to pride ourselves on reliability and service as we adjust to this shift from central generation to more distributed, local generation,” he says. “It has some challenges, but it’s also an opportunity. I think it’s a very exciting time to be in the industry.”