How To Manage Generation & Transmission Demand Flexibility Programs Under a Single Umbrella

During the heatwave of summer 2023, generation and transmission (G&T) cooperatives effectively met demand with few interruptions to service. This is a significant accomplishment since the last eight consecutive years have proven the hottest on record, and meteorological evidence from 2023 suggests that Earth may endure its ninth such year of temperature extremes. These temperature extremes cause increased electric demand, which is compounded by global electrification efforts that add further encumbrance to the grid. These challenges are surmountable through several strategies, from adding more distribution lines to employing demand flexibility initiatives to conserve or aggregate existing communally generated energy assets. For rural cooperatives, these demand flexibility programs may prove cost-prohibitive. Fortunately, G&T operations can aggregate across multiple territories to help cooperatives all over to enhance their grid resiliency, defray high energy costs during peak demand, and improve member satisfaction.

The Cost of Infrastructure Upgrades

Since 1936, President Roosevelt’s New Deal and Rural Electrification Act have brought electricity to rural areas for generations. Like the Inflation Reduction Act, which offers billions to develop the electric infrastructure necessary to modernize the grid, the REA came with a steep initial budget of $50m annually for the first two years, then an additional $40m for the next decade, for a total of $580m. With inflation, that’s more than $10b today. Funding infrastructure has always proven expensive, albeit necessary, which is why significant updates are currently needed and why they take so long to begin with.

Research indicates that overhead transmission lines cost around $86,700 per mile, or almost $1m in rural areas. While burying transmission lines does much to increase the resiliency of lines, it adds an exponential cost to the construction with estimates of around $297K per mile in rural areas or almost $4.5m in urban areas. While these figures represent new construction initiatives, existing infrastructure carries a price tag of nearly $750 per customer. Still, that beats the rapidly rising costs of inaction in climate change which cost $165b in 2022 alone.

In addition to challenges to grid resiliency, inaction against climate change is estimated to hit around $1.7b in economic damage per utility by 2050. As it stands, it would cost the U.S. around $21t to upgrade the grid. So while those changes are required for a variety of reasons, it’s infeasible that any one utility, energy market, or even nation can afford to fund all of those upgrades in a short period. Fortunately, demand flexibility initiatives offer a scalable, one-sized solution for cooperatives—including G&T operators—to better manage demand during peak usage, increasing grid resilience while defraying high peak energy costs.

SaaS-Models & Non-Wires Alternatives

From environmental, social, and corporate governance (ESG) ratings as a credit assessment to robust market growth in distributed energy resources (DERs) & distributed energy resource management systems (DERMS), investments in renewable energies and electric infrastructure are rapidly developing. Still, keeping up with demand at the moment is a tall order that funding hasn’t quite caught up to. To keep up with demand, turn to the clouds. SaaS-modeled software solutions offer not only the non-wires alternatives that foster demand flexibility potential by several metrics but a comparatively much smaller upfront and annual recurring cost.

While these initiatives may prove cost-prohibitive to individual cooperatives, G&T utilities can apply them to a broader market of potential customers, boosting the potential for enrollment and scalability necessary to increase savings and decrease high energy costs. Through a distributed energy resource management system (DERMS), utilities can aggregate any distributed energy resource (DER)—including smart thermostats, EVs, batteries, solar, and more—irrespective of where those devices are located, so long as they are WiFi enabled. What that means for G&T utilities is that, unlike individual electric cooperatives, they can employ demand flexibility programs to greater effect across a bigger area, yielding more savings.

Types of Demand Flexibility Programs

As enumerated above, there are many demand flexibility options for G&T utilities to craft. Demand flexibility programs have flourished over the last decade through the Internet of Things (IoT); as more devices are online, there are more opportunities for widespread device control for participating members. Those opportunities are and will expand both to meet greater device adoption and as the United States expands broadband access.

Demand Response

Perhaps the oldest and most renowned demand flexibility initiative, demand response is a conservation strategy that minimizes usage during peak demand through concerted and coordinated device control. For members, those efforts often manifest as their thermostats are lowered—although rarely shut off—to decrease overall consumption. These strategies are at their most effective when members willingly participate; seizing control without homeowner consent has often led to an understandably poor public backlash. Likewise, demand response is often incentivized, which, along with member engagement, can be managed automatically by program managers to quickly and efficiently enroll, engage, and, eventually, scale programs to greater savings.

EV Managed Charging

EV managed charging is a protocol parallel to demand response. While V2G charging functionality allows utilities to shift load from an idle EV battery reciprocally back and forth to the grid, EV managed charging conserves energy through load shifting during periods of peak demand. Currently, EV production has increased both due to public adoption and legislative mandate, meaning that by 2030, there will be more EVs on the road than ever. With the IRA and comparable bills bringing EV infrastructure beyond rural areas, managing EV charging is an inevitable existential reality. Still, EV managed charging is an effective demand flexibility initiative, by shifting loads from during peak periods of usage, charging during off-peak periods instead.

Technical Virtual Power Plants

Virtual power plants have proven a buzzword for years now, with the tacit promise that they will change the industry. So far though, they are proving incredibly potent as a load-shifting strategy, which is why the Department of Energy has invested in VPP functionality in weather-prone areas like Puerto Rico, to better help with long-term grid resiliency. Virtual power plant initiatives function in several ways, although in general, they aggregate any of the many DERs on the market, to either shift load from ambient community energy assets like solar or to conduct wide-scale conservation efforts across a variety of device types.

How To Manage Generation & Transmission Demand Flexibility Programs Under a Single Umbrella Conclusion

Each example of demand flexibility benefits from a wider range of constituents. Because of this, G&T cooperatives are poised to utilize these programs and initiatives at a much larger scale, aggregating net savings and defraying high energy costs at a comparatively higher rate than any individual cooperative. These non-wires alternatives represent a fixed and much lower cost than pricey infrastructure repairs, helping utilities big and small alike better prepare for tomorrow today.

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About The Author
Jeff Quigley blog author

Jeff is the VP of Sales for Virtual Peaker. He has spent his entire career in energy and data analytics where he has led teams working with utilities, government agencies, oil and gas companies, and financial institutions to help drive growth strategy and manage energy transition. He has worked with a team of analysts in developing an integrated resource plan (IRP) for a major U.S. vertically integrated utility, with a focus on load forecasting, locational marginal pricing (LMP) prediction, and long-term grid reliability. He has also managed the development of marketing and growth strategy for one of the four largest global oil and gas firms with a focus on the long-term viability of the Asian market-entry strategy.

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