Enbala Blog

More Equipment or Better Engagement: Which will pay off better for you?

Posted by Enbala on May 5, 2016 9:53:00 AM

INTRODUCTION:

Raise your hand if you’re a utility professional or grid operator planning to make some significant infrastructure investments in the next few years. You won’t be alone.

After all, energy infrastructure in the U.S. earns a D+ from the American Society of Civil Engineers (ASCE). If you went to the ASCE report card, you’d see some mighty big numbers associated with the transmission and distribution spending that will likely be needed by 2020 to fill the investment gap, which is the difference between what’s needed and what’s planned.

 


On the distribution side alone, the investment gap could equal $10.3 billion in the area served by the Western Electric Coordinating Council, the largest of the regional entities charged with promoting reliability in the bulk power system. The gap equals $11.8 billion for the Midwest and eastern states served by the ReliabilityFirst Corporation and $18.8 billion in the area served by the Southeast Reliability Corporation.

An article this past February in The Roanoke Times noted that Appalachian Power earmarked $237 million to upgrade one substation. Plenty of utilities look at a price tag like that and wish they could defer the expense. Chances are, they can. At least, that’s what Enbala found after conducting a study for a North American utility.

Picking a winner

UtilitySubstation.jpgThe utility in question wanted to see if using the Symphony by Enbala platform to shift load away from peaks would be a cost-effective way to spread out investment dollars. Since some substations have more demand management potential than others, Enbala used multiple years of data on substation load, load limits and associated large industrial/commercial load data from ten different sites. Then, the Enbala team ranked the substations in terms of suitability for system deployment, and three were selected for more rigorous study.

How did Enbala pick the substations? The winners showed significant peak-shaving opportunities as well as three or more weeks per year during which the substation almost hit peak capacity. Each station also has an anticipated2 percent annual load growth forecast.

Among the things Enbala investigated were the type of commercial and industrial accounts served by each substation as well as the kind of load each potential business participant had to offer. Enbala classified potential loads as:

  • Constraint-based – These loads have process flexibility, meaning that the work done by the loads may be shifted slightly without upsetting any site processes, and Enbala follows customer-defined constraints in controlling the load itself. Water pumping is a good example of these loads.
  • Impactful loads – These are loads that either do not have process flexibility or are not controllable.
  • Base loads – These other site loads may be random but common. They include elevators, computer equipment, etc.

After classifying each load, Enbala engineers estimated kW flexibility and kWh storage of constraint-based loads using Enbala’s past experience and research conducted with the U.S. Department of Energy and the Oak Ridge National Laboratory (ORNL).

Ultimately, the Enbala team was able to quantify curtailment potential for a large set of 70 to 120 C&I loads on each particular substation.  This was done by modeling, but Enbala also did some site visits to better understand specific loads that could participate in a demand management program.

One, a tomato-growing operation, may have more than 10 MW of dispatchable demand using automated lighting and cogeneration.  In this company’s case, the very conservative Enbala modeling tool would have estimated curtailment at about 20 percent of site’s demand, but the more specific and detailed site audit identified that more than 75 percent of site demand could be curtailable. 

As for costs of the system, Enbala used a number of assumptions in making those calculations. The Enbala team assumed recruitment would be led by the utility, customer incentives and program costs didn’t factor into the calculation, and customer churn expense also was left out.

Given this, the estimated price tag of the Enbala platform to provide capacity upgrade deferral and system peak shaving ranged between 66 and 80 $/kW-year in Canadian dollars. In U.S. dollars, that range is $50.85 to $61.63.

How does that compare to the $/kW-year cost of your substation investment plans over the next few years? Let us know if you'd like to talk to us about how to leverage distributed energy resources to improve your capital and operating investment scenarios. Contact info@enbala.com.

 



 

Topics: distributed energy resources, DERs, utility infrastructure, utility CAPEX improvement, peak load management, T&D infrastructure, CAPEX/OPEX

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