With all the stimulus money that has been invested in Smart Grid to help jump start the advanced metering infrastructure (AMI) business in North America, one can ask the difficult question about return on investment and benefit realization. Given that many of the economic justifications of advanced metering are the societal benefits associated with demand reduction and consumer behavior changes, it may be difficult to ascertain the contribution of this technology to actual customer changes.
While the analysis of customer participation rates, stickiness of participation, and demand response fatigue are all valid metrics and significant factors to consider, some energy utilities appear to be avoiding the difficult process and adopting strategies that stick closer to the “normal” way of doing business.
For example, calculating the impact of conservation voltage reduction (CVR) may be easier to determine than estimating how many customers will over-ride the fifth demand response event during a heat wave. Likewise, managing Volt/VAR in an interactive manner may be easier to assess than determining the impact of conservation alerts provided over an in-home display unit.
To achieve the benefits of an advanced metering system, there must be a saturation level (meters remotely read) before any significant operational savings can be accrued. Whereas, in a distribution automation (DA) environment, one may elect to surgically deploy technology with “trouble” circuits, and avoid blanketing the entire service area with a network.
In a recent commission study, AMI and various distribution automation technologies were analyzed to see how the return on investment of different technology implementations could be realized over time. Treating these different grid technology solutions in a similar manner to generation resources, economic dispatch tools can then be used to schedule execution to achieve the greatest short and long term benefits. For instance, as previously noted, AMI requires a level of saturation to achieve many of the long term benefits; whereas, line fault indicators can yield a quicker return if they are deployed in areas that have historical problems.
Is advanced metering taking a back seat to distribution automation in Smart Grid implementation? My opinion is no. AMI is a strategic utility asset that provides great value beyond revenue collection. Smart meters today produce a suite of comprehensive information that has value throughout the enterprise. In a similar manner, if distribution automation can be deployed surgically to known trouble circuits, then the problem is much easier to solve. However, intelligence is often required to know which circuits are in trouble. That is where AMI can be a strategic DA asset.
So what are your thoughts on advanced metering infrastructure and distribution automation? Are they complementary in the path to Smart Grid? Should they be dispatched equally? Or is there a strategic value to focusing on one first?
By: Ron Chebra, vice president, Management & Operations Consulting, DNV KEMA Energy & Sustainability
Something significant is lost by generalizing this issue. The question that needs to be asked by each utility (and possibly for each circuit) is ‘Where are we now?’ A costly DA rollout may be justified if a utility has not historically invested in IEDs, switched capacitors and prioritized improvements to its worst performing circuits. The same rollout may not be justified for another utility that has been consistently improving its system in deliberate incremental efforts over time. Some legacy outage management software, together with engaged engineers, can provide the intelligence required to identify trouble circuits. Other legacy systems may not provide enough information. Each utility must consider their own cost-benefit analysis for the condition in which they currently find themselves. For better or worse, this may mean that some poorly performing utilities will be (and have been) eligible to take advantage of funding sources for projects that allow them to ‘leapfrog’ better performing utilities whose business cases for similar projects are comparatively weak. The repercussion is that the new state-of-the-art projects are hailed as something everybody should be doing, and then commissions pressure the better performing utilities to chase a carrot that is out of reach for them.
Wyatt, thanks for your comments and insights. You are correct in stating that every utility must do their own analysis of how and where best to invest. My blog was intended to address the general issue of how AMI and DA should co-exist in the right environment. I do not see it as an either or case, but rather one of how these technologies can complement the business needs of the utility.
Thanks for posting your comments.
To view AMI & DA as two separate projects and systems is to miss out on what would seem to be obvious synergies. While I agree with you that a high level of saturation is required to reap the full economic benefits of an AMI deployment, even limited, targeted deployments such as “end of circuit” meters to provide data for CVR initiatives show how symbiotic the technologies can be. The mutual benefits are multiplied with that saturation, for example using outage traps from the AMI network, correlated and filtered, to feed outage/restoration verifications to an OMS system.
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