Smart grid stimulus: some important thoughts for the ‘quiet period’


By Tim Wolf

Hundreds of Smart Grid Investment Grant (SGIG) applications are now in the hands of the Department of Energy and being reviewed initially by a cadre of hired industry consultants, engineers and other experts to determine which applications merit more detailed consideration and ultimately funding. Funding decisions are expected to be announced by the DOE in the fall.

In the weeks leading up to the August deadline, hundreds of utilities and other players in the energy markets across the United States found themselves in a stressful scramble to plan, strategize, analyze, quantify, position and capture their Smart Grid aspirations into neatly packaged grant applications hoping to get a slice of the pie from the SGIG program.

With estimates projecting that Smart Grid in the United States will ultimately take anywhere from $200 billion to over $1 trillion, the $4.3 billion in funds available through the ARRA program represents a tiny fraction of what will be required to truly modernize the nation’s energy delivery system. Nevertheless, utilities large and small, those with well-developed Smart Grid plans and those for whom Smart Grid is still a gleam in the eye, could not pass up the opportunity to take their best shot at some federal funding.

Looking back on the history of the 20th century, few would argue that the Federal-Aid Highway Act off 1956, which provided impetus and funding to the Interstate Highway System, did not provide a huge and enduring boost to economic growth by creating an efficient, safe and standardized national transportation network.

But the Smart Grid is not a massive slab of concrete strengthened by steel and rebar. It’s a complex, rapidly evolving concept. Some of its components are here and available today. Some are years away from commercialization and widespread adoption. While much of the Smart Grid is tangible – hardware, software, communications equipment, etc. – the most difficult challenges lie in the areas of system integration, interoperability, standards, data management, security and other areas that are still somewhat ethereal.

Whether 10 years, 20 years or 50 years from now, it will be fascinating to look back and debate whether the ARRA Smart Grid Investment and Demonstration Programs of 2009 performed as advertised and provided the impetus to modernize the nation’s energy delivery infrastructure. Did it help create an engine for economic growth by supporting a reliable, efficient, and environmentally sustainable supply of energy? Or did it lead to an ill-considered hodge-podge of spending and technology procurement that lacked a unifying vision. Only time will tell.

So what have we learned from our collective experience with the SGIG grant preparation thus far, and how can we apply what we’ve learned regardless of each utility’s particular funding outcome?

AMI is core to Smart Grid
By no means did every SGIG investment grant include advanced metering infrastructure (AMI) technology, but certainly the majority of applications our firm assisted with featured AMI technology as their centerpiece. Two-way communication to every customer premise, interval data collection, outage detection, remote disconnect/reconnect, voltage monitoring, home area network communication for load control, demand response, price signaling, etc. all add up to a communication, monitoring and control package that for now – is the cornerstone of the Smart Grid.

As the DOE evaluates the AMI category applications, clearly those utilities that have successfully combined large-scale AMI installation with clear intentions to offer time-based rates on a broad scale and evaluate the results through a carefully constructed, randomized study methodology, will be at an advantage. And while the DOE clearly acknowledges the fact that many utilities submitting AMI-centered proposals still need regulatory approval to introduce time-variant pricing tariffs, those utilities that are able to achieve expeditious support for those tariffs from their commissions will find themselves in a advantageous position for funding.

Regardless of how the $4.3 billion is doled out, the application development process further reinforced the notion that without AMI there can be no Smart Grid, and utilities developing their Smart Grid plans and strategies are smart to put AMI front and center in as the key building block to a “no-regrets” technology strategy. The technology is reasonably mature and reliable. AMI costs, when analyzed in the context of a broader business case that properly and accurately contemplates demand response, peak load reduction, and distribution-side reliability and efficiency benefits, generally provides a favorable return on investment to cover the increased cost above traditional automatic meter reading and one-way fixed network systems.

Standards and interoperability are not necessarily synonyms
Standards are not yet mature or complete – we must focus on interoperability in the near term. Perhaps the greatest challenge to utilities in assembling their grant applications was crafting a compelling system interoperability story for their projects. While most of the interoperability requirements, such as summarizing communication interfaces, integration of legacy systems, and response to device failure and upgrade scenarios, were fairly straightforward, harmonizing these projects with the National Institute of Standards and Technology (NIST) Smart Grid nascent interoperability framework and roadmap proved more challenging. The fact is that the NIST framework and roadmap is still in its early stages of development. And though the NIST interoperability lists several dozen standards for review and harmonization, the “sausage” is still being made.

Yet whether it was AMI, distribution automation, or home area networks, utilities had to specify currently available technologies, and the standards they currently utilize, for their projects. For example, many utilities proposed Smart Grid projects that rely on the DNP3 protocol standard for communication supporting substation and distribution automation. Yet reconciling that with the NIST roadmap is challenging. For example, the IEC 60870-6, IEC 61850, and IEC 62968 standards appear to be gaining broad acceptance as core components of the NIST framework while DNP3 is being described as a “legacy” protocol that should be phased out and ultimately replaced by IEC 61850. This example captures the dilemma utilities face in specifying and deploying currently available Smart Grid systems in an accelerated manner while trying to adhere to a longer-term vision of deploying technologies that embrace open, common standards.

In this context, the focus must necessarily be on achieving interoperability – the ability to communicate and share data to enable Smart Grid functionality – rather than identifying the perfect standard, which in some areas, may still be years away.

Another key question is what should utilities be thinking about and prepared for if the DOE calls in October and says their project is funded? Or to put it more colloquially, what happens when the dog catches the bus?

Preparing for less than 50 per cent
First, it will be vital that successful utility applicants have a contingency plan that prioritizes and sequences Smart Grid investments in response to alternative matching scenarios. While most applications were built upon assumptions of a 50 percent funding match, the DOE made is very clear in the Funding Opportunity Announcement (FOA) that matching funding will be awarded “up to 50 percent.” So if the specific scenario planning hasn’t been done already, utilities should be planning project contingencies based on award amounts of 20 percent, 30 percent, 40 percent and so on. And in each scenario, what project element would be delayed or eliminated, and what would the implications be for project dependencies and risk?

Strings attached …
All federally funded programs come with strings attached and very specific reporting requirements. SGIG is no different, apart from the fact that the DOE made it clear in the FOA that it intends to exercise “more stringent management oversight and control than normally seen in grant programs.” That means frequent detailed project and expenditure reporting and transparency based on clear project milestones and accomplishments. The requirements include detailed quarterly reporting on funds receipt and expenditures, as well as details on project progress, job creation/retention and other areas. If utilities haven’t already identified specific internal and/or external resources to support the DOE reporting requirements, they should do so because once funding begins, the organizations will be burdened with these significant requirements.

The DOE wants data
The central purpose of the SGIG program is to accelerate investment in Smart Grid technologies and gather comparable data so that solid conclusions can be drawn regarding the costs and benefits of Smart Grid. This data and analysis will, in turn, be utilized by the DOE and other utilities to drive their Smart Grid planning and create replicable models for success. To support this outcome, utilities must become social scientists of sorts, gathering all sorts of data ranging from customer demographics to distribution system performance and reliability, or get help from the local college or university to do so. And while the grant application process provided some opportunity to sketch out how all this data will be gathered and analyzed, the burden has yet to be dealt with. Identifying resources (both internal and external) and defining processes for gathering data will be critical to negotiation with DOE once an initial positive funding decision has been made.

Put plans into a Technology Roadmap
The DOE grant application process provided utilities with a great impetus to do some forward thinking around Smart Grid technology investments. Yet the compressed time frame and mad rush to the application deadline didn’t necessarily allow enough time to place those investments in a clear strategic context. That’s where the technology roadmap comes in. The roadmapping process challenges the utility to explore the future and its vision with respect to its mission and business objectives. To be effective, a technology roadmap must contain both strategic and tactical components. It must provide big picture vision and a path or direction to get there. Yet it also must define tactical (and practical) elements of the vision – security, quality, reliability and availability – are critical as well.

The Roadmapping Process
There is a clear established process for developing a solid technology roadmap for Smart Grid. Most importantly, the roadmapping process requires stakeholders from across the organization to come together, leave behind their notions of “how things have always been done,” and think beyond the traditional constraints.

It’s about asking the right questions: Where are we today? What technology are we investing in and why? What are the key influences and trends that will impact our business over the next 5- 10 years? RPS, carbon emissions costs, aging workforce, PHEVs, distributed generation, market restructuring, changing customer relationships, etc. And how are we managing to those today? Then comes synthesis of the vision. What will we look like in 10 years if we stay on the current path? More importantly, what path do we need to be on to meet those challenges? What does the new path look like compared to the old one and where are the gaps we need to fill?

With this foundation in place, it becomes easier to align capital expenditures and resource allocation with Smart Grid vision and strategy. It quickly becomes apparent which technology investments should take place when in relation to others. What are the “nuts and bolts” solutions utilities can move forward with confidently today that deliver value and also pave the way for future enhancements down the road?

Whether it’s AMI, outage management, distribution automation, integration of renewables, mass market demand response, the technology roadmap provides the basis for effective decision making going forward. Equally importantly, the technology roadmap must be a living document, requiring updates as technology, regulatory or business conditions change. Just by starting the process, a utility can find itself well down the road to a smarter grid. And thanks to the ARRA Smart Grid Stimulus application work, many utilities have a significant head start on that important process.

Stakeholder Facilitation and Education
Strong leadership and executive sponsorship is the most basic requirement of any Smart Grid initiative. Furthermore, deployment of Smart Grid technologies and programs (TOU rates, load control, demand response, in-home devices, etc.) will fundamentally transform a utility’s relationship with its customers. For this reason, it’s imperative that utilities that are awarded funding for their Smart Grid projects to have a solid stakeholder outreach and education plan for customers in place and ready to execute shortly after award. Shared understanding of the project purpose and alignment with objectives, along with support from stakeholders, both internal and external to the utility, will be critical to ensuring project success.

What about the hundreds of utilities that expended many extra hours and resources putting together compelling grant applications only to find out this fall that their projects were not selected by the DOE for funding? If done well, and in a strategic context rather than in a “lottery moment,” those plans have value and can be built upon to provide a Smart Grid roadmap for the future. The only difference is that you won’t be moving quite as quickly as you would if you received matching dollars.

Either way, we’re just getting started.