Navigant Research Blog

New York’s Grid Restructuring Begins to Take Shape

— November 28, 2016

GeneratorAfter numerous rounds of conferences, discussions, and announcements, concrete results from New York’s Reforming the Energy Vision (REV) initiative have begun to emerge. Despite the initiative’s ambitious goals, limited on-the-ground changes have been made. The recent announcement that Green Charge Networks will deploy a network of 13 MWh of distributed energy storage marks one of the most significant developments to date and adds Green Charge to the growing list of companies driving the initiative.

The REV initiative aims for major reforms to both utility business models and market regulations to enable a transformation to a grid built around distributed energy resources (DER). Near-term targets include allowing for greater use of renewable generation and other DER to reduce emissions, improve the resiliency of the grid, and limit costs for upgrades passed onto customers. New York City and other urban areas face extremely high costs for replacing or upgrading underground electrical infrastructure, hence the initiative’s focus on using local DER.

Ambitious Goals

Perhaps the most notable project through REV thus far is the Brooklyn Queens Demand Management Program. This program seeks to defer a proposed $1.2 billion substation upgrade through a combination of 52 MW of demand reductions and 17 MW of DER investments. Most of the projects supporting this effort involve conventional demand response (DR), energy efficiency, and other demand-side management solutions. Utility Consolidated Edison is also looking at more reliable options, including distributed energy storage and microgrids. It first announced requests for information and proposals in March 2016. Following this request, the first major announcement of new DR capacity was released in August 2016, accounting for 22 MW of peak demand reduction capacity, with payments to providers ranging from $215/kW to $988/kW each year. This announcement is noteworthy for including distributed energy storage from leading providers Stem and Demand Energy.

The program has also established incentives for thermal energy storage, with system vendor Axiom Energy offering subsidized solutions to grocery stores throughout New York city. Through the program, customers can save on their monthly bills by using stored ice to provide cooling for refrigeration at times of peak grid demand rather than compressors; the utility is then able to reduce peak demand in constrained areas. These incentives are expected to result in 6 MWh to 8 MWh of utility-controlled demand reduction capacity.

Building on Success

The announcement for a further 13 MWh of distributed storage capacity from Green Charge Networks further builds on the progress made through the REV initiative. This progress positions New York as a leading state in shaping the structure of the emerging distributed energy ecosystem. A successful transition to a DER-centric grid requires a two-pronged approach. It’s necessary to both facilitate the integration of new technologies and also to reform utility business models so that all stakeholders—including utilities—benefit from the efficiency and resiliency that DER can provide. These recent developments have made New York’s efforts much more tangible, and it will be exciting to see what else the state has in store.


The iDER Playbook for Utilities: A Firsthand Report from the EEI Strategic Issues Roundtable

— November 14, 2016

SmartCityMichael Rutkowski and Jay Paidipati coauthored this post.

Navigant’s new integrated distributed energy resources (iDER) maturity model provides a valuable tool for immediate application to address today’s emerging industry needs. Using the tool, utility planners can evaluate their current state of readiness for DER integration and value capture, as well as provide guidance for future investments. We recently had the opportunity to apply the iDER maturity model during a highly interactive session with a senior utility audience at the Edison Electric Institute (EEI) Strategic Issues Roundtable, and the findings tell a compelling story.

After sharing some of Navigant’s latest insights on DER and our industry tipping points, we opened the dialogue to focus on the five dimensions of the iDER maturity model—Customers & Programs, Regulation & Policy, Business Models, Technology, and Operations. After outlining the context of each dimension, we described the characteristics of a utility at the highest maturity rating—Level 5—and described what such a utility would look like in terms of strategic focus, operational capability, and market structure.

Scoring DER Readiness and Importance

We prepared the audience, a group of about 80 utility executives, for deeper discussion by asking an initial strategic question for each dimension: How important is it for your utility to be mature today and 5 years from now? Respondents gave low and high scores for each dimension, and after a brief discussion, we recorded an average score across the group. The scores varied for good reasons and were dependent on the role of each utility executive, the current adoption rate for DER in their jurisdictions, and whether or not their companies were already offering DER programs and solutions in regulated or non-regulated business units.

We then asked a second question, again for each dimension: How mature is your utility today, and how mature should it be in 5 years? This resulted in a rich dialogue for each score, and afterwards we tallied average results accordingly. For example, some utilities have an active DER business unit already focused on customer product and service offerings. Naturally, their scores suggested greater importance regarding readiness and importance for Customers & Programs.

The results often reflected wide variations across different utilities, as well as divergence from different stakeholders within the same utility. Summary results are outlined in the two tables that follow.





 Source: Navigant analysis

Operations (e.g., organization and processes) scored the highest in terms of importance to utilities today and 5 years from now for a fully mature iDER company. However, this dimension had one of the lowest readiness scores from the group, setting it up as an area with considerable gaps to fill over the next 5 years. Some of the reasons cited for this lag include the lack of a robust telecommunications network for high-speed connectivity to DER devices on the far edges of the grid, as well as limited ability to handle high volumes of data and provide sufficient analytics in the middle and back office. There was also mention of softer elements, such as the right cultural mindset and ability to hire talent that fully understands and embraces new digital applications and advanced customer analytics.

Furthermore, the utilities generally felt that their Business Models were not ready today but would be the most important area for readiness 5 years from now, suggesting that considerable work needs to be done along this dimension. On another level, the utilities felt that Regulation & Policy was highly important for iDER maturity and that they were further along today in this dimension. Some of the representatives in the room were from states where these regulatory constructs are well underway, including New York (i.e., REV proceedings). Others were in areas of the Midwest, where traditional, vertically integrated market structures are not expected to change in the near future.

Finally, we noticed variations in scores from representatives within the same utility. This implies that maturity model scoring needs to take place across multiple functions within a utility in order to inform an overall strategic approach. Navigant is applying this model with a number of initial utilities and will be publishing a white paper showing where the industry currently is and benchmarking against Navigant’s vision of a fully DER-integrated utility. Through this effort, we will present an industrywide view on the state of utility readiness for DER integration, as well as the top priority areas for utilities in readying their organizations to serve as a useful basis for utility strategy, planning, and resource allocation efforts as this industry transformation takes place.


New Cummins and Tangent Joint Venture Enters the Heart of the Energy Cloud

— November 14, 2016

PipelineA joint venture has entered the Energy Cloud, pioneering new value propositions for stakeholders across the energy value chain. Dubbed edgeGEN, this offering allows energy retailers and commercial and industrial (C&I) facilities to capitalize on real-time economic opportunities on the grid.

edgeGEN consists of Cummins’ natural gas generator sets (gensets) equipped with Tangent Energy’s Tangent AMP distributed energy resource management system (DERMS). The system’s key focus is predicting (and reacting to) customer coincident peak demand, a rare occurrence that can nonetheless represent a significant portion of an electric bill. By focusing on these high-value instances, edgeGEN has the potential to provide high economic value to the grid with a small amount of fuel.

The business case for the product includes value propositions on both sides of the meter. Municipal utilities and energy retailers, the exclusive channel partners for the offering, save costs by incentivizing customers toward desired behavior like cutting demand during peak hours. C&I customers can be rewarded monetarily while in some cases also realizing the benefits of resilient power to ride through outages. Bringing it all together is a financing structure that typically requires no money down from the host facility.

Established Technology in a New Skin

Gensets remain the de facto backbone of many onsite generation systems for several reasons. They are dispatchable quickly any time of day, can have the cheapest levelized cost of energy of any distributed generation (DG) source, and can reliably deliver 1,000 times or more annual energy per square meter than solar PV. They account for 40% of the average microgrid generation capacity in Navigant Research’s Microgrid Deployment Trackermore than any other technology.

Though some argue that the dramatic cost declines in developing technologies like solar plus storage will lead to the displacement of gensets, we see this convergence as a key opportunity. As intermittent renewables grow, there will be increasing demand for fast-ramping gas generation, as noted in recent reports about California by the National Renewable Energy Laboratory (NREL) and the Union of Concerned Scientists. Additionally, according to a report funded by the German government, distributed natural gas generation must play a growing role in thermal energy storage. Both on- and off-grid, growing access to cheap natural gas is only accelerating this trend.

Offerings like edgeGEN have room to grow. Other DER and demand response can be integrated on the same platform, one that has flexibility to evolve alongside the coming growth in transactive energy. Municipal utilities and energy retailers, especially in areas with high capacity and transmission tags, should consider the value of incorporating smart gensets and complementary DER. Facility owners should consider the offering while also considering the true value of resilient power as a potential bonus. With growing renewables penetration, persistently cheap natural gas, and regulatory bodies recognizing the value of dispatchable DG, the opportunities in this space are promising.


What to Consider When Evaluating Networking Solutions

— November 4, 2016

Ethernet CablesAs the electric utility business evolves toward a bidirectional, multi-faceted model (i.e., the Energy Cloud), utilities’ need for robust, future-proof communications networks is paramount—but decision-making can seem fraught with risk. The wrong choice can quickly become a limiting factor as management teams explore new applications at the grid edge. But as distributed generation proliferates and overall energy usage falls, the need for that visibility will only become more critical—to customer engagement, demand-side management, transactional energy, load management, asset management, and more.

Traditionally, utilities have preferred to purchase their networking infrastructure, making large capital investments that they can put into their rate cases. Regulators have generally shown a strong preference for the lowest (upfront) cost approach.

Increasingly, however, utilities are evaluating the total cost of ownership (TCO) for various solutions. So where Solution A may be the most attractive in terms of initial costs, over the 10/15/20-year lifecycle of the network, Solution A may actually be more expensive—or worse, it may not be robust enough to support emerging applications.

Recently, Navigant Research was commissioned to do a TCO analysis comparing private spectrum options for utilities with other more popular networking technologies, including unlicensed radio frequency (RF) mesh technologies, existing point-to-multipoint technologies like that of Sensus, public cellular, power line carrier (PLC) technologies, and others.

As it turns out, the TCO for each of these can vary widely. The rural, low-density nature of cooperatives makes for a very different economic model than that of a municipal utility or a large investor-owned utility (IOU). The results of our analysis can be seen in the table below.

Total Cost of Ownership for Various Utility Networking Scenarios: 15-Year Time Horizon

TCO Study

(Source: Navigant Research)

 Is My Existing Network Adequate?

Advanced metering infrastructure (AMI) systems are now operated at utilities serving half of all United States meters. Many utilities will try to leverage those existing networks for distribution automation (DA) or other advanced applications. In some cases, this may be a cost-effective approach. In other cases, however, ongoing maintenance costs and denser equipment requirements will result in high costs over time. Repeater creep—where utilities must continuously add repeaters to a mesh network in order to accommodate growing capacity needs—is a potentially expensive outcome when existing AMI networks are tapped for newer DA functions like Volt/VAR control; fault location, isolation, and restoration (FLISR); or demand response.

Historically, utilities have not been fond of purchasing private spectrum, primarily due to costs, which public cellular service providers have driven higher as their bandwidth needs grow (thank YouTube on your phone for that). More recently, however, there are some private bands available to utilities that may provide a cost-effective solution. Our TCO analysis considered the 700 MHz A-band licenses, which are available today across much of the United States for a relatively modest price/MHz POP (population unit).

Private spectrum ownership is now an affordable option—in some cases, the most affordable option—for a utility looking to deploy a variety of DA use cases across a large or varied territory. When used for a combination of AMI, DA, and even substation connectivity needs, the control and flexibility that private spectrum offers can be very attractive.

For further information on the Navigant Research Total Cost of Ownership Analysis, contact Richelle Elberg. For further information on the regional availability of licensed spectrum, contact Robert Finch at Select Spectrum.


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