Navigant Research Blog

Energy Cloud 2.0: Orchestrating Power Networks via Virtual Power Plants

— August 30, 2016

AnalyticsThe evolution of energy markets is accelerating in the direction of a greater reliance upon distributed energy resources (DER), whether those resources generate, consume, or store electricity. The new frameworks necessary to manage this increasing two-way complexity are quickly evolving. Nevertheless, strategies are being deployed today all over the globe.

One such strategy is a virtual power plant (VPP), the concept that intelligent aggregation of DER can provide the same essential services as a traditional 24/7 centralized power plant. The definition of a VPP is fuzzy. In short, it is based on the idea that the value of DER must not only provide value to the prosumer, but must also be enabled (through technology and regulation) in order to migrate value upstream to utilities and even transmission grid operators. In other words, they need to rely upon a network orchestrator, a concept that is articulated in a new white paper entitled Navigating the Energy Transformation.

Gaining Acceptance

Navigant Research published its first VPP report in 2010. Since that time, what was once seen as a futuristic scenario fed by a number of experimental pilot projects in Germany, Denmark, and the rest of Europe is emerging into a real market that draws upon analogies with companies such as Uber. The network orchestrator driving value for the VPP may not own all of the assets; value is created by organizing these assets in a way that creates real-time physical benefits to the power grid (or in the case of Uber, to people seeking near-immediate transportation services).

VPPs represent an Internet of Things (IoT) approach to energy management, tapping existing grid networks to tailor electricity supply and demand services for a customer, utility, or grid operator. VPPs maximize value for both the end user/asset owner and the distribution utility through software and IT innovations. The primary goal of a VPP is to achieve the greatest possible profit (or savings) for asset owners, while at the same time maintaining the proper balance of the electricity grid at the lowest possible economic and environmental cost. From the outside, the VPP looks like a single power production facility that publishes one schedule of operation and can be optimized from a single remote site. From the inside, the VPP can combine a rich diversity of independent resources into a network via sophisticated planning, scheduling, and bidding of DER-based services.

A Transforming Field

Perhaps the most transformative example of a VPP is the aggregating up of residential rooftop solar PV systems with distributed energy storage, which can then deliver dispatchable demand response (DR) services to utilities. A great example of this VPP model comes from the Sacramento Municipal Utility District.

Navigant’s recently released white paper concludes that roughly $10 trillion can be attributed to the digital innovations necessary to integrate renewables, which will represent the vast majority of new power supplies supporting the grid by 2030. A report to be published this September will carve out how large the VPP market is expected to be over the next decade. Regardless of the precise figures included in these forecasts, revenue across the electricity value chain is shifting downstream toward the edge of the grid.

Without VPPs, this shift could result in chaos. With emerging business models such as VPPs, however, a balancing of the grid can occur that also balances costs and benefits, ideally in a way that serves a broad array of society’s stakeholders.

 

Are Drones About to Catch More Air Among Utilities?

— August 30, 2016

DroneDrones are on the verge of becoming a more commonly used tool by US utilities to improve operations and management of dispersed assets. The latest catalyst is the Federal Aviation Administration’s (FAA’s) new rule called Part 107, which went into effect on Aug. 29. Part 107 comes with some hurdles utility stakeholders need to be aware of, but there is a process that should prove helpful.

Essentially, Part 107 sets the rules for routine commercial use of drones, or small unmanned aircraft systems (sUAS), in the federal parlance. The aim of the rules is to open “pathways towards fully integrating” drones into the nation’s airspace, according to an FAA release. These rules apply to non-hobbyist drone operators who are flying drones weighing less than 55 pounds. The person flying such a commercial drone must be at least 16 years old and hold a remote pilot certificate with a rating for this type of drone, or be directly supervised by someone with such a certificate. A Transportation Safety Administration (TSA) security background check is also required of all commercial drone pilots before a certificate can be issued.

However, there are restrictions likely to frustrate utilities or third-party drone vendors who might contract with a utility to provide drone services. For example, a drone operator must maintain a visual line-of-sight with the drone; keep the drone below 400 feet; fly during the day; keep the drone’s speed below 100 mph; not fly over people; and not fly from a moving vehicle. The line-of-sight and daytime-only restrictions are likely the most onerous to utilities. However, there is a waiver process by which specific restrictions can be removed. That waiver process is supposed to be done within 90 days, but one could expect a backlog, particularly through the rest of 2016 and into next year, assuming there is a flood of waiver filings.

The rules make sense from a cautious regulatory standpoint, but have taken several years to emerge. The slow pace has the US commercial drone market among the laggards compared to other countries, and the US rules are seen as among the most stringent in the world. Nonetheless, the regulatory framework is taking shape, and utilities can make plans.

Beyond Cameras – Lidar

One of the obvious benefits of drones is the use of onboard cameras to inspect grid assets for damage and current condition assessments. But there is another non-camera advantage through the use of lidar technology, which employs laser light instead of radio waves to generate precise, 3D data that can create real-time virtual maps of areas—something quite useful for utilities and transmission and distribution operations. The expectation is that the use of lidar combined with thermal and visual data will pave the way for virtual reality (VR) applications. For instance, a transmission operator could remotely explore storm damage at sites or transmission circuit failures.

The upshot of this new rule is that drones are likely to go from experimental gadgets to important devices in the utility toolbox in the near term. The cost to send drones into the field to monitor remote transmission lines or substations is much less than sending a truck in numerous instances, and as with other new technology, there are likely some new applications not yet devised. For more details of how the drone market among utility stakeholders is likely to unfold, see Navigant Research’s report, Drones and Robotics for Utility Transmission and Distribution. It’s worth a test flight.

 

Distributed Energy Resources Hit the Auction Blocks in California and New York

— August 30, 2016

Cyber Security MonitoringAs we head into the fall fantasy football season, this summer has been good practice for those in the distributed energy resource (DER) world to value their portfolios and bid into auctions to provide their services. In both California and New York, utilities recently held auctions to procure DER to address electric grid needs. Although the outcomes are similar, the methodologies to get there were quite different.

First, California’s investor-owned utilities—Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDGE)—ran the second edition of the state’s Demand Response Auction Mechanism (DRAM). Since the California Independent System Operator (CAISO) does not have a capacity market, the California Public Utility Commission (CPUC) ordered the utilities to offer DRAM as a way to incentivize DER to provide similar product characteristics to capacity. In total, the utilities procured almost 82 MW, about 4 times the minimum requirement of 22 MW. However, a group of bidders is currently petitioning the CPUC, arguing that the utilities could have procured even more resources within their budgets.

New York took the spotlight in the form of Consolidated Edison’s (ConEd’s) Brooklyn Queens Demand Management (BQDM) auctions in July. Unlike DRAM, which is concentrated on statewide capacity issues, BQDM is a focused effort to relieve distribution constraints in a targeted area of high load growth. While final results are not yet public, initial information from ConEd states that 22 MW of resources were procured for 2018 from 10 bidders, with clearing prices ranging from $215/kW/year to $988/kW/year. These prices are much higher than ConEd’s existing demand response programs, which pay in the area of $90/kW/year, and the New York Independent System Operator’s (NYISO) capacity market, which offers around $130/kW/year in ConEd’s territory.

Different Mechanisms

There are some notable differences between the DRAM and BQDM mechanisms. First, DRAM has one product with a standard set of requirements that all bidders must meet and compete against. BQDM has two separate product types that bidders must choose to offer, one for the 4-8 p.m. time period and another for the 8 p.m.-12 a.m. period. These 4-hour blocks were created to allow energy storage devices with 4-hour charging capacities to participate.

Another major difference is the auction process itself. DRAM is a pay-as-you-bid format, where bidders submit their offers by a deadline and then the utilities review them and select the least-cost combination of bids, with each bidder receiving its submitted price. BQDM, on the other hand, is a live, descending clock auction, in which bidders log into an auction platform at a given time and can submit bids as prices are displayed. The price keeps decreasing until the auction reaches its desired number of megawatts. Then all remaining bidders receive that uniform clearing price, even if they would have bid lower than that price. The pay-as-you-bid versus uniform clearing price debate is a classic economic debate that has raged for years.

As usual, there are multiple paths that can achieve similar goals. Best practices and lessons learned will be observed with experience—but I doubt if California and New York will ever admit that the other did something better.

 

Meters Are Sensors and Sensors Are Meters—and It’s All IoT

— August 30, 2016

Power Line Test EquipmentOn August 11, Hazelwood, Missouri-based smart metering system vendor Aclara announced it acquired the smart grid business of Tollgrade, a provider of distribution grid sensors and software for monitoring and analytics. The deal comes just 8 months after Aclara acquired GE’s electric metering business, and all of this in the wake of its own sale to Sun Capital Partners in 2014.

It’s no surprise that Aclara is broadening its portfolio horizons. Upside potential for Aclara’s legacy technology—power line carrier (PLC) communications for smart meter data transfer—is on the wane. While still popular with low density utilities such as rural cooperatives, PLC isn’t as strong a platform for some of the newer smart grid applications that utilities want their advanced metering infrastructure (AMI) networks to support. Aclara has more than 14 million meters in the field and has been looking for growth opportunities since before its sale to Sun Capital.

Aclara has ventured into software, including solutions in the customer engagement and asset planning realms. It also offers several wireless communications solutions as an alternative to its enhanced Two-Way Automatic Communications System (eTWACS) PLC offering. These include cellular solutions and its Synergize RF point-to-multipoint system for utilities. But with the addition of GE’s meter business and now a leading line sensor/grid monitoring solution provider, Aclara has (or will have, presumably) a far more integrated set of products to offer. That means greater customer retainment.

The LightHouse product line also provides Aclara with an entry into the investor-owned utility (IOU) market where it has concentrated its efforts—Tollgrade has deployed its LightHouse system with DTE, Duke Energy, Toronto Hydro, and Western Power in the United Kingdom. In theory, Aclara can now better promote its various AMI solution sets to electric IOUs while marketing the LightHouse distribution monitoring solution to its sizable installed base of cooperatives and munis. Aclara historically has had a sizeable presence in the IOU marketplace with its gas and water AMI systems, with millions of endpoint systems deployed with customers in states including California and New York.

It’s All About the Smart

What makes a grid smart is the overlay of communications and software solutions that allow formerly manual controls to be automated. While Aclara was offering a piece of that smart equation with its legacy communications system, it now offers a broader array of solutions to smarten up not only the meters at the very edge of the grid, but also feeders throughout a distribution network.

The line sensor market hasn’t exactly taken the world by storm in the last few years, but it has shown promising traction more recently. Where the devices used to be expensive and analytics solutions (from which the return on sensor investments really come) were nascent, today’s costs are lower and the ways that real-time operational data can be used are growing exponentially. Navigant Research expects the global installed base of overhead line monitors to grow from a couple hundred thousand in 2016 to around 1.7 million by 2025.

Installed Base Overhead Line Monitors by Region, Worldwide: 2016-2025

Aclara Smart Meters

(Source: Navigant Research)

Generally, we don’t expect the overhead line monitor business to reach the same levels of penetration as, say, smart meters. They’ll be used on particularly troublesome feeders or where there are high levels of distributed solar wreaking havoc at the grid edge.

The Internet of Energy

What Aclara is doing by consolidating various sensors types—and a meter is just another sensor in the grid—into its product line is demonstrating its commitment to going beyond meter reading and boldly into the broader Internet of Things—or Energy—to make its platform more valuable and deepen its reach with utility decision makers. I wouldn’t be surprised to see more announcements from Aclara, perhaps related to software or analytics that leverage the underlying network and devices now incorporated in the company’s stable of products.

 

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