What is Transactive Energy and Why is it Important to Microgrids?

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The growing emphasis on using microgrids to generate revenue is leading to increased discussion of transactive energy, a concept described in a new paper by Monash University researchers and featured at the recent Microgrid Knowledge Virtual Conference.

transactive energy

Monash University New Horizons research facility. Photo by Nils Versemann/Shutterstock

The Monash paper, “Transactive Energy Market for Energy Management in Microgrids: The Monash Microgrid Case Study,” offers by way of example a microgrid being developed at the Australian university consisting of 20 buildings — a load of 3.5 MW — plus 1 MW of solar, a 1 MWh battery and two electric vehicle chargers.

Located on the university’s Clayton campus, the microgrid will receive and store energy from numerous renewable energy sources.

The university, Australia’s largest, also has proposed creating a Microgrid Electricity Market Operator, a third party entity that would coordinate distributed energy resources (DER) and interface with the wholesale electricity market and the ancillary services market. DER owners participating in the market would be compensated for providing grid services, such as frequency and voltage control.

Defining transactive energy

A microgrid market operator would help enable transactive energy — “the ability to control the electrical grid, the flow of power in the electrical grid using economic or market-based constructs,” as defined by Kay Aikin, CEO and co-founder of Dynamic Grid, an affiliate of Introspective Systems. Aikin spoke at the Microgrid Knowledge virtual conference June 3 in the session, “How Microgrids Make Money.”

In their paper, Monash University researchers say transactive energy encourages “dynamic demand-side energy activities based on economic incentives and ensures that the economic signals are in line with operational goals to ensure system reliability.”

The paper noted that transactive energy benefits both DER operators and the central grid. DER operators are able to tap into new revenue streams by selling services to the grid; the grid gains greater stablization from the services.

Aikin also said that employing transactive energy helps with two major challenges to microgrid development: capital and operating costs.

“One way we can actually make microgrids lower their operations cost and increase value streams is use this idea of transactive energy, and that is making loads integrate into the microgrid and actually contribute to the operation of the grid,” she said.

Creating pricing signals is an important part of this process, the Monash University researchers said.

Monash University plan

Monash University’s plan is to integrate distributed energy resources and actively manage them, predicting their demand and flexibility. Customers will be rewarded for providing services.

The university microgrid will be capable of controlling when and how to use its energy, and that can lower demand and strain during peak periods. It will also help stabilize the grid by providing resilience that will benefit the larger community, especially during severe weather.

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The project will examine a number of scenarios, including peak demand events. The electricity retailer might ask the university to decrease load in return for financial incentives, creating a market event. In this scenario, potential flexible resources would be identified — distributed energy resources such as electric vehiecles, solar and storage. They could reduce their demand or provide resources for the grid. After an event, the microgrid operator would log transactions for billing purposes.

Microgrid assets will be monitored in real time, which will help provide efficient and reliable supply. With a transactive market in place, each building will be able to buy and sell electricity, and also respond to pricing signals.

The university engaged AZZO, an Australia-based company, to build a medium voltage SCADA distribution management system and power quality monitoring solution for the three medium voltage rings on the Clayton campus in preparation for the microgrid automation. AZZO deploys EcoStruxure products by Schneider Electric for metering, monitoring and control of electrical distribution systems, microgrids, utility scale solar photovolatics and battery energy storage systems.

Smart buildings plus microgrids

In her presentation, Aikin cited a possible scenario in which a university with a microgrid on campus might include solar and storage. Numerous buildings within the microgrid would work together to balance the microgrid. The microgrid would sell services to the larger grid. The microgrid would balance variable generation — from solar energy, for example — and provide peak load reduction. In doing so, it could decrease costs for the entire grid

“Smart buildings integrated with microgrids provide advantages to the entire system,” she said. “You can provide multiple services to both the building owner and also to the microgrid operator.”

In this example, balancing the microgrid would require load — such as appliances and heat pumps — to provide flexibility by reducing or increasing energy use as needed. Benefits would be shared among all the microgrid users.

To balance the microgrid when power availability from the main grid is dropping — on a cloudy day, for example — the building owners would lower consumption, and more energy from the battery would be used. On sunny days, when power is available from solar, the buildings would consume more energy, providing balance by using available solar that might otherwise be wasted, Aikin said.


By Introspective Systems, for “How Microgrids Make Money,” Microgrid Knowledge Virtual Conference

“The idea of transactive energy is when power is scarce, for instance, there’s a cloudy day, consumption will go down and production will go up from the battery,” said Aikin. “And when power is abundant and you have a very sunny day, consumption will actually go up to help balance the grid, and production will go down.”

Under this scenario, the buildings inside a campus are each their own value center. The buildings could supply services to the microgrid so the microgrid could provide expanded services to the outside grid.

The buildings might have heat pumps, for example, that help contribute to this balancing act. The heat pumps would reduce their demand when power availability is low and use grid power when power availability is high.

“In this case, the buildings that have the heat pumps are receiving value for services they’re providing and helping to balance the grid using power when it’s very abundant, and when power is not abundant, they lower their loads. So they provide value to the grid,” Aikin said.

Overall, using transactive energy, microgrids can yield more value and income by working along both sides of the “fence,” she said. They provide services to consumers at the lower end of the grid, and benefits to the larger grid.

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  1. Victor Saade says:

    Hi Lisa, thank you for this article.

    I would like to raise questions about your definition of a microgrid. Per the industry standard, a microgrid is an integrated energy system consisting of interconnected loads and energy resources which, as an integrated system, can island from the local utility grid and function as a standalone system.

    The last part about islanding from the grid is crucial to differentiate a microgrid from a standard on-grid DER system. With 3.5MW of load, 1MW solar, 1MWh (probably 500kW) of storage and no generator, we can not consider this a microgrid. Rather, what you are describing is a distributed energy system providing grid services and leveraging market prices for economical purposes.

    Looking forward to hearing your opinion on this.


  2. Fred Fastiggi says:

    Lisa – This is an interesting article on ways to enhance the revenue and profitability of Distributed Energy Resources (demand or supply side resources) however I would caution becoming too dependent on these new revenue streams as a justification for future investment in these assets. There are a couple of concerns that merit close consideration and at this point basing investment decisions on evolving programs with an undefined life-cycle may be problematic.

    Making Projections based on Limited History – Several of the programs which have historically been suggested as options for enhancing distributed energy resources have a very short operating history. Promoters of these programs as a way to squeeze more revenue from assets often look at this limited pricing history, in some cases as few as two or three years, and use it as a basis for projecting future pricing as much as twenty years into the future. The limited number of data points in current history, are not substantial enough to make statistically valid forecasts on future pricing.

    Additionally, it should be considered that most of the cited revenue enhancement programs for DER were specifically designed to address and remedy issues (generation and transmission shortfalls) that existed at a point in time (e.g.: polar vortex effect within PJM’s area). As potential suppliers of generation or transmission consider participation in these programs, they will presumably weigh the attractiveness of attainable pricing versus their costs to provide the assets which address program needs. This is especially true for potential investors in incremental or new capacity. The pricing reflected in current history (short though it is) indicates that the programs have been attractive enough for investors to make capital commitments for new or idle assets that satisfy the needs of the programs. However, given the laws of supply and demand, logic would suggest that as capacity is continually added to the market driven by attractive program pricing, the demands on the system which produced the need for these remedial programs, will reach equilibrium with supply, at which point prices for the various programs will level off and/or decline.

    If one believes that this “supply and demand “outcome is likely, it is quite possible that the pricing we have seen recently for these programs in their early evolution when the largest discrepancies in supply versus demand were experienced (which several promoters have suggested as baseline starting points for their analysis), are the best prices that will ever be seen over the life of these programs.

    Escalation in pricing – Further distorting this analysis, is the approach with price escalation. Historically-based pricing whose shortfalls have been discussed are often steadily escalated over the course of many years at fixed escalation rates, to arrive at cash flow and return on investment indicators. As previously discussed, a valid argument can be made that the base year pricing is perhaps as good as it is going to get due to evolving supply and demand factors. To assume that pricing will increase, albeit only by 2 or 3% per year, over the life of the investment, is misleading. It is much more likely that pricing for these programs will either taper off and decline, or fluctuate up and down from year to year, rather than escalate at a fixed rate of 2 or 3%. While there is ample history to make assumptions that a 2 or 3% escalation is valid for appropriate costs and expenses such as operations, maintenance, administration, insurance and perhaps even fuel, there is no history, or logic that would support making the same type of escalation assumptions for pricing offered by many of the suggested approaches.

    Extrapolation of Current Regulatory Scenarios – Related to the escalation concerns can be the assumption made on the life of the programs that generate revenue from the distributed generating assets. Assuming revenue programs current in place, will continue to be in place for a period of twenty (20) years or more may be optimistic. Consideration should be given as to whether the situation which caused the development and implementation of these programs is likely to be representative of the future environment and market conditions. Many of these programs are based on market conditions of the recent past which negatively affected the availability of generation or transmission capacity. If the programs work as designed, they should for example, relieve capacity constraints which calls into question whether the programs will be needed in the future. The trend towards “strategic electrification” will continue, increasing the need for both generation and transmission capacity however at some point the increasing demand for electricity will stabilize as will the capacity that serves that demand or provides ancillary services. This will reduce the need for programs in the northeastern US which I am familiar with such as ICAP, NITS, Demand Reduction and Synchronous Reserve. A reasonable question when making investment decisions is whether this level of supply and demand equilibrium will be achieved over a period of twenty years, ten years, five years or some other time frame.

  3. Adoption is key to being able to bring down energy storage costs by the “economies of scale” practice. The problem today is the unknown. The rote electric utilities will not invest in energy storage until someone “else” proves its worth on their dime and their time. In Australia the TESLA energy storage system installed across the Neoen wind farm in 2017 has already paid for itself in stacked grid services and it’s only been about 3 years. Now I understand this energy storage project has been “vetted” and enhanced to 150MW/193.5MWh. This site will not be “proven” until it is online until at least 2027 to prove the 10 year longevity claim. The only long term use of energy storage over the long term is Japan’s use of NaS batteries that have been used for about 20 years. There is a body of evidence being gathered that is showing long term predictions of energy storage technology can be very cost effective over decades of use.

    Technologies like LAES, (liquid Air Energy Storage) or very large redox flow batteries have not been built and used, although the redox battery industry says their product is a 20 year in use product. As redox is modular, one can increase the energy density by adding ion tanks or replacing small tanks with large tanks. Redox flow batteries can be rebuilt, repaired and refurbished in perpetuity for decades. What IS needed is better analytics and grid modelling to insure assets are installed where they get the most “bang for the buck”. Very large redox flow battery storage may be more applicable to the HVAC grid energy storage in multiple GW of energy storage on the regional level. At the local level some sort of lithium ion energy storage at switching stations to allow fast reacting grid smoothing like frequency and voltage, arbitrage services to the grid.

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