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By Peter Asmus
March 15, 2023

Once viewed as an isolated market with limited lessons to offer global markets, Australia has emerged as a leading voice in articulating how best to accelerate the transition to a net zero energy economy. And while strong differences separate Australia from ����ӰƬ, the two jurisdictions share a lot when it comes to the provisions of vital electricity services to remote and isolated communities.

When I engaged on my first report on the global microgrid market in 2009, much of the available data on the types of resources deployed in microgrids came from ����ӰƬ and Australia. The source of this data was the Commonwealth Scientific and Industrial Research Organization (), an R&D lab that has long been involved in developing cutting-edge solutions to energy challenges. Since then data provided by the ����ӰƬ Center for Energy and Power (ACEP) shows that ����ӰƬ has more microgrid capacity installed today than any other US state. An estimate provided by Guidehouse Insights showed ����ӰƬ with close to 3,000 MW compared to Australia’s 1,300 MW of microgrids that include some portion of renewable energy and/or energy storage. Australia does include some regional grids in the west that could be considered microgrids, but were not included in the Guidehouse tally.

Likewise, Australia is a market leader in remote microgrids in the Asia-Pacific, particularly on the western side of the country which, like ����ӰƬ, lacks traditional grid infrastructure that is common throughout industrialized markets such as the US and Europe. Knowledge sharing between ����ӰƬ and Australia to resolve common integration challenges for increasing amounts of renewable energy with isolated power systems that traditionally featured diesel generators has been ongoing. Both regions initially focused on wind and diesel hybrid power systems, but today are turning to solar photovoltaics (PV) and new kinds of battery storage to enable the transition to a lower carbon energy system.

Despite these similarities between ����ӰƬ and Australia, there are also some major differences. These differences go beyond climate, with ����ӰƬ’s ongoing operational challenges for its remote microgrids focused on cold-weather impacts on technology choices and operational constraints. In contrast, Australia has to deal with extreme hot weather impacts.

The primary focus of this blog is on distinctions between ����ӰƬ and Australia where traditional transmission infrastructure is already in place. Rather than technology, the innovation that Australia can teach ����ӰƬ revolves around market reforms to better integrate distributed energy resources (DERs). Rather than viewing these DERs as problems, new market structures can transform them into solutions for grid reliability.

The other area where Australia leads is in the push for hydrogen as a decarbonization linchpin. Where ����ӰƬ is currently exploring its options with regards to hydrogen, Australia is already moving forward with several major initiatives. Such initiatives in ����ӰƬ would allow the state to leverage the strong presence of the oil and gas industry and enable them to become players in the current energy transition.

The New Australian Energy Landscape

A report by CSIRO forecasts that by 2050 almost 2/3 of all customers in Australia will feature some form of distributed energy resources (DER).¹ Once a country whose primary contribution to energy innovation was the build out of remote microgrids in its western states and territories, Australia is now a hotspot for grid connected virtual power plants () in the southeast. The deregulation of energy markets there has accelerated reforms that now make VPPs – the temporary aggregation and optimization of diverse DERs including residential and commercial and industrial (C&I) loads – a virtual necessity for intelligent grid management. Consider the following:

• Australian consumers boast one of the highest per capita electricity consumption rates in the world. These consumption levels translate into flexible load that can serve as the basis for demand response () programs and, ultimately, VPPs.
• Australia also lays claim to having the highest per capita rooftop solar PV penetrations in the world. Adoption is expected to accelerate over time (see chart below). Curtailment of solar production is a related challenge with companies such as seeking solutions.
• Like US markets in New Mexico, California, Colorado and Oregon, Australia has also been wracked by wildfires and corresponding power outages, building the business case for grid- connected microgrids too.
• As coal plants are retired and replaced by large-scale solar and wind farms, the Australian Energy Market Operator (AEMO) requires greater visibility into the assets used to balance the grid and integration of behind-the-meter with front-of-the-meter assets to maintain grid reliability.

Rooftop Solar PV and Battery Storage Adoption, Australia: 2015-2050

In October of 2021, AEMO, which runs Australia’s National Energy Market (NEM) and serves the densely populated southern and eastern grid-connected portions of the country, instituted a market reform that changed the rules to shorten settlement periods for energy trades from 30 minutes to just five minutes. The NEM market represents 80% of Australia’s total energy consumption. Commencing operations in 1998, the NEM market supplies approximately 9 million customers with over 54 gigawatts GW of generating capacity. Over 300 buyers of electricity post more than $16 billion in trading every year.

The five-minute market results in a hyper competitive bidding process that sets the stage for deregulated energy retailers and other market participants to fully embrace the VPP market optimization opportunity. The NEM market (see diagram below) is an energy only market lacking a capacity or day ahead market, so trading activity can be frenzied. Bidders can sell into six frequency services market products as well as eight other grid service markets. There are almost 20 different ways a battery can be allocated with compensation spanning almost a dozen different pricing bands.

Australia’s National Energy Market Footprint

In Australia, however, the VPP use case that has risen to the top of the agenda for energy retailers is frequency regulation, especially in South Australia and New South Wales.² A report released by Cornwall Insight Australia claims that the majority of utility scale battery assets currently operating in the NEM derive 75-80% of their market revenue from supplying Frequency Control Ancillary Services (FCAS.) The study shows that the location of batteries really does matter.

While FCAS figures to be a market revenue bonanza throughout NEM, South Australia is particularly attractive for a couple of reasons. Despite having a portfolio of large-scale batteries, the region has a significant shortfall in regional suppliers of FCAS due to the proliferation of both behind the meter and in front of the meter variable renewables and corresponding lack of spinning synchronous generation typically used to bolster grid reliability.

Decarbonizing ����ӰƬ’s Railbelt Transmission System

Like Australia, ����ӰƬ does not have an interconnected electric grid network covering the state such as the lower 48 or Europe. Instead, ����ӰƬn communities are all served by some form of a microgrid, some of which are then interconnected via a transmission network to form larger regional grids. The largest of these regional grids is called the Railbelt grid. It is called the “Railbelt Grid” because it runs along the general route of ����ӰƬ’s Railroad. It extends for over 600 miles and links three distinct service areas that are each capable of islanding via a transmission backbone, including (from north to south): the greater Fairbanks area, the Matanuska-Susitna Valley and Anchorage metropolitan area, and the Kenai Peninsula.

����ӰƬ’s Railbelt Grid system evolved from some of the first utility companies in ����ӰƬ. Over time, utility companies - many of them cooperatives - served the most basic needs for electricity and energy throughout ����ӰƬ. As these cooperatives grew, they started to bump into each other, and borders were created to distinguish the control area each utility covered. The six electric utilities along the Railbelt Grid do interconnect with each other but maintain their independence with their own generation sources.

The Railbelt Grid operates on 75% natural gas, 10% hydropower, and the rest coal power. From one perspective, ����ӰƬ has a relatively clean grid, since natural gas produces less air pollutants, chiefly CO2, than both coal and oil. But natural gas is still not a totally “clean” energy source as it is not renewable. Ironically, the carbon footprint of the Railbelt Grid is much larger than that of many remote microgrids that have transitioned away from a sole reliance upon diesel to integrate hydro, wind and solar resources, among them utilities serving , and .

In addition, the Railbelt Grid, which represents approximately 2,000 MW of total peak generating capacity, is comprised of nested microgrids such as the University of ����ӰƬ Fairbanks campus and several military bases. These microgrids bump up against each other but interaction is limited as there is no independent system operator for the transmission system. While resilient, these microgrids are hampered by the lack of interactive DR that could lead to more efficient operations. A lack of transparency on supply and demand across the grid also limits the kind of real-time system wide optimization of DERs and other resources that is taking place today in NEM, which is much larger in size both geographically and in terms of peak demand of over 35,600 MW.

As noted in a last year, ACEP developed three different scenarios to decarbonize the Railbelt Grid, which are summed up briefly below:

Scenario 1: This scenario is built on decentralized, customer-driven decarbonization and the maximum plausible use of aggregated DERs and requires greater integration between today’s existing microgrids.

Scenario 2: This scenario aims to provide electricity through utility-scale carbon-free energy resources such as hydro, wind, solar, geothermal, tidal, biomass, and perhaps nuclear and relies upon carbon capture and sequestration (CCS) to remove any residual carbon emissions.

Scenario 3: The third scenario for Railbelt decarbonization relies on a large-scale export project revolving around large-scale hydrogen production to take advantage of ����ӰƬ’s position on world shipping routes to export low-carbon fuel constituents for Pacific marine transportation and energy production in the Asian markets.

Phase 1 of the analysis is nearing completion. Future work on decarbonization will likely examine a blend of all three of these scenarios, but the scope of the Phase 2 analysis has not yet been decided upon.

Today’s Contrasts Between ����ӰƬ and Australia Underscore Role of Regulatory Reforms

Most microgrids in ����ӰƬ are operated by local utilities, with over 100 certificated utilities active in the state. The non-integrated nature of ����ӰƬ’s electric infrastructure permits this large number of certificated utilities to serve such small populations. Cooperative utilities are the predominant model in ����ӰƬ, but municipal and private utilities also have a significant footprint. The cooperative model has been particularly effective in aligning customer needs and desires with utility programs to increase renewable energy portfolios.

In contrast to this decentralized utility-led approach, consider the regulatory environment of Australia. Horizon Power, which serves Western Australia, boasts the largest utility service territory in the world: five times the size of California. Its other claim to fame is that it has the lowest customer per square kilometer ratio of any utility service territory (one for every 53.5 km²;). Given how sparse its customer base is, Horizon Power is currently disconnecting some isolated customers from its grid networks and instead supplying them with standalone power systems. All told, Horizon Power serves only 47,000 customers.

Many of the microgrids that Horizon Power operates historically relied on a centralized diesel generation power system. Horizon Power’s poster child for more advanced microgrids integrating DERs and renewables is a microgrid serving the coastal town of Onslow with a population of 850. Integrated into this microgrid are DERs owned by customers, reflecting disaggregated ownership trends that are sweeping through global markets. Before recent upgrades, the microgrid was designed to meet a 4 MW peak load with an 8 MW natural gas generator, 1 MW diesel generators and a 1 MW lead acid battery.

Today, the microgrid includes the following resources:

• 1 MW utility-owned solar PV array with two 1 MWh batteries connected at the utility substation
• 260 customer owned solar PV installations, representing over half of the microgrid’s customers, totaling 2.1 MW of clean energy capacity
• 500 kWh of customer-owned distributed battery systems
• Plans to add another 200 kW of customer-owned DER assets in the future

This mix of both utility-owned and customer-owned assets can serve as a model for the Railbelt Grid microgrids. Since these ����ӰƬ grid-connected microgrids have the theoretical capability of sharing resources across microgrid boundaries, the key barrier to decarbonization for the Railbelt is less about technology choices – though those will clearly play a role - and more about regulatory reforms.

For example, the only way a significant reliance upon DERs would be viable in the Railbelt Grid would be to restructure the market allowing for dynamic pricing, a common carrier model for transmission access and the ability to access resources across the entire grid to balance overall supply in the most cost effective manner possible. Though a five-minute market settlement structure might not make sense for the Railbelt Grid, a dynamic trading regime of some sort is one of the primary lessons ����ӰƬ regulators and utilities could learn from Australia. The same jurisdiction can accommodate both remote microgrids managed by utilities as well as a deregulated energy market that leverages the economic efficiency of new retailers, aggregators and other market players infusing power grids with new dynamic sustainable energy solutions.

Translating the Hype on Hydrogen into Commercial Reality

Both ����ӰƬ and Australia are investigating what role hydrogen might play in the larger decarbonization play in the coming decades. ����ӰƬ’s forays to date have largely been conceptual and are focused on piggy-backing on the extensive oil and natural gas development that has made ����ӰƬ famous worldwide in the past. Australia also shares a history of extractive industries with ����ӰƬ but is moving much more rapidly with renewable energy-based hydrogen projects with four major large scale projects already underway. Here is a brief description of these four mega-projects:

• . This project dates back to 2014. It has undergone significant revisions along the way. With BP in the lead, the project also includes and . The ambitious project would be supported by 26 GW of combined wind and solar capacity, an amount of clean energy equal to roughly a third of Australia’s total electricity generation in 2020. That amount of new renewable capacity would create 1.6 million tons of hydrogen (or 9 million tons of green ammonia.) The project could reduce Australia’s carbon footprint by 17 million tons annually.
• . This project also includes both CWP Global and Intercontinental Energy, but this time the third partner is , a group representing local indigenous peoples. The project is projected to generate 50 GW of new solar and wind capacity, enough renewable energy to create 3.5 million tons of green hydrogen.
• . This project involves another global oil company – Total of France’s independent power producer arm – and partners and . It is already under development and its size was increased from 1 to 8 GW of wind and solar capacity. It is estimated that it can produce 550,000 tons of green hydrogen annually upon completion, with phase 1 representing 4 GW of clean energy capacity. The project leverages existing pipelines and is viewed primarily as an export opportunity to decarbonize the Asia Pacific region.
• . The fourth large-scale green hydrogen project being co-developed by Intercontinental Energy is this project, which was started in 2018 and is based on development of 25 GW of renewable energy netting 1.8 million tons of green hydrogen. In January 2023, Shell, another global oil company giant, joined this project, the third major oil company to be involved with hydrogen development in Australia., a state-owned Kuwait enterprise, is also a project partner.

With four major large-scale hydrogen projects involving three of the world’s largest oil companies moving forward, one could make the argument that Australia is currently the leading country in the world in committing to a hydrogen future. How does ����ӰƬ stack up?

The short answer is there is no comparison. Nevertheless, ����ӰƬ does seem to represent the best hope in the U.S. for large scale hydrogen production hubs. The Bipartisan Infrastructure Bill of 2021 also provided the seed funding for 6 to 10 hydrogen hubs in the U.S., investing $8 billion over five years. The ����ӰƬ Gasline Development Corporation (AGDC), working with ACEP and other partners, has submitted a proposal to the federal Department of Energy to develop such a hub. Among the criteria for DOE funding is the ability to produce 50 to 100 tons of clean hydrogen daily. Grants can reach as high as $1 billion for a single project.

Why is ����ӰƬ poised to take the lead on hydrogen for the U.S.? Unlike Australia, ����ӰƬ could tap the enormous existing natural gas reserves in the state that have already been developed at a world-class scale. To meet the decarbonization metrics, ����ӰƬ also has significant potential for carbon sequestration. Along with enormous fossil fuel reserves, the state has potential for significant renewable energy development, including newer options such as tidal resources - ����ӰƬ has the best tidal resources in the U.S.

Perhaps the most important factor for hydrogen in ����ӰƬ is the availability of private sector funding to make these projects commercially viable. ����ӰƬ’s North Slope is North America’s largest untapped source of natural gas. Converting to hydrogen (along with liquified natural gas exports) is the best way to tap this resource without unduly accelerating global climate change. Cook Inlet in south central ����ӰƬ has the potential to sequester 50 gigatons of carbon in underground geologic formations. A project to do exactly that has been proposed but it is far from simple. The diagram below showcases the complexity and integration of several technologies and market players for this vision to become reality, including the integration of a decommissioned ammonia plant.

DOE ����ӰƬ Hydrogen Hub Proposal: Multiple Players; Multiple Products

Conclusion

Both ����ӰƬ and Australia share much in common, especially when it comes to a reliance upon microgrids to serve isolated communities. But when it comes to market reforms for the respective regions connected to traditional transmission infrastructure, they couldn’t be more different. ����ӰƬ’s Railbelt Grid wins high marks for the resiliency nested microgrids can provide, but lacks the ability to leverage demand response and other tools to shrink reliance upon fossil fuels. The lack of a dynamic market structure and common carrier model for transmission access may need to be revisited if ����ӰƬ is to find the most cost effective way to reduce climate change risk.

The hyper-dynamic market structure of Australia probably would not work in ����ӰƬ as utilities still remain in the driver’s seat when it comes to ownership and control, but the current system is inefficient and does not take advantage of major advances in control technologies that render past assumptions on grid balancing obsolete.

In terms of future technologies such as hydrogen, Australia is also far out in the lead. Yet ����ӰƬ could be positioned to lead the U.S. on hydrogen development. As the world transitions away from carbon fuels, industry stakeholders in ����ӰƬ have an opportunity to reinvent themselves. By transforming the state’s oil and gas industries towards hydrogen development, they can pave the way for large-scale infrastructure that creates significant economic benefits for ����ӰƬ while contributing to the clean energy transition in the most creative and cost-effective way possible.

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¹ Energy Networks Australia and CSIRO, Electricity Network Transformation Roadmap: .

² PV Magazine: .