Australia, once considered a niche energy market, has risen to global prominence in leading the transition to a net-zero energy economy. While geographically and climatically distinct, Alaska and Australia share surprising parallels, particularly in delivering essential electricity to remote and isolated communities. This comparison between Alaska and Australia reveals valuable insights for both regions as they navigate the complexities of energy transition.
Early data on microgrid deployments, gathered in 2009, highlighted both Alaska and Australia as key players, thanks to research from organizations like the Commonwealth Scientific and Industrial Research Organisation (CSIRO) and the Alaska Center for Energy and Power (ACEP). ACEP data indicates Alaska currently boasts more installed microgrid capacity than any other US state, estimated by Guidehouse Insights to be nearly 3,000 MW, compared to Australia’s 1,300 MW (excluding some regional grids in Western Australia).
Australia is a leader in remote microgrids within the Asia-Pacific region, especially in its western territories, which, like Alaska, lack the extensive grid infrastructure prevalent in industrialized nations. Knowledge exchange between Alaska and Australia has been vital in addressing the challenges of integrating increasing renewable energy sources into isolated power systems traditionally reliant on diesel generators. Both regions initially explored wind-diesel hybrids but are now shifting towards solar photovoltaics (PV) and advanced battery storage to achieve lower carbon energy systems.
However, significant differences exist beyond climate. Alaska’s microgrids grapple with cold-weather operational challenges, impacting technology choices and operational limitations, whereas Australia contends with extreme heat.
This article focuses on market innovations, rather than technology, where Australia’s experience can offer valuable lessons for Alaska, even in areas with existing transmission infrastructure. Instead of viewing distributed energy resources (DERs) as obstacles, Australia’s market reforms demonstrate how to transform them into assets for grid reliability.
Another area of Australian leadership is the proactive pursuit of hydrogen as a cornerstone of decarbonization. While Alaska is in the early stages of hydrogen exploration, Australia is actively implementing major hydrogen initiatives. For Alaska, embracing hydrogen could leverage its established oil and gas sector, enabling them to become key players in the evolving energy landscape.
Australia’s Evolving Energy Market
CSIRO projects that by 2050, nearly two-thirds of Australian consumers will utilize some form of DERs. Australia has transformed from a nation primarily known for remote microgrid expertise in its western regions to a hub for grid-connected virtual power plants (VPPs) in the southeast. Energy market deregulation has spurred reforms making VPPs—the coordinated management of diverse DERs like residential, commercial, and industrial loads—essential for intelligent grid management. Several factors underpin this shift:
- Australia has one of the highest per capita electricity consumption rates globally. This high consumption provides substantial flexible load, which can be leveraged for demand response (DR) programs and VPPs.
- Australia leads globally in per capita rooftop solar PV penetration, and adoption is projected to increase. This surge in solar energy presents challenges like curtailment, prompting utilities like Synergy to seek innovative solutions.
- Similar to wildfire-prone regions in the US like New Mexico, California, Colorado, and Oregon, Australia faces increasing wildfire risks and associated power outages. This strengthens the rationale for grid-connected microgrids.
- As coal-fired power plants are decommissioned and replaced by large-scale solar and wind farms, the Australian Energy Market Operator (AEMO) requires enhanced visibility into grid-balancing assets and the integration of both behind-the-meter and front-of-the-meter resources to ensure grid stability.
Alt text: Graph showing increasing trends in rooftop solar PV and battery storage adoption in Australia from 2015 to 2050, highlighting Australia’s global leadership in solar energy.
In October 2021, AEMO, which manages Australia’s National Energy Market (NEM) serving the densely populated southeastern grid-connected areas, implemented a market reform reducing energy trading settlement periods from 30 minutes to five minutes. The NEM accounts for 80% of Australia’s energy consumption. Launched in 1998, it supplies approximately 9 million customers with over 54 GW of generation capacity, with over 300 electricity buyers trading more than $16 billion annually.
The five-minute market fosters intense bidding competition, enabling deregulated energy retailers and market participants to fully capitalize on VPP market optimization. The NEM, an energy-only market without capacity or day-ahead markets, experiences rapid trading activity. Participants can bid into six frequency services markets and eight additional grid service markets, offering nearly 20 ways to deploy battery storage with varied compensation across pricing bands.
Alt text: Map of Australia’s National Electricity Market (NEM) footprint, concentrated in the southern and eastern regions where most of the population resides, emphasizing grid infrastructure.
Within Australia, frequency regulation has become the primary VPP use case for energy retailers, particularly in South Australia and New South Wales. A Cornwall Insight Australia report indicates that utility-scale battery assets in the NEM derive 75-80% of their market revenue from Frequency Control Ancillary Services (FCAS), underscoring the critical role of location for battery asset profitability.
While FCAS presents lucrative revenue opportunities throughout the NEM, South Australia is particularly attractive due to a significant shortage of regional FCAS suppliers. This deficit is driven by the increasing prevalence of both behind-the-meter and front-of-the-meter variable renewables, coupled with a decrease in synchronous generation, traditionally used for grid stabilization.
Decarbonizing Alaska’s Railbelt Grid
Unlike the contiguous electric grid networks in the lower 48 US states or Europe, Alaska’s communities are served by microgrids, some interconnected to form regional grids. The largest, the Railbelt Grid, stretches over 600 miles along the Alaska Railroad route, connecting Fairbanks, the Matanuska-Susitna Valley and Anchorage, and the Kenai Peninsula. These areas can operate independently as needed.
Alaska’s Railbelt Grid evolved from early utility cooperatives meeting basic electricity needs. As these cooperatives expanded, service area boundaries emerged. While the six Railbelt utilities are interconnected, they maintain independence with separate generation resources.
The Railbelt Grid’s energy mix is 75% natural gas, 10% hydropower, and the remainder coal. While natural gas is cleaner than coal and oil in terms of air pollutants like CO2, it is not renewable. Paradoxically, the Railbelt Grid’s carbon footprint is larger than many remote Alaskan microgrids that have shifted from diesel to incorporate hydro, wind, and solar, such as those serving Kotzebue, Kodiak Island, and Cordova.
The Railbelt Grid, with approximately 2,000 MW peak capacity, includes nested microgrids like the University of Alaska Fairbanks campus and military bases. These microgrids operate with limited interaction and lack a system-wide independent operator. Despite resilience, they suffer from a lack of interactive DR, hindering operational efficiency. Limited transparency in grid-wide supply and demand also restricts real-time system optimization of DERs, unlike the NEM, which is significantly larger geographically and in peak demand (over 35,600 MW).
Alt text: Graphic depicting the Railbelt Grid in Alaska as a transmission system composed of interconnected, nested microgrids, highlighting its unique structure.
As outlined in an Alaska Microgrid Group blog, ACEP has proposed three decarbonization scenarios for the Railbelt Grid:
Scenario 1: Decentralized, customer-driven decarbonization maximizing aggregated DERs and enhanced integration of existing microgrids.
Scenario 2: Utility-scale carbon-free energy resources (hydro, wind, solar, geothermal, tidal, biomass, potentially nuclear) combined with carbon capture and sequestration (CCS) for residual emissions.
Scenario 3: A large-scale hydrogen export project leveraging Alaska’s shipping routes to supply low-carbon fuel to Asian markets and for Pacific marine transportation.
Phase 1 analysis is nearing completion, with Phase 2 likely exploring a hybrid approach integrating aspects of all three scenarios.
Regulatory Contrasts and the Role of Market Reform
Most Alaskan microgrids are operated by local utilities; over 100 certified utilities operate in the state. Alaska’s decentralized electric infrastructure allows numerous utilities to serve small, dispersed populations. Cooperative utilities are common, effectively aligning customer needs with renewable energy initiatives.
In contrast, Australia’s regulatory landscape features entities like Horizon Power in Western Australia, which operates the world’s largest utility service territory—five times the size of California—with the lowest customer density (one per 53.5 km2). Due to this sparsity, Horizon Power is transitioning some isolated customers to standalone power systems, serving only 47,000 customers in total.
Historically, Horizon Power’s microgrids relied on centralized diesel generation. However, the Onslow microgrid, serving a coastal town of 850, exemplifies advanced microgrids integrating DERs and renewables, including customer-owned assets. Before upgrades, it met a 4 MW peak load with an 8 MW natural gas generator, 1 MW diesel generators, and a 1 MW lead-acid battery.
Currently, the Onslow microgrid includes:
- A 1 MW utility-owned solar PV array with two 1 MWh batteries at the substation.
- 260 customer-owned solar PV installations (2.1 MW total), representing over half the microgrid’s customers.
- 500 kWh of customer-owned distributed battery systems.
- Plans for an additional 200 kW of customer-owned DER assets.
This blend of utility and customer-owned assets could serve as a model for Alaska’s Railbelt Grid microgrids. Given the Railbelt’s potential for resource sharing across microgrids, regulatory reforms are more critical than technology choices for decarbonization.
Enabling significant DER integration in the Railbelt Grid requires market restructuring to allow dynamic pricing, a common carrier model for transmission access, and grid-wide resource access for cost-effective supply balancing. While a five-minute market settlement like Australia’s NEM might not be suitable, some form of dynamic trading regime is a key lesson for Alaskan regulators and utilities. A single jurisdiction can accommodate both utility-managed remote microgrids and a deregulated energy market leveraging new retailers and aggregators to drive sustainable energy solutions.
Hydrogen’s Commercial Potential: Lessons from Australia
Both Alaska and Australia are exploring hydrogen’s role in decarbonization. Alaska’s hydrogen initiatives are largely conceptual, linked to its oil and gas industry. Australia, despite a similar history of extractive industries, is rapidly advancing renewable energy-based hydrogen projects, with four large-scale projects underway.
These major Australian hydrogen projects, involving leading oil companies, position Australia as a global leader in hydrogen commitment. In comparison, Alaska’s hydrogen development is nascent. However, Alaska holds significant potential to become a US hydrogen hub. The 2021 Bipartisan Infrastructure Bill allocated $8 billion over five years for 6-10 US hydrogen hubs. The Alaska Gasline Development Corporation (AGDC), with ACEP and other partners, has proposed a DOE hydrogen hub project, aiming for 50-100 tons of daily clean hydrogen production, with potential grants up to $1 billion per project.
Alaska’s hydrogen advantage lies in its vast, developed natural gas reserves, offering carbon sequestration potential. Alongside fossil fuels, Alaska has substantial renewable energy resources, including leading tidal energy potential in the US.
Crucially, private sector investment is vital for hydrogen project viability in Alaska. The North Slope represents North America’s largest untapped natural gas source. Hydrogen conversion, alongside LNG exports, offers a pathway to utilize this resource while mitigating climate change impacts. Cook Inlet has potential for 50 gigatons of underground carbon sequestration. A proposed project aims to integrate these elements, alongside a decommissioned ammonia plant, as illustrated below.
Alt text: Diagram illustrating the proposed Alaska hydrogen hub project, showcasing multiple stakeholders and products generating value across the energy ecosystem, including carbon sequestration and ammonia plant integration.
Conclusion
Alaska and Australia share similarities in their reliance on microgrids for remote communities. However, their approaches to market reform for grid-connected regions starkly contrast. Alaska’s Railbelt Grid excels in resilience due to nested microgrids but lacks the dynamic market mechanisms to fully leverage demand response and reduce fossil fuel dependence. A more dynamic market structure and common carrier transmission model may be necessary for Alaska to achieve cost-effective climate risk reduction.
While Australia’s hyper-dynamic market might not directly translate to Alaska’s utility-centric model, the current Alaskan system is inefficient and fails to utilize advancements in grid balancing technologies.
Regarding hydrogen, Australia is significantly ahead, yet Alaska has the potential to lead US hydrogen development. As the global energy transition progresses, Alaska’s energy stakeholders have an opportunity to transform its oil and gas industry towards hydrogen, creating substantial economic benefits and contributing to a cleaner energy future in a creative and cost-effective manner.
References
1 Energy Networks Australia and CSIRO, Electricity Network Transformation Roadmap: Final Report, April 2017.
2 PV Magazine: FCAS fetches highest revenues in SA and NSWM.
