laska’s Railbelt region refers to the area serviced by Alaska’s interconnected electric grid stretching from the Kenai Peninsula through Anchorage and the Matanuska-Susitna Borough, north to Fairbanks. According to the Alaska Energy Authority (AEA), the Railbelt functions more like an “energy island.” This isolation is compounded by the Railbelt’s structure; AEA likens the three regions to a “single extension cord.” This is unlike the Lower 48, where grids can tap into a vast network of power sources via multiple pathways.
The Alaska Center for Energy and Power (ACEP) at UAF recently completed an exhaustive exploration into the Railbelt grid’s future. This report focused on navigating the complex factors of energy infrastructure such as reliability, affordability, and clean energy development for the region. The project’s purpose, outlined in extensive consultation with Alaska’s energy community, was to inform future decisions and studies by utilities, the State of Alaska, and other stakeholders through a detailed evaluation of resource mixes, electrification impacts, operational and reliability implications, and the potential costs of a decarbonized power system.
Renewable energy sources, such as wind and solar power, offer a promising avenue for reducing the Railbelt’s carbon footprint. The ACEP study, supported by the Hawai’i Natural Energy Institute and US Office of Naval Research, concludes that Railbelt communities could generate 96 percent of electricity from non-fossil-fuel sources by 2050.
But there’s a catch: the conversion would cost up to $12 billion dollars. Integration of renewable energy sources introduces a set of unique challenges. Unlike coal, gas, or diesel-fired turbines that can be easily turned on or off to match demand, wind and solar power are intermittent, requiring advanced management strategies to ensure grid stability. Furthermore, these sources generate direct current, which must be switched by inverters into the alternating current that energizes the grid. These inverters represent both a challenge and an opportunity for innovation in how renewable energy is integrated into the Railbelt’s energy mix.
“When we started this project two years ago, we decided to name it a ‘decarbonization study’ because of the interest in establishing an RPS [renewable portfolio standard] or clean energy standard. However, the model we’ve developed is really a technology-neutral tool,” says Gwen Holdmann, associate vice chancellor for research, innovation, and industry partnerships at UAF. “It’s intended to help identify a sustainable mix of energy resources capable of satisfying the Railbelt’s future energy requirements without compromising system stability.”
Holdmann was the director of ACEP when the study began in 2022. The final product released for public comment earlier this year ended up somewhat different from what researchers anticipated. “So we’re considering rebranding this effort in the future to make it clear this can encompass a diverse array of energy resources and generation sources,” Holdmann says.
Acknowledging the limitations of any single method to cover all aspects of power system planning, the study adopted a multi-modal approach. This strategy allowed for a detailed examination of different grid configurations, integrating renewable energy sources like wind, solar, tidal, and hydro, alongside traditional energy sources and emerging technologies such as nuclear power and battery energy storage systems. A core concept of the study was a power system simulation and modeling process, utilizing advanced software tools that are widely recognized and employed by utility entities nationwide, including those within the Railbelt network.
Scenario 1: Business as Usual. This scenario envisages minimal shifts toward renewable energy. It projects the construction of new fossil fuel units to meet increasing energy demands, with renewables making up 11 percent of the energy mix. This scenario, requiring a capital investment of $2.3 billion (in 2023 dollars), anticipates a generation and transmission cost of $119 per megawatt-hour (MWh), setting a benchmark for comparing other options and the economic and environmental impacts of more ambitious decarbonization efforts.
Scenario 2: High Renewables. This scenario represents a significant pivot toward wind, solar, and hydroelectric energy, incorporating the Susitna-Watana Hydro project (475 MW), 1,022 MW of wind, and 472 MW of utility solar. It aims for renewables to contribute 88 percent of the required energy, supported by 1,243 MW of new battery storage to enhance grid stability. The scenario requires substantial capital investment of $11.8 billion and yields a generation and transmission cost of $134/MWh. This mixture of investment highlights the indispensable role of battery storage for a renewable energy grid in addressing the challenges of intermittent power production.
Scenario 4: Small Modular Nuclear Reactors. Envisioning a near-complete decarbonization, this scenario considers the deployment of small modular nuclear reactors in addition to 1,056 MW of new wind and 328 MW of utility solar, aiming for 96 percent zero-carbon generation. It also plans for 1,518 MW of new battery storage and Alaska Intertie upgrades. The scenario outlines a capital investment of $10.1 billion and a generation and transmission cost of $128/MWh, illustrating the role nuclear energy could play in achieving deep decarbonization.
Some of these efforts stand to benefit from federal funding, but there are challenges. According to the AEA, a pivotal concern in funding the transition is the current uncertainty surrounding Clean Energy Tax Incentives. “The Internal Revenue Service has not yet issued its final determination on the Clean Energy Tax Incentives, as part of the Inflation Reduction Act (IRA),” the authority states (while cautioning that it does not offer tax advice). “In the meantime, AEA recommends that prospective energy project developers consult professional tax advisors for accurate information about whether IRA tax credits may be applicable to their respective projects. In addition, IRA tax credits are very specific and apply to only certain aspects of a clean energy project, with bonus credits available for projects that meet certain additional criteria. Clean energy tax credits are likely to benefit clean energy development and may reduce overall project costs.”
The success of Railbelt decarbonization depends on overcoming the intertwined challenges of funding, regulation, technology integration, and stakeholder alignment. Another hurdle is that the Railbelt is split into five customer-owned cooperatives: Golden Valley Electric Association, Matanuska Electric Association, Chugach Electric Association, Homer Electric Association, and the municipal Seward Electric System.
“Each utility serves its customers first and the larger system second,” says AEA Executive Director Curtis W. Thayer. “While appropriate, that dynamic does not always work to the benefit of the Railbelt as a whole. However, there is a consistent effort by all of the utilities to collaborate on Railbelt-wide efforts.”
Thayer points to regional collaborations such as the committee that manages the Bradley Lake Hydro Project near Homer for the benefit of the entire grid. Utilities also work together to manage the Alaska Intertie that allows electricity to flow between Southcentral and the Interior. More recently, they formed the Railbelt Reliability Council. “These entities may represent the best example of collaboration between the different member utilities on the Railbelt today,” Thayer says.
The utilities have a lot to learn in the time it would take to implement any of the decarbonization scenarios. “Currently there is limited operational experience of running the Railbelt with large inverter-based resources such as wind and solar,” says Holdmann. “There will be a significant learning curve with the first large wind project for dispatchers and operations engineers. Therefore, changes and additions are best done in incremental steps.”
Indirectly, the stabilization of energy costs on the Railbelt has far-reaching implications for the cost of living and doing business across most of the state. According to AEA, lower energy costs on the Railbelt, where about 70 percent of Alaska’s population lives, could lead to reduced rates for rural communities through mechanisms such as the Power Cost Equalization program, thereby addressing one of Alaska’s longstanding challenges: the high cost of energy in remote areas.
Additionally, the focus on energy efficiency and electrification, particularly in the areas of transportation and heating, may offer avenues for innovation that help communities be more economically resilient.
Findings from the study emphasize the importance of strategic planning and policy support to navigate the economic complexities of decarbonization. It highlights the need for a holistic approach that considers not only the immediate costs but also the long-term economic benefits.
“One of the most important things learned from this project was how to address these types of questions and what tools to use to solve them,” Holdmann says. “Methods for performing system planning for electric grids have evolved substantially in the last few years and will likely continue to, as there is more variability in energy resources and the inverter-based resource technology changes and improves. This necessitates new types of modeling not previously needed to capture the potential new types of stability and resource adequacy challenges.”
The ACEP study presents a vital roadmap for navigating the energy transition, balancing technical feasibility with economic and social considerations.