During visits to my aunt’s house in Germany when I was a young girl, I loved to snuggle up to the Kachelofen – a colorful tiled masonry stove with a built-in bench – on chilly mornings. I could always count on it to be toasty warm and it was my favorite place to curl up with a book. At the time I never thought to ask where that heat came from, despite never seeing any evidence of the wood or coal traditionally burned in them. It was just nice and warm, and slowly released heat into the house all day. I never questioned it.
Decades later, on the other side of the globe, I found myself reminded of the Kachelofen as I stood before a similar radiant heat device in Kongiginak, Alaska. I was in Kongiginak at the invitation of the community to see firsthand their novel approach to managing wind energy. The local tribally-owned utility, Puvurnaq Power Company, was implementing a strategy pioneered by Alaska-based developer Intelligent Energy Systems. That strategy involved storing excess power in the form of heat, rather than in chemical batteries, by strategically installing thermal electric stoves in individual residences. These stoves are manufactured by Steffes, a small North Dakota based company. Appearing as a nondescript rectangular white appliance, these devices looked far more utilitarian than my aunt’s beautiful Kachelofen,but they function exactly the same way. Inside the Steffes stove are ceramic fire bricks with a high heat capacity and density as well as an electric heating element that warms when there is cheap power available. The homeowner can then use that heat when they want it by turning on a fan that blows air through channels in the hot bricks, and into the home.
My aunt and the community of Kongiganak use these electric thermal stoves for exactly the same reason, despite being separated by decades and a continent. To reduce their home heating bill. In both cases, the strategy is to take advantage of cheap electric power when available, and use that as an alternative to their more expensive primary source of heat. In Kongiganak, that cheap source of energy is excess wind power – something that occurs much more often during the winter months, when heating demand is also high.
In 1980-era Germany, cheap power was supplied by nuclear and sometimes coal. Electric night time heating and storage was a win for everyone – the utilities sold more power, people had access to a cheaper and easier source of heating, and it also helped reduce air pollution within cities. Hence, electric thermal storage was incentivized by providing free retrofits to residents – an option my aunt clearly took advantage of, leaving the coal cellar in the basement empty and unused. Germany and other European countries then further encouraged residents to use the electric heat through a sharply discounted electric power rate available only during late night and early morning hours.
Wind and solar are similar to nuclear in that they are relatively capital intensive to build, but have almost no incremental cost once they are up and running. That means ideally, you want to squeeze as much power out of these generation sources as possible since each additional kilowatt hour is produced at virtually zero marginal cost. While my aunt’s Kachelofen was programmed to turn on and then off at set times of the night to match the reduced rate timing, a scheduled approach does not work in Kongiganak where there is no way to predict when the wind will blow.
Fortunately, the Steffes stoves are a lot smarter than my aunt’s Kachelofen – they are programmed to continually monitor grid frequency and respond nearly instantaneously to changes in supply or demand. When the wind is blowing, the thermal electric stoves come online automatically. And because Kongiganak has a lot of installed wind – more than three times the average load – this happens quite often. In other words, the stoves can automatically “see” when there is excess wind power and turn on to suck it up. They are also in constant communication with each other, programmed to turn on and off sequentially so they don’t all run at the same time, ensuring every household gets a fair share. The stoves are metered separately from normal electric power services, and residents are charged a special “wind rate” for home heating at 10 cents per kilowatt. That amounts to substantial savings given the normal, unsubsidized rate for electric power of 67 cents per kWh. Tracking use and billing for this special “wind rate” also requires more sophistication since this event could happen at any time, day or night. Intelligent Energy Systems handles this by separately metering the Steffes Stoves at the lower 10 cents per kWh rate. That’s cheap and offsets expensive heating oil, with some residents reporting the electric heaters reduced their fuel oil consumption by two-thirds.
Reducing the cost of heating is a big deal in rural Alaska. While the cost of electric power is subsidized through the Power Cost Equalization program for residential users, the cost of heating oil is not, with the exception of some low income heating assistance programs. Therefore, reducing the cost of heating, whether indirectly through home weatherization improvements or directly through a supplemental source of heating can make a big difference in rural household budgets.
In the vernacular of mainstream energy markets, Kongiganak has implemented a dynamic time-of-use rate structure, charging less when there is excess zero marginal cost power available. At the same time, they have strategically increased community load in order to justify the installation of bigger wind turbines that can achieve better economies of scale. The cost of installing six wind turbines, as Kongiganak has, is not too different from the cost of installing two. Dennis Meiners, the owner and founder of Intelligent Energy Solutions who designed this system, sees this approach as the future of rural energy. In fact, he wants to double down on this strategy. He envisions bigger, more economical turbines - perhaps Megawatt-scale turbines mounted on a floating structure, such as giant off-shore wind turbines increasingly gaining traction in other markets. This strategy would dramatically reduce the time and complexity of installation and eliminate the need to construct a foundation - a tricky and expensive undertaking, especially in areas with unstable permafrost. The economics of such an ambitious project would require a significant increase in local electricity sales, since the power can’t be transmitted to distant users via a transmission network as would be possible elsewhere. That means this increase in demand needs to occur locally - and electrifying heating loads is an obvious approach.
Other utilities, like Kotzebue Electric Association, also use wind-to-heat, but have opted for a single, big load that is cheaper to install and easier to manage. Rather than heating units in individual residences, they have installed an electric boiler at the hospital to augment the fuel oil boiler that normally provides heat to the facility. When the output of their wind farm exceeds some threshold in comparison to the load, the utility automatically shunts excess power to the hospital and displaces heating oil there. It doesn’t have the same storage component of the Steffes heaters, but the hospital is always in need of heat, just like many other commercial loads. In either case, it’s an elegant solution. Dispatchable thermal loads have enabled economies of scale in installing larger renewable energy projects and extended the benefits from these installations to energy demands beyond just “normal” electric power loads.
The role of niche markets in technology transitions
Kongiganak and many other communities in rural Alaska are indisputably global leaders in energy, specializing in integrating ever-increasing proportions of variable renewable energy like wind and solar on small grids, also called microgrids. In fact, it is arguably one of the most organically innovative energy markets in the world, with remote Alaska home to around 10% of the world’s renewably-powered microgrids. This is largely driven by the simple matter of dollars and cents, not forward-looking energy policies. Electric power is expensive in rural Alaska, and compared to other similar markets the subsidies we offer are pretty small. That means there are real, buck-stops-here incentives to try to do things that reduce the cost of energy and reduce reliance on diesel fuel. Using more local resources is the obvious way to do that.
Alaska’s disaggregated and decentralized energy market enables a whole bunch of on-the-ground innovation and experimentation. Rural utilities are largely not rate regulated, so they are free to take pragmatic risks. They, of course, report to their boards but in general, they can make decisions about trying new approaches organically and locally. This freedom can have negative consequences when a local utility is poorly managed however. The current situation in Aniak, with more than tripling rates in a month, is an example where the lack of rate regulation can create untenable situations for residents.
Nonetheless, some communities in remote parts of the state have been pushing the limits far beyond what most mainstream utilities would be comfortable with. As a result, they have served as incubators for a wide range of really innovative technologies and strategies that are now gaining popularity in mainstream markets. Examples include dynamic time-of-use energy pricing, demand management, smart metering technology, heat pumps, thermal storage, and the strategic addition of new loads to maximize the use of local renewable energy resources. As a result, Alaska’s rural utilities have been showcasing what the grid of the future might look like, and the evolving role of the utility industry within the broader energy market.
The evolving role of utilities
Shungnak – a small community in the Northwest Arctic – has some of the state’s highest energy costs. In 2020, Shungnak installed a large solar farm - large enough to shut off their diesel power plant and operate 100% off solar when the sun is shining. Given their location north of the Arctic Circle, this happens quite often in the summer months. But what is more interesting to me is the ownership structure of their solar project. The local tribe owns the solar farm, battery, and inverter. The conventional diesel powerplant and all of the distribution infrastructure and relevant switchgear are owned by the local electric utility, the Alaska Village Electric Cooperative (AVEC). When the available solar energy is adequate to exceed the local electrical load, AVEC shuts off the diesel, effectively handing over generation responsibility to the tribe. They then purchase the power from the tribe, while continuing to monitor the grid and distribute power to their customers.
Handing over 100% of generation responsibility to a third party is a big deal for electric utilities. But many experts think this is the evolving role utilities will play in future energy markets - essentially serving as the traffic cop managing power coming from all sorts of different sources, from conventional power plants (which they might own) to rooftop solar, to large wind and solar farms operated by independent power producers that all feed power onto the grid. Customers will be charged rates dynamically, too, based on how much power at what price is available at any particular moment in time – something that is already happening in many larger energy markets.
If the grid of the future is already being incubated in rural Alaska, could the Railbelt benefit from some of these strategies and lessons learned? Undoubtedly.
We spend a disproportionate amount of time discussing energy planning focusing on the supply-side view of the energy system: How will we replace declining Cook Inlet Natural Gas? What will replace coal plants? How can we integrate wind? What transmission do we need? How about storage? Should we build Susitna? These are all important questions, but they miss half the equation. We shy away from the demand side of our energy system partly because it’s hard to wrap our heads around. Change on the demand side represents diffuse, societal change, and we tend to fall into the trap of the “end of history illusion.” When we think retrospectively about our past selves, we remember ourselves as being quite different. Our personalities, opinions, and tastes change over time. Looking back retrospectively, this is usually quite apparent. But when we look ahead, we somehow expect the “me” of tomorrow to be a lot like the “me” of today. In other words, the “end of history” illusion is about people underestimating - often significantly - how much they will change in the future. And we do the same when it comes to energy and infrastructure. It is hard to imagine that how we use energy in the future will be vastly different then how we use it today, or what source it comes from. We understand that there will be incremental change, but truly wholesale replacement is difficult to envision. Nonetheless, consumer demand and energy markets are evolving, with greater and greater electrification of new loads emerging as a clear and accelerating trend.
Globally, electricity accounts for roughly 20% of final energy demand today, up from around 15% twenty years ago. That number is only expected to grow in coming decades. There is no reason to think Alaska can or should go in a different direction. Instead, we could choose to embrace this future and electrify everything – or as much as we reasonably can. That is, assuming we have a pathway to cheap power. We have a lot of good reasons to get ahead of the curve, not the least of which is uncertainty about future natural gas supply in Cook Inlet.
How do we move in this direction? Railbelt utilities could consider conducting some limited trials to see what the uptake for technologies that increase demand for electricity might be, despite the fact that right now, we don’t have much unused generation capacity. Testing the market demand would be a great way to understand technical, regulatory and social implications while holding everyone’s pocketbooks harmless. For example, experimenting with time-of-use rates on a limited basis to charge EVs or electrothermal heaters, installing dispatchable electric boilers for a few commercial customers, or incentivizing heat pumps with some sort of rebate could be a few opportunities that should pass muster with the Regulatory Commission of Alaska.
My colleague at ACEP, Dominique Pride, is working with residents in poor air quality areas of North Pole to install Steffes stoves in about 15 homes, artificially mimicking a time-of-use rate by providing a subsidy to the homeowner equivalent to a 10 cents power rate. In essence, she is applying the Intelligent Energy Systems strategy to the Railbelt. Another colleague, Phylicia Cicilio, is working with the Railbelt utilities to develop a suite of scenarios for decarbonization of the Railbelt grid by 2050, including resource assessment, load forecasting (including potential uptake of EVs and electric heating), economic dispatch of generation sources, stability and reliability analysis - and - importantly, potential impact to consumer rates.
Technology transitions don’t happen uniformly all at once. There are pockets of early adopters, or niche markets, where technology uptake is much faster than the norm. Rural Alaska is an example of such a market. These niche markets are often where significant experimentation occurs, systems are hardened, and bugs worked out before broader, mainstream adoption occurs. We would be wise to advantage of the significant amount of knowledge and expertise that has accumulated over time. To learn from rural communities and utility managers what strategies and approaches have worked, where, and why. After all, when it comes to renewable energy, rural Alaska has been paving the way – quietly and without fanfare – for a very long time.
Gwen Holdmann is a Senior Researcher at the Alaska Center for Energy and Power and the University of Alaska Fairbanks’ Associate Vice Chancellor for Research, Innovation & Industry Partnerships. This is part of a series of articles on Alaska’s energy future published by the ACEP.
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