In a multi-year debate over how to enable residents of the city of Fairbanks in Alaska’s Interior to obtain affordable energy supplies, there is at least one point of general agreement: The city is hurting from the impact of high energy prices, thanks to a dependence on the use of expensive liquid fuels for the heating of buildings and for some power generation. But with various people and organizations exploring several future Fairbanks energy supply possibilities, there is a diversity of views on how to tackle the Fairbanks energy problem.
In the interests of clearing some of the ice fog surrounding the Fairbanks energy debate, Antony Scott, senior economist and policy advisor at the University of Alaska Fairbanks, has been working with the Alaska Center for Energy and Power on a study into the economics of Fairbanks energy options. And on Jan. 16 Scott presented some of the results of that study to the Alaska Senate Resources Committee.
Scott told the committee that the study results demonstrate the critical importance of the sales terms for fuel commodities, including pricing and the duration of pricing terms, in determining the cost of energy in Fairbanks. And, if Fairbanks is going to rely on natural gas as a primary energy source in the future, it will be particularly important to clarify from the outset the price terms for that gas, especially if people are looking for any price discounts for Alaska communities, he said.
“It’s critically important, I would urge, that those considerations get nailed down as soon as possible,” Scott told the committee. “There is nothing keeping people from negotiating gas sales contracts, for example, today.”
The study has used publicly available information from projects targeting future Fairbanks energy supplies, and Scott thanked people involved in these projects for the time they had spent in helping the university with its work. The study evaluated the following options:
• trucking liquefied natural gas from the North Slope to Fairbanks;
• the construction of a small-diameter gas pipeline for the delivery of natural gas to Fairbanks from the North Slope;
• offloading Fairbanks gas from a gas pipeline from the North Slope to Southcentral Alaska, with three potential daily throughput capacities for that line: 250 million cubic feet, 500 million cubic feet and one billion cubic feet;
• obtaining Fairbanks gas through a spur line off a major gas sales line from the North Slope, with that sales line assumed to be delivering gas for export as liquefied natural gas to Asia through a port in Southcentral Alaska;
• shipping gas to Fairbanks through an in-state pipeline north from Beluga on the west side of the Cook Inlet;
• the manufacture of liquids fuels in the Alaska interior using a coal-to-liquids plant; and
• the use of electrical power for both heating and lighting in Fairbanks, with the power coming from a planned hydropower plant at Watana on the Susitna River.
• the use of electrical power generated on the North Slope and delivered to Fairbanks through a high voltage direct current transmission line.
Scott said that the study compared these options on the basis of the potential delivered cost of energy to Fairbanks energy consumers, without considering other factors such as the resulting cash flow to the state. And the study included the two electrical power options for the purposes of comparison, while accepting that a full evaluation of the complexities of electricity supplies was beyond the study’s scope.
To ensure meaningful comparisons, the study used a consistent set of assumptions for project financing for all projects while applying the same sensitivity analysis to each project when assessing project uncertainties. For projects involving the use of North Slope natural gas the study assumed the purchase of untreated gas on the Slope, with the cost of removing impurities from the gas being part of the overall project costs.
For each energy option, the study derived potential energy costs in Fairbanks in 2023, a year that would post-date the completion of any of the projects under review.
While recognizing the importance of the cost of energy transportation, such as the shipping of gas through a pipeline, the study particularly focused on commodity pricing as a key driver for the cost of energy in Fairbanks, Scott said. And the study found that for the most part it is possible to index the commodity prices back to the price of North Slope crude oil, as sold in U.S. West Coast markets.
For example, much North Slope gas currently sold for use on the North Slope is priced using a formula agreed in the early 1990s between the state and the North Slope producers for the state’s royalty gas. That price formula sets the price per million British thermal units of untreated gas at about 4.6 percent of the oil price per barrel. And, although it may be possible to negotiate a better price than this, North Slope gas pricing is currently indexed to oil pricing in this way, Scott said.
The price of liquefied natural gas on the Asian market is also currently indexed to oil: Historically the per-million-Btu price in this market has been approximately 14.5 percent of the Alaska oil price, plus about 90 cents per Btu, he said. And although people have speculated about Asian prices softening in the future, any significant price softening would jeopardize the prospects for a major Alaska gas sales line.
The price of heating oil in Fairbanks, by comparison, has worked out on a Btu basis to be 22.5 percent of the oil price plus $4.20 per Btu.
One interesting outcome of the oil price indexing is the way in which the multipliers involved in the indexes can magnify the commodity price volatility as the oil price changes — that effect can lead to greatly different risk profiles for projects involving the use of energy resources from different places, Scott pointed out.
Range of prices
Plugging the commodity price models into financial models for each energy option enabled the plotting of potential Fairbanks energy prices for each option across a wide range of North Slope oil prices. One set of energy prices is based on an assumption that the projects would be entirely funded by private capital, and another set of energy prices is based on an assumption that the state would fully fund the projects. An energy option would show promise if its projected price for energy in Fairbanks appears lower that the projected price of heating oil.
The analysis assumed that the North Slope producers would sell gas at the most advantageous price, depending on market access for the gas, with no home-town discount for Alaska residents. And this assumption led to some intriguing outcomes for the 500 million cubic feet and 1 billion cubic feet options for an in-state gas pipeline, on the assumption that the scale of these pipelines would require the sale of at least some gas into the highly priced Asian liquefied natural gas market. At oil prices above about $70 per barrel that linkage to the Asian market could push the price of gas in Fairbanks higher than the price from a smaller scale pipeline, with the relatively high commodity price overwhelming any economies of scale to be gleaned from a relatively high pipeline throughput, Scott said.
Oil price uncertainty
Another intriguing result of the analysis indicates that if future oil prices turn out to be relatively low, the major gas sales line would be the only option to beat the cost of heating oil in Fairbanks, Scott said. And there is major uncertainty about future oil prices, given possible scenarios such as the worldwide implementation of shale oil technologies, he cautioned.
The analysis suggested that both options involving the use of electrical power for the heating of buildings in Fairbanks would prove substantially more expensive than any other energy option, including the use of heating oil.
Comparisons between the estimated cost of Fairbanks energy for privately funded versus state funded projects shows that state funding would substantially reduce the energy cost. That effect mainly results from the fact that all options tend to be highly capital intensive, with the state funding reducing the cost of the capital, Scott said. Under the assumption of state funding, all options start looking preferable to the use of heating oil. Those options involving the dedicated shipment of gas from the North Slope to Fairbanks have energy pricing estimates that are statistically indistinguishable, while options involving a linkage to the sale of liquefied natural gas in Asia have pricing that rapidly escalates with the oil price.
An important issue that people would need to address when implementing a new energy source for Fairbanks is what Scott referred to as “ramp-up risk,” the risk associated with the timeframe involved in building the necessary new energy infrastructure. While there is no ramp-up risk for heating oil, a commodity that Fairbanks residents already widely use, an expansion of the natural gas distribution network, for example, might take a couple of years or so to accomplish. The cost of providing energy to consumers during, say, the first year of infrastructure construction would be much higher than after the customer base is fully subscribed, Scott said. And, high initial prices, perhaps above the cost of heating oil, coupled with conversion costs that customers would face, could deter customers from switching to the new fuel.
One particular problem in assessing the ramp-up risk associated with a Fairbanks project is a general lack of knowledge of just how much energy Fairbanks consumers use, Scott said. Whereas in a city like Anchorage it is possible to obtain data about how much gas people are consuming for the heating of buildings, there is no means of obtaining similar data for Fairbanks, where many people heat their houses using heating oil or firewood obtained from multiple sources.
Other complexities facing energy decision makers include the wide range of investment required for the different energy options, and the range of timeframes required for option implementation.
Coal-to-liquids technology presents some intriguing challenges. Because this technology involves fuel that is very similar to heating oil, coal-to-liquids would present no start-up risk. On the other hand, the fuel produced from coal would compete directly in the market with heating oil, thus making it is almost impossible to conceive of a state-sponsored project in which the artificial fuel would bring cost relief to fuel oil users, Scott said. Essentially, any undercutting of fuel oil prices by a state subsidized project would likely result in people buying the subsidized fuel and then reselling it at market rates, he said.
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