Given the current intense debate over various options for bringing North Slope natural gas to market, objective information is critical to assessing the feasibility of ideas that seem attractive but that may not withstand the rigors of harsh reality. Would, for example, a spur line to bring North Slope gas into Southcentral Alaska be economically viable? Is an Alaska-based petrochemical industry a real option or simply an optimistic mirage?
The U.S. Department of Energy tackled those and other questions in a comprehensive report it has just released on potential Alaska natural gas demand in the years ahead.
Prepared by a team of consultants from SAIC (Science Applications International Corporation) and extensively reviewed by natural gas stakeholders from government and industry, the report examines the various economic factors that will impact Alaska gas supply and demand in the future.
The study looks into the crystal ball of natural gas usage in the period between 2015 and 2035. There is, of course, major uncertainty regarding what the actual economic situation will be during that period. But, as a detailed and comprehensive analysis of most of the factors impacting Alaska natural gas supply and demand, the report provides invaluable insights into future uses for gas in the state.
Based on assumptionsThe findings from the study depend on several critical assumptions about the future and the study assumed that by 2015:
• An Alaska natural gas pipeline will be built from the North Slope to the Lower 48, following the route of the Alaska Highway into Canada.
• A spur gas line will be built connecting the Alaska Natural gas pipeline to the existing natural gas infrastructure in Southcentral Alaska. That spur line may follow the Parks Highway from Fairbanks or go through Glennallen to follow the Glenn Highway to Wasilla. (The study also examined the economic viability of building a spur line.)
• Gas supplies from known gas reserves in Cook Inlet gas field will continue (the study did not take into account the discovery of additional reserves).
• Lower 48 gas and crude oil prices will follow forecasts published by the DOE Energy Information Administration in 2005.
• North Slope gas (including NGLs) will be sold at Lower 48 prices, less the tariff for shipping on the Alaska natural gas pipeline.
• The price of natural gas delivered to Southcentral Alaska will be the North Slope gas price plus the tariffs for the use of the spur gas line and the relevant portion of the North Slope gas line.
• Gas for use in Fairbanks will not pass though the spur line and will require a separate offtake point from the North Slope gas line.
• Any future new petrochemical industry will be located in Southcentral Alaska rather than Fairbanks, because of lower operational and capital costs, and the proximity to export terminals and trading routes.
Gas prices tied to Lower 48The study assumptions lead to the conclusion that the base price of gas delivered to Southcentral Alaska after the year 2015 will be tied to natural gas prices in the Lower 48. Specifically, the study anticipates that the Southcentral price will equal the Lower 48 price less some component of the Lower 48 tariff for the North Slope gas line plus the tariff for the spur line. Gas shippers would be unwilling to sell gas in Southcentral below that base price, because they would then undercut their Lower 48 pricing.
Conversely, if that base price is higher than the maximum price that a gas-based industrial user in Southcentral requires for viable operation, that industrial user will cease operations or seek alternative sources of feedstock. And if the base price for natural gas exceeds the equivalent cost of other forms of energy (coal, for example), an energy user will switch to that alternative source.
By using the Energy Information Administration’s forecast of future gas prices coupled with estimated gas line tariffs the study team derived a Southcentral Alaska base gas price ranging from $4.14 to $5.145 per million British thermal units (1 million British thermal units are roughly equivalent to 1,000 cubic feet of natural gas).
The study also considered a high gas price range case of about $6 to $7 per million British thermal units and a low gas price range case of about $2 to $3 per million British thermal units for gas delivered to Southcentral Alaska.
All prices and calculations used 2005 dollars.
The Southcentral gas price would track slightly lower than the Lower 48 price because the combined pipeline tariffs for delivery to Southcentral should be less than the tariff for Lower 48 delivery.
That price differential with the Lower 48 might have some impact on gas exploration in the Cook Inlet area, because the lower price in the Cook Inlet might deter exploration investment in the Cook Inlet rather than elsewhere. On the other hand, a gas pipeline linkage between the Cook Inlet and the Lower 48 could also open up Lower 48 markets for Cook Inlet gas.
Types of demandSo, if we assume a supply price in the range of $4 to $5 per million British thermal units during the first few years of spur line operation, what might gas demand in Alaska look like? The study considered five major, potential users of dry natural gas in the region (dry gas consists of almost pure methane, as distinct from wet gas that includes natural gas liquids such as propane and butane):
• residential and commercial users of gas for heating and cooking;
• electrical power generation;
• LNG production, as at the current LNG plant at Nikiski on the Kenai Peninsula;
• ammonia and urea production, as at Agrium’s Nikiski fertilizer plant;
• a gas-to-liquids plant (abbreviated to GTL), for converting methane into something similar to diesel fuel.
The study also considers the industrial use of wet gas for:
• a petrochemical plant manufacturing materials such as polyethylene and monoethylene glycol for export from Alaska;
• a liquid petroleum gas plant producing LPG for use in Alaska and for export.
Residential and commercial useIn calculating future residential and commercial demand the SAIC consultants used current population levels and projected population growth in both Southcentral Alaska and central Alaska. The consultants used historic Alaska gas demand/price sensitivity data to project future demand from existing gas users, and used Enstar Natural Gas Co.’s projections for demand from new gas customers (the projections take into account gas price levels that would motivate people to convert to gas from alternative fuels). Enstar is the main gas utility in Southcentral Alaska.
Gas price levels would impact demand. But, because the price of natural gas delivered through a spur line is likely to remain below the price of heating oil, natural gas demand for residential and commercial use is likely to remain high. In fact the consultants forecast residential and commercial demand to increase from a current level of 96 million cubic feet per day to 118 million cubic feet per day by 2015 and 148 million cubic feet per day by 2035.
Power generationThe study found that natural gas is likely to continue to be the main source of energy for electricity power generation in Southcentral Alaska. However, if natural gas prices rise towards the top gas price case, coal would likely displace gas for electricity generation. However, the report comments that a linkage in gas pricing between Alaska and the Lower 48 might make competing fuels more attractive. Coal prices in Alaska, for example, might not increase much relative to gas because of the isolated location of the state.
On the other hand, building a new coal plant involves major capital cost.
The study concluded that increasing demands for electricity are likely to drive a significantly increased demand for natural gas, with a current demand level of 93 million cubic feet per day growing to 148 million cubic feet per day by 2035.
Industrial demand for dry gasThe SAIC consultants analyzed the potential natural gas demand by an LNG plant, an ammonia/urea plant or a GTL plant by calculating the maximum price that each of these facilities could afford to pay for gas while remaining economically viable in world markets for the plant products. The calculations involved deriving “netback” product prices, by subtracting from future projections of world product prices the production and transportation costs for the products.
The consultants obtained the following results:
• The current Nikiski LNG plant would require gas at or below $3.20 per million British thermal units, thus rendering it uneconomic under most price scenarios for spur line-delivered natural gas.
• The Nikiski ammonia/urea plant would require gas at or below $2.79 per million British thermal units, likely making that plant uneconomic.
• A GTL plant would require a gas price at or below about $3.20 per million British thermal units, a price level that again looks uneconomic.
But what about industrial plants that use wet gas?
A world-class petrochemical plant in Southcentral Alaska would become viable at gas prices at or below $4.60 per British thermal unit, while an LPG plant would require a price at or below $4.20, the study found. So, both of these types of plant look marginally economic.
The consultants did include within their analysis smaller scale industrial uses, such as the use of gas for electricity generation for the proposed Pebble mine near Iliamna. However, they found that this type of industrial application did not increase the gas demand significantly.
Spur pipeline optionsThe results of the analysis of future gas demand led to four possible gas spur line scenarios.
But the consultants found only one scenario that clearly appeared viable under the base assumptions for future natural gas pricing and other factors. That scenario consisted of a 350 million-cubic feet per day pipeline delivering dry gas. That type of pipeline would support just the Southcentral commercial and residential gas demand and the demand for electricity generation, it being assumed that the gas delivered from the North Slope would be too expensive for large-scale gas-based industries.
The spur gas line capacity for this scenario assumed the availability of 80 million cubic feet per day from Southcentral gas storage facilities to meet peak winter demand.
A second scenario would consist of a 590 million-cubic feet per day spur line that has the capability of carrying wet gas. In addition to the dry gas supplies of the first scenario, this larger spur line would deliver 75,000 barrels per day of ethane to a petrochemical plant, 63,000 barrels per day of butane and propane to an LPG plant and 15,000 barrels per day of pentane for gasoline blending. The scenario appears viable using base prices but suffers from complications such as the construction and operation of the wet gas pipeline (including a plant to separate NGLs from the products flowing down the Alaska natural gas pipeline); competition from the Alberta petrochemical industry; and uncertainty regarding long-term product pricing.
Another spur line scenario would be a 1 billion cubic feet per day line delivering just dry gas. This would support the same gas users as the first scenario but would also supply 212 million cubic feet of gas per day for the Nikiski LNG plant and 480 million cubic feet of gas per day for a GTL complex. Uncertainties regarding the continuing operation of the LNG plant, uncertainties regarding the capital cost of a GTL plant and uncertainties about the future value of GTL combine to make the viability of this scenario less probable than that of the second scenario.
The fourth scenario would be a 1.3 billion cubic feet per day spur line that can carry wet gas. This pipeline could supply natural gas and NGLs for all of the demand components included in the first three scenarios. But the combination of unfavorable economic factors that affect the second and third scenarios makes this fourth option the least likely scenario to be viable.
The report also says that the large drawdown in natural gas or NGL from the Alaska natural gas pipeline, were the 1 billion or 1.3 billion cubic feet per day options to be implemented, would adversely impact the economics of the Alaska natural gas pipeline — that impact would be another factor to be taken into account in assessing spur line viability.
The report also points out that the study’s assessment of industrial processes such as LNG and GTL production assumed the use of current technologies and associated cost profiles. Advances in technology might improve the economics.
The report is available at the Kenai Peninsula Borough’s Cook Inlet oil and gas web site at http://www.cookinletoilandgas.org/.