Nothing has altered the North American natural gas market and its appetite for LNG as severe as the discovery and development of significant unconventional gas sources. Within a couple of years, the supply-demand balance has changed from one of continuous production declines to one of an upcoming surplus.
Rising natural gas prices since 2001, easy financing and technological innovations (i.e., horizontal drilling and hydraulic fracturing) encouraged companies to invest in wells. Amongst others, large deposits were explored with the Barnett Shale and Eagle Ford plays (both in Texas) and the Haynesville Shale (Louisiana). The Potential Gas Committee states in its 2008 assessment report that the US alone might possess a total resource base of 51,200 bcm which would increase the static reserves-to-production ratio from about ten to 90 years. In Canadian British Columbia, the Horn River Shale Basin is estimated to comprise about 14,000 bcm.
The substantial rise in unconventional gas production reversed the historical decline in US gas output reducing demand for LNG. In the early 2000s, researchers still saw North America as a major player in the future LNG market. The EIA regularly adapted its annual energy production and consumption forecasts. In 1999, most domestic production was expected from conventional natural gas with unconventional sources projected to account for not more than 200 bcm in 2020 and LNG imports were forecasted to remain at marginal levels. The 2004 outlook five years later predicted unconventional production to increase to 255 bcm and LNG imports to rise to 140 bcm in 2025. In its latest outlook, future unconventional natural gas production has been adjusted further upwards (340 bcm in 2025 and 400 bcm in 2030) whereas the prospects for LNG imports with 30 bcm in 2030 are less enthusiastic.
The future potential for natural gas production from unconventional sources, however, will mainly be determined by the level of natural gas prices and the development of production costs. Each shale play has its individual geological characteristics; no general statement on the cost structure can be made. Dar (2009) quotes the break-even price at 3.88 USD/MBTU (Eagle Ford), 3.74 USD/MBTU (Marcellus), 4.49 USD/MBTU (Haynesville), and 5.18 USD/MBTU (Barnett). This goes in line with Jensen (2009) arguing that much shale gas could be developed at natural gas price levels of 4 USD/MBTU. Berman (2009), in contrast, argues that only half of the Barnett Shale wells would be economic at prices of 10 USD/MBTU and expects a drop in drilling activities as a response to the lower prices since mid-2008. Whether current production levels can be maintained at prices below 5 USD/MBTU is one of the major uncertainties for the mid-term future.
As a consequence of the increased domestic production, needs for imports declined. For the shortterm, this trend is further amplified by the recent demand downturn due to the economic crisis. US LNG imports dropped in 2008 to 9.9 bcm from 21.8 bcm in 2007. Import terminal operators suffered from idle regasification capacities. The load factor of total North American LNG import capacity fell from 61% in 2004 to 8% in 2008 (see Figure 1). It is very likely that beside the completion of projects already under construction, no significant investments in LNG capacities will be realized in the midterm future. Some LNG terminal operators even have already sought permission from FERC to add export equipment to their facilities. Since North America was expected to be a major growth market for LNG, this development has a severe impact on the future global LNG demand.
Sophia Ruester, Dresden University of Technology