As usual at this time of the year, we update our US price scenario for the next three years. Bullish factors seem to overwhelm bearish factors for the foreseeable future. The only bearish factor is the fact that the steady decline of US domestic production capacity, experienced from 2001 through 2006, seems to have reversed, mainly thanks to unconventional onshore gas in Texas and the Rocky Mountains and the new facilities in the deepwater Gulf of Mexico. According to EIA, total US Dry gas production has increased by more than 4% in 2007, to reach 52.8 bcf/day (1) on average. It is expected to grow also in 2008 (by almost 3%, up to 54.2 bcf/day), as January and February recorded a y/y monthly increase of more than 3 bcf/d. According to the most bullish forecasters, US domestic production could average 55 bcf/d this year. Nevertheless this output increase is the result of tremendous drilling efforts, as more than 1400 rigs have been constantly in activity since January 2007, with a peak of 1,523 units last August. Because of the declining production per well, it is necessary to drill almost three times as many wells today compared to the late 1990s in order to maintain the same production level. Moreover, unconventional production continues to increase its weight in the supply mix. It currently represents more than 70% of the total drilling activity (and roughly 45% of total production) versus 40% in 2003. This trend is clearly being reflected by a dramatic rise of production costs. As of today, we estimate US marginal production costs at 5.1 US$ per MMBtu, up by more than 3 US$ over the last 5 years as a consequence of higher reserve acquisition expenses and more intense unconventional drilling. While US production is doing better than expected, it is not the case for Canadian output. Even though Canadian exports to the Lower 48 have been quite stable so far, the consensus points to a net decline between 0.5 and 0.75 bcf/d in 2008 and a further 0.3 to 0.5 bcf/d in 2009. At the same time, the Lower 48 storage surplus, which has been characterising the last two winter seasons, has progressively disappeared following a slightly more rigid than normal winter, the first in five years. Underground gas stocks are now in line with their 5-year average, while they exceeded the latter by almost 500 bcf in January 2007. Even assuming domestic production at 54.4 bcf/d, US LNG imports should reach at least 557 bcf by the end of October (assuming a +0.5% demand and barring any hurricane outage this summer) to allow once again working gas in storage at 3,400 bcf, a comfortable level for the beginning of the winter season. Unfortunately, US LNG imports have been extremely low in 1Q08, 77 bcf vs. 184 bcf in 1Q07 according to preliminary data. Tighter than expected liquefaction supplies and record oil prices have triggered a rally in Asian LNG prices (see also our Gas Trends "LNG Tension in the Pacific Basin" dated February 2008), much more directly indexed to oil prices than Henry Hub and Nymex quotations. The US$ devaluation is pushing investors into commodities: not only crude oil has reached historical peaks, but also coal (the main substitute to gas for power generation) and emission prices are very strong. Nuclear outages in Japan and drought in Spain are supporting LNG demand for power generation while long awaited new liquefaction supplies from Tangguh, Sakhalin, RasGas III and YLNG, representing altogether almost 40 mtpa, are being delayed from 2H08 to 1H09 and additional supplies from Peru and Qatar expected for 2009 (almost 25 mtpa) are likely to come on stream only in 2010.  In such a context, competition to attract LNG cargoes is likely to remain strong, not only between the Atlantic and the Pacific basin, but also among alternative Atlantic destinations, with NBP and EU continental prices tracking more closely oil price increases than Henry Hub. To sum up, despite the significant increase of domestic production of 1Q08, the US gas market will probably continue to undergo external pressures from record oil prices and LNG supply competition for 2008 and 1H09. Relief from larger liquefaction availability and lower oil prices should come from 2H09. We then expect HH prices to converge towards 7 US$/MMBtu, bearing in mind that rising F&D and production costs are structurally underpinning long term prices.

(1) 1 bcf/day = 10.3 bcm/year; 1 mtpa = 1.38 bcm/year     May 2008   Click the link in the left download box to read more.   The information published in this document has been obtained from public sources believed to be reliable. BNP Paribas does not make any representation or warranty, express or implied, in connection with the accuracy of the opinions or statements contained herein. The information provided by this document is only indicative, not to be relied upon as substitution for the exercise of judgment by any recipient, and subject to change without notice. BNP Paribas shall not accept any liability whatsoever for any direct or consequential loss arising from any use of material contained in this document. This document is not intended as, and does not constitute, an offer or a solicitation to buy or sell any instrument or to enter into any transaction. Any reference to past performance should not be taken as an indication of future performance. This document should not be reproduced (in whole or in part) without BNP Paribas’ written consent. © BNP Paribas (2008). All rights reserved.