The record pace of drilling in Canada has finally started to pay off. Canada’s National Energy Board (NEB) reported that natural gas exports to the United States through February of this year were up 1.3% to 626.5 Bcf, or about 10.44 Bcf/d, compared to 618.7 Bcf, or 10.31 Bcf/d, over the same period in 2003. The NEB said the biggest volume increase was to the California market where exports jumped 23%. Volumes to the Pacific Northwest rose 15%. Exports to the Northeast and Midwest fell by 7% and 0.8%, respectively. Gas exports in the month of February totaled 303.7 Bcf compared to 291.7 Bcf in February 2003. During 2003, exports fell to 3.5 Tcf, their lowest level since 1999 when exports were 3.37 Tcf. The U.S. Energy Information Administration expects gross pipeline imports to fall this year to 3.28 Tcf from 3.42 Tcf in 2003. Meanwhile, Lehman Brothers analyst Thomas Driscoll said on Tuesday that he expects Canadian gas production to rise 1.2% this year to 16.6 Bcf/d. Driscoll said first quarter Canadian production was flat at 16.5 Bcf/d based on a survey of 14 major gas producers.

ExxonMobil Canada plans to provide $1 million for research and development for Atlantic Canada through the Petroleum Research Atlantic Canada (PRAC), which fosters building capacity in the region’s oil and natural gas industry. ExxonMobil is a partner and operator of the Sable Offshore Energy Project (SOEP) near Nova Scotia and also has interests in Hibernia and Terra Nova developments in Newfoundland. PRAC is a federally incorporated, not-for-profit, public-private partnership that began operations in 1999. PRAC’s members are drawn from academia, federal and provincial governments and industry. The $1 million grant over the next five years is in addition to an earlier $1.25 million grant in 1999 by ExxonMobil, which was a founding member of PRAC.

Williams has set the terms for a $1.1 billion tender offer as part of a long-range plan to trim $4 billion of its $11.3 billion debt by the end of 2005. Williams, which is refocusing on its natural gas production and pipeline operations, is offering to purchase all of its $114 million debt in 6.6% notes due Nov. 15, and up to $1 billion of other notes that mature in 2006 through 2009. The tender offers are scheduled to expire June 8. Some of the outstanding notes were originally issued by Barrett Resources Corp., Williams Holdings of Delaware Inc. and MAPCO Inc. Williams purchased Barrett Resources in 2001 for $2.5 billion, now a subsidiary known as Williams Production RMT Co. In connection with the offer for 7.55% senior notes due in 2007 that were originally issued by Barrett, Williams Production wants to eliminate most of the restrictive covenants and certain default provisions that are part of the original note. Williams has retained Lehman Brothers Inc. to serve as the lead dealer manager.

Birmingham, AL-based producer Energen Resources increased its hedge position to include another 3.6 Bcf of gas production at a price of $6/MMBtu and 240,000 bbl of sour crude at an average Nymex price of $33.98/bbl. The company now has prices locked in for 41% of its 2005 gas production and 40% of its 2005 crude oil production. Energen’s total gas hedge position for 2005 now stands at 21 Bcf out of a total of 51.2 Bcf at $5.36/Mcf. The gas hedges include 4.8 Bcf of contracts at a Nymex futures price of $5.45/Mcf, 15.5 Bcf of San Juan Basin-specific contracts at an average Nymex-equivalent price (including basis) of $5.33/Mcf, and 0.6 Bcf of Permian Basin-specific hedges at a Nymex-equivalent price of $5.62/Mcf. Energen’s 2005 oil hedge position now totals about 1.4 million bbl at an average of $32.05/bbl. Energen also has hedged 30.2 million gallons (43%) of its 2005 natural gas liquids production at an average price of 48.5 cents per gallon. The company estimates that the most significant basis differentials in 2005 will equal 80 cents per Mcf for San Juan Basin gas, 35 cents per Mcf for Permian Basin gas and $2.90 per barrel for Permian Basin sour oil. These assumed basis differentials have been used to calculate the Nymex-equivalent prices of its basin-specific gas and sour oil hedges for 2005.

Following much bigger gas cost rate changes in the two previous years, Intermountain Gas, a natural gas distribution company in southern Idaho, has asked state regulators for a $22.1 million, or 10%, boost in rates, effective July 1. The Idaho Public Utilities Commission has asked for comments on the annual purchased gas adjustment (PGA) by June 11. The PUC is seeking comments “not only regarding the reasonableness of the proposed rates, but also on the question of whether Intermountain’s annual PGA adjustments should be processed closer to the winter heating season,” a regulatory commission spokesperson said. Serving 230,000 customers, Intermountain was granted a 33% increase and 28% decrease in annual PGA rate changes in 2003 and 2002, respectively. Whenever purchased gas costs drop lower than projected, customers get decreases, and unlike general rate increases, there is no increase in earnings for the PGA changes, the PUC spokesperson said. Last year’s 33% hike was not felt by customers until “well into the winter heating season,” the spokesperson said, prompting the regulators this year to seek stakeholder/customer comments on whether to move the PGA to the fall to “improve the effectiveness of customer price signals and promote greater customer interest.” The later proceeding might also result in more accurate wholesale gas price forecasts, the spokesperson said.

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