With hints of rising prices on the horizon, 24 leading natural gas marketers had total transactions of 135.07 Bcf/d in 1Q2011, a 2.49 Bcf/d (1.9%) increase from the 132.58 Bcf/d they transacted in the year-ago period, according to NGI‘s 1Q2011 Top North American Gas Marketers Ranking.
BP plc remains at the top of NGI‘s marketers survey, despite an eighth consecutive quarterly decline compared to the year-before period, and ConocoPhillips leapfrogged Shell Energy North America to move into the second spot in the survey. BP reported physical sales of 24.70 Bcf/d in 1Q2011, down 16% from 29.40 Bcf/d in 1Q2010. The last time BP reported a quarter-to-quarter increase was 1Q2009, when it reported 31.80 Bcf/d, a 17% increase compared with 1Q2008. BP’s physical sales peaked at 32.50 Bcf/d in 4Q2008.
Shell also reported a decline in 1Q2011, down 19% to 13.90 Bcf/d from 17.20 Bcf/d in 1Q2010. That decline, combined with ConocoPhillips’ 15.40 Bcf/d — a 9% increase from 14.10 Bcf/d in 1Q2010 — reversed the rankings of the two energy giants in the NGI survey.
A significant increase was reported by JP Morgan (7.26 Bcf/d, up 79% compared with 4.06 Bcf/d in 1Q2010), which acquired RBS Sempra Commodities’ wholesale natural gas marketing and trading unit late last year (see NGI, Dec. 6, 2010). RBS Sempra, which had reported 6.51 Bcf/d in 3Q2009, exited the survey in 3Q2010.
It was also a positive quarter for ExxonMobil Corp., which reported 4.37 Bcf/d, a 130% increase from 1.90 Bcf/d in 1Q2010. Unconventional gas volumes drove the increase, the company said. The Barnett, Fayetteville and Marcellus shales will increasingly belong to big players like ExxonMobil, according to one energy industry financier, who recently said only the majors can bring low-cost capital, large staffs and the ability to capture the economies of scale inherent in shale plays (see NGI, May 30).
Goldman Sachs commodity trading subsidiary J. Aron & Co. joins the NGI survey this quarter with 3.89 Bcf/d. The company purchased Nexen Inc.’s North American downstream natural gas marketing business last year (see NGI, May 17, 2010).
After an extended period of low prices the market has edged up in recent weeks, and there may be even better news ahead for producers, according to Ken Medlock, an energy and resource economics fellow at Rice University’s Baker Institute.
“Most people don’t see this low-price environment as one that’s going to persist for a long, long time,” Medlock told NGI. “A lot of people, I think, do see a little bit of a recovery, and if we do get into the $5-6 window, that’s a healthy enough price for a lot of producers to survive at pretty robust production levels. And that price won’t be too high to discourage demand, either — that makes that $5-6 window almost magical. You could still displace a lot of old coal…people aren’t going to start bailing out of the gas industry just yet. They’re going to weather the storm, so to speak.”
While gas prices are softer than they were last year, producers can look forward to some firming next year, according to the Energy Information Administration (EIA), which said Tuesday it expects slowing growth in production to contribute to a tightening domestic market next year, with the Henry Hub price averaging $4.58/MMBtu in 2012 (see related story).
Source: Quarterly financial reports with the Securities and Exchange Commission, or if necessary, statements signed by company officials and provided to NGI. Some previous-year data has been updated by the companies since it was originally reported.
Companies providing data directly to NGI include Bank of America Merrill Lynch, BP, Chevron, Citigroup, ConocoPhillips, EDF Trading NA, J. Aron & Co.; Gazprom, JP Morgan, Louis Dreyfus, Macquarie Energy, Shell Energy and Tenaska. *Macquarie Energy data reflects Macquarie Energy LLC’s transactions in the U.S. and Macquarie Energy Canada’s transactions in Canada. **The gas volume figures for Apache, Chesapeake, Devon, EnCana and ExxonMobil represent the amount of North American gas produced in the quarter. Those companies may be marketing more third-party gas for sale. ***J. Aron & Co. is the commodity trading subsidiary of Goldman Sachs.
An explosion of production out of the nation’s shale plays has had a significant effect on the market, according to Medlock, who said lower prices have in turn had their effect on producers’ approach to the shale plays.
“There has been a lot of redirection of the horizontal fleet toward the liquids-rich parts of shale plays — in the Niobrara, the Bakken, the Eagle Ford — so there is a lot of using oil to pay for the gas, so to speak. When you have oil prices sitting where they are and you have your lighter products that are indexed to oil in general, and gas trading so cheaply, if you can produce more of those liquids, then you’re going to be much better off. The gas is sort of like a byproduct almost in the production process.
“The other thing that’s going on, quite frankly, is producers are getting smarter about their operations in shale. So you’re seeing higher initial production rates associated with the fracks that are being done, you’re seeing longer laterals, more multi-stage frack jobs — a lot of these things are just increasing the productivity of the wells, and altogether that brings down the cost of production so you can survive in a lower-price environment. But there’s still some stress in the market,” as evidenced by Chesapeake and other companies selling some shale assets (see NGI, Feb. 14).
And while shale plays have been grabbing most of the energy headlines, traditional drilling still accounts for the majority of gas production, Medlock said.
“There’s still a lot of production that’s not coming from shale. Shale is something on the order of 15% of total North American production right now. So you still have to think about coalbed methane, tight sands, conventional plays — and that includes gas that comes from offshore — imports from Canada, which are falling but are still substantial. So there are a lot of things that are still in the mix.”
Highlights of NGI‘s 1Q2011 survey include a 36% increase for EDF Trading NA (6.98 Bcf/d, compared with 5.14 Bcf/d in 1Q2010), an 18% increase for Sequent (5.80 Bcf/d, compared with 4.90 Bcf/d in 1Q2010), a 20% increase for Citigroup (2.65 Bcf/d, compared with 2.20 Bcf/d in 1Q2010), a 33% increase for Southwestern Energy Co. (1.59 Bcf/d, compared with 1.20 Bcf/d in 1Q2010) and a 52% increase at Apache (1.50 Bcf/d, compared with 0.99 Bcf/d in 1Q2010).
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