Despite significant differences in the amount of natural gas marketed by individual companies and the effects of some major acquisitions, there was a 7.6 Bcf/d increase in the total amount of natural gas transacted by the 24 marketers that participated in both NGI’s 3Q2010 Top North American Gas Marketers Ranking and NGI‘s 3Q2009 survey.
Those 24 marketers reported 135.01 Bcf/d in 3Q2010, a 6% increase from the 127.41 Bcf/d posted in 3Q2009. Citigroup, which reported 2.12 Bcf/d in 3Q2010, did not participate in the survey in the year-ago period.
While still the top marketer in the survey, BP plc reported physical sales of 25.10 Bcf/d, an 11% decline from 28.10 Bcf/d in 3Q2009. The embattled energy giant, which also reported a significant decline in NGI‘s 2Q2010 survey, continues to recover from the Macondo well blowout in the deepwater Gulf of Mexico (GOM) earlier this year.
BP’s GOM assets remain a solid part of the company’s portfolio, but it is in no rush to restart operations there (see NGI, Nov. 8). Once the Bureau of Ocean Energy Management, Regulation and Enforcement has smoothed its permitting procedures and companies restart their offshore GOM drilling operations, BP management will decide what to do with the drilling rigs that now are idled, said CEO Bob Dudley.
Shell Energy North America (US) LP remains second in the NGI survey with a 2% increase to 15.40 Bcf/d in 3Q2010 compared with 15.10 Bcf/d in 3Q2009, and ConocoPhillips reported 15.20 Bcf/d in 3Q2010, a 3% increase compared with 14.80 Bcf/d in 3Q2009.
Robust production — bolstered by burgeoning shale output — in combination with historic gas storage numbers and continuing low prices, paint a picture of a dynamic but volatile natural gas market, according to Houston Energy Partners co-manager John Olson.
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 BP, Chevron, Citigroup, ConocoPhillips, EDF Trading NA, JP Morgan, Louis Dreyfus, Macquarie Energy, Bank of America Merrill Lynch, Shell Energy and Tenaska. *Macquarie Energy data reflects Macquarie Energy LLC’s transactions in the United States 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.
“Natural gas has great promise over the next five to 10 years, but over the next two years things are going to be volatile and tricky,” Olson told NGI. From an investor’s point of view, the business is “chronically overfunded by Wall Street, and it is overdrilled as a result,” he said.
Working gas storage, which stood at 3,814 Bcf at the start of the winter heating season, is expected to be 1,833 Bcf at the end of March 2011, according to the Energy Information Administration, which based its estimate on a projected 3.1 Bcf/d increase in production and 5% fewer heating degree days over the next four months compared with the year before (see NGI, Dec. 13a).
A well saturated market and sustained drilling has led energy analysts to cut price forecasts for U.S. natural gas in 2011. Bank of America Merrill Lynch recently reduced its price outlook to $4.60/MMBtu from $5.00 (see NGI, Dec. 13b). Deutsche Bank’s chief economist said prices may not reach $6/Mcf before 2015 (see NGI, Nov. 22) and Goldman Sachs cut its 2011 price forecast to $4/MMBtu from $5.25 (see NGI, Dec. 6a).
For the week ending Dec. 17, the number of rigs searching for gas in the United States declined by 7 from the week before to 941, according to the Baker Hughes Rotary Rig Count.
“We have again overachieved, with the rig count staying in the 925-975 area, when the consensus opinion is that you really need maybe 600-700 rigs to really sustain deliverability,” Olson said.
And the search is still on for the demand needed to siphon off that gas. There hasn’t been any significant uptick in industrial demand and opening the transportation fuel market to natural gas “is a very noble task, but it is minuscule in the overall demand profile,” Olson said.
“The great hope has always been for further additions of combined-cycle gas-fired power plants. Those have to come through regulated channels; you need to get an approval from somebody somewhere to be a new gas-fired power plant, and the demand has to be there as well. There is momentum there — no ifs, ands or buts, because people are backing out coal-fired plants in Ontario and in the states — but will this fill the gap this year? I’d say it’s unlikely.”
The flood of natural gas coming out of the United States could have the unintended consequence of creating a value trap for Canadian producers, Olson said.
“They’re going to be trapped inside their own high pipeline tariffs and may be invaded by production coming in from the Marcellus, with the possible reversal of lines like Iroquois [Pipeline Inc.] and Empire [Pipeline].” The Federal Energy Regulatory Commission in September approved requests from Iroquois and Empire to export gas to Canada (see NGI, Sept. 20).
“The tariff structure in Canada has become so high-cost that it makes no sense to drill a gas well up there for the foreseeable future,” Olson said. “The other problem is that you have the Ruby Pipeline going from Opal to the California-Oregon border. That’s going to be 1.5-2 Bcf/d, so that’s going to compete with Canadian gas as well. You have a battleground developing there. Unless this market grows legs really quickly in the next year, we’re likely to have some fairly noticeable gas-on-gas competition” (see related story).
NGI‘s 3Q2010 survey was highlighted by significant changes at three companies.
XTO Energy Inc., which had reported 1.42 Bcf/d in 3Q2009, was acquired by ExxonMobil Corp. late last year (see NGI, Dec. 21, 2009). The $41 billion deal was closed June 25 and volumes from the former XTO helped ExxonMobil achieve 4.28 Bcf/d in 3Q2010, more than doubling the 1.94 Bcf/d it reported in 3Q2009. In contrast, ExxonMobil reported declines in every non-North American market in which it operated in 3Q2010.
RBS Sempra, which had reported 6.51 Bcf/d in 3Q2009, exited the survey in 3Q2010, “due to the unwind of Sempra’s business during that time and the current sale of the business to JP Morgan,” an RBS Sempra spokesman told NGI. Work was recently completed on the sale of the last key North American assets in RBS Sempra Commodities (see NGI, Dec. 6b). The assets are now owned by J.P. Morgan Ventures Energy Corp., a unit of JP Morgan Chase & Co. JP Morgan reported 5.14 Bcf/d in 3Q2010, a 36% increase compared with 3.79 Bcf/d in 3Q2009.
Nexen Inc., which earlier this year agreed to sell its North American downstream natural gas marketing business to Goldman Sachs commodity trading subsidiary J. Aron & Co. (see NGI, May 17), reported 1.80 Bcf/d in 3Q2010, a 63% decline compared with 4.90 Bcf/d in 3Q2009. Nexen also reported a double-digit percentage decline last quarter — 3.10 Bcf/d in 2Q2010, a 33% decline compared with 4.60 Bcf/d in 2Q2009.
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