ExxonMobil Corp., the largest natural gas producer in North America, is well aware of the economics in drilling U.S. and Canadian dry natural gas wells today. But it has no plans now to shut in any gas wells, the investor relations chief said last week.
David Rosenthal, who spoke with financial analysts during a conference call to discuss quarterly and year-end earnings, said instead of ramping up gas wells, more rigs now are targeting liquids-prone targets. However, delineation and appraisal work will continue in several gassy onshore plays.
“As you all know, due to record production and storage levels — and a relatively mild winter to date — prices have weakened recently,” Rosenthal told analysts. “I can tell you that we have not curtailed any gas production. We have 65 to 70 rigs across the space.” But “a substantial number” has been shifted in the past year.
“We remain bullish on the future of natural gas as an energy source,” Rosenthal said. He reminded analysts that in December ExxonMobil published “Outlook for Energy: A View to 2040,” which forecast that gas would make the biggest global gains in energy demand (see NGI, Dec. 12, 2011). “As you know, we are bullish on the demand side for natural gas as a resource in the United States. Given the steep decline in conventional gas, unconventionals will lay a dominant role going forward. In that regard, we’re very pleased with our unconventional portfolio and we plan to be a major participant in the space.”
Rosenthal didn’t give specific details on how many dry gas rigs continue to be used in North America nor did he break down the number of rigs percentage-wise that are drilling for liquids versus gas. More details are expected during an investor conference in March.
“The overall size of the fleet is the same,” he told analysts. “We are still drilling dry gas wells. A few of those are required for at least maintenance and other contractual obligations. We are drilling those [dry gas wells] that provide good economics. We have a drillable inventory [in North America] of over 40,000 wells. We want to be able to put those things in order and have significant optionality to drill them and to be able to maximize the resource over time…We’re focused on the long term and making adjustments to higher-value, higher-margin products.”
ExxonMobil’s exploration and production profitability in the United States was impacted by the decline in gas prices. However, the company continued to make efficiency gains in its gassy portfolio, most of which it acquired about two years ago when it bought shale king XTO Energy Inc. (see NGI, Dec. 21, 2009). The merger moved ExxonMobil to the top of the gas pyramid in North America.
“Some of the objectives we set out at the time of the merger are coming to fruition,” said Rosenthal. “We are seeing an improvement in capital efficiency, reductions in operating expense and improved productivity on wells, from pad spacing, to length of laterals, to how we lay the laterals…A number of engineering and technical expertise that we brought to the table is paying off. From that standpoint, we are progressing well. But at the end of the day profitability on a book basis certainly was impacted by the price trend we saw at the end of the year.”
The move to liquids plays didn’t dent in ExxonMobil’s quarterly or year-end gas production numbers. In fact, U.S. gas output was up by more than 1 Bcf/d in 2011 from 2010.
U.S. gas output averaged 4 Bcf/d in the final quarter of 2011, which was slightly higher from the 3.9 Bcf/d in the year-ago quarter. For the year domestic gas production averaged 3.9 Bcf/d, versus 2.6 Bcf/d in 2010. Worldwide, the Irving, TX-based super major’s average gas output fell to 13.67 Bcf/d in 4Q2011, which was down 975 MMcf/d from 14.65 Bcf/d reported in 4Q2010. Annual production averaged 13.16 Bcf/d, more than 1 Bcf/d higher than the 12.15 Bcf/d reported in 2010.
The shift to liquids targets should show up in the production numbers by the end of this year, said Rosenthal. “We’re really figuring out what we’ve got and figuring out the best way to optimize the total over the long period of time as opposed to being in a big hurry,” he said. ExxonMobil wants to determine field sizes, where the sweet spots are, and where to go first to optimize development.
“We probably spend more time than others working on front-end design but we are focused on the long-term value out of that. That’s front-end investment in time and resources. Even as we are doing some of the delineation and appraisal wells, we are seeing some efficiency gains as we go from one area to another. We’re not starting out from scratch…”
ExxonMobil is focusing on unconventional liquids targets in several places across the United States and in Canada. Among them are the Woodford Ardmore, Bakken Shale, the Permian Basin in West Texas and the Cardium formation in Canada.
“A lot of our drilling has been delineation in nature; a lot of wells are not online yet for production,” Rosenthal said. Other unconventional areas in North America that continue to be tested include the Utica Shale. “We do have one well going down [in the Utica] as we speak,” Rosenthal said. “The acreage position is about 75,000 acres today and we are looking forward to working on that…”
In the gassy Horn River Basin of Canada, where ExxonMobil is the largest leaseholder, a drilling program “is planned for this year, about the same as we had last year, and again related to evaluation and delineation as opposed to production…We’ll have about two to three wells, which is typical of what we’ve been doing.”
Asked if ExxonMobil had been working on any plans to monetize the Canadian gas for liquefied natural gas export, Rosenthal said he didn’t have “specific information to provide other than with a resource potentially as large as that, we are exploring all options out there and will continue to do so…”
It’s unlikely the North American rig count will be increased this year, despite early indications of success in the emerging liquids plays.
“I think it’s reasonable to expect to see us expand our focus on liquids and liquids-rich plays, particularly in areas where we’ve had good initial success and we look forward to bringing on more wells there,” said Rosenthal. “We’ll see how the year progresses.”
The company earned $9.4 billion in 4Q2011, which was 2%, or $150 million, more than in the year-ago period. However, profits were down from 3Q2011, when it earned $10.3 billion a 41% jump from 3Q2010. Full-year 2011 profits were up 35% year/year to $41.1 billion, “reflecting higher crude oil and natural gas realizations, improved refining and chemical margins, and gains on asset sales,” said CEO Rex Tillerson.
ExxonMobil spent $10 billion for capital and exploration activities in the final three months of 2011, which was about the same amount it spent in the final quarter of 2010. Cash flow from operations and asset sales in the final period totaled $17.6 billion, including proceeds associated with asset sales of $6.9 billion. Share purchases to reduce shares outstanding were $5 billion. Upstream earnings were $8.8 billion, up $1.35 billion from the fourth quarter of 2010. Higher liquids and natural gas realizations increased earnings by $1.99 billion. U.S. upstream earnings totaled $1.18 billion in 4Q2011, which was $133 million lower than in 4Q2010. Non-U.S. upstream earnings were $7.6 billion, up $1.48 billion from a year earlier.
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