U.S. exploration and production (E&P) companies are laying down natural gas rigs at a faster clip than in previous down cycles, and the gas rig count is on pace to fall by almost two-thirds from last year, energy analysts said last week. Still, some analysts and producers fear that dropping rigs won’t be enough to balance the oversupplied gas market by the end of 2009.
Just last week some of North America’s biggest gas producers — Devon Energy Corp., EOG Resources Inc., Anadarko Petroleum Corp. and XTO Energy Corp. — all announced they would reduce their onshore rig count (see related stories). Junior independents are struggling, too. Gasco Energy Inc. plans to release its only rig later this month and pay a hefty early termination fee (see related story).
The energy team at Raymond James & Associates Inc. two months ago had forecast that the total U.S. oil and gas rig count would fall around 40% year-over-year, or by around 850 rigs (see NGI, Dec. 15, 2008). Now that eight-week-old forecast is looking positively rosy. Last week analysts J. Marshall Adkins and John Fitzgerald predicted that 60% of U.S. oil and gas rigs would come down this year, with gas rigs responsible for 65%, or 1,035, of the cuts. Oil rigs, they said, are likely to fall by half, or by 1,220.
“Our new estimated bottom for the U.S. rig count should be around 800 rigs with the bottom being early fourth quarter,” the Raymond James duo wrote. “As far as annual averages are concerned, we are now looking for a 45% reduction in [total U.S. rigs in] 2009 followed by another 11% reduction in 2010. Too harsh, you say? Our 800-rig bottom is still 60% higher than the 1999 (508 rigs) downturn and 10% above the 2002 (738) bottom. That means that our new estimates may still be too high considering that the U.S. natural gas oversupply problem will likely not be solved in 2009 and customers should still be dropping rigs late into the year.”
The rig count overview put together by Raymond James two months ago was based on “two very generous assumptions,” said Adkins and Fitzgerald. “These assumptions were: (1) every rig is equally productive; and (2) a rig count decline would occur equally across all regions and drilling types. Obviously that is not going to happen. Producers will stop drilling their least productive, least economic wells first. When we account for the highly productive shale wells and consider that horizontally drilled wells (the most productive) are being dropped from drilling programs at a much slower rate, we find that gas production will probably not fall as fast or as far as the rig count (in percentage terms).”
Baker Hughes Inc. CEO Chad Deaton told analysts during an earnings conference call in January that the use of advanced technologies and the unconventional gas plays caused North American production output to exceed demand growth in 2008. Now, he said, the recession has impacted “demand and reduced access to capital has resulted in activity and spending cuts by our customers.
“Operators are now cutting their budgets in order to live within their free cash flow. Drilling is already down 25% from peak levels with the Rockies, Southern and Central areas of the U.S. being hit hardest. Vertical drilling is down 33% from peak. In comparison to historic downturns, today we are experiencing a steeper decline in the rig count than we saw in the four prior cycles. The unconventional gas rigs in place have fared the best so far with horizontal drilling activity falling only 10% from peak…
“North America has clearly been the first to feel the effects of the global recession and lower commodity prices,” said Deaton. “The North American rig count averaged 1,879 rigs for 2008 and peaked at 2,031. The average rig count in 2009 could be down 25% to 30% compared to the 2008 average or an average of about 1,300 to 1,400 rigs compared to the 1,879 we saw in 2008.”
From its peak in October, “the market has dropped roughly four vertical rigs for every one horizontal rig,” the Raymond James team noted. “Additionally, recent activity data points indicate that the rig counts in unconventional plays (which typically have the highest well productivities) are holding up much better than the total fleet average. For example, total shale drilling is down only 10% on average since the peak, compared to 30% for the rest of the rig count. Unfortunately for the gas markets, this means these first rigs that have been laid down will likely have less of an impact on production as producers high-grade their prospects…”
Newfield Exploration Co. is just one example of how much of a game changer unconventional gas drilling has become. The Houston-based producer on Friday reported that its Woodford Shale play in the Arkoma Basin of Oklahoma will produce 30% more gas this year than in 2008 — even though it will run fewer rigs. The jump in output is expected to result from longer laterals, which may yield higher initial production rates, more recovery per well and improved finding costs, Newfield said.
Rocky Mountain producers have seen low gas prices for a long time — and now demand destruction has exacerbated the problems.
“It’s tough in the Rockies,” said John Campbell, a spokesman for Wyoming-based Double Eagle Petroleum Co. “Here we are in the middle of winter, and gas is only in the $3s. True, we haven’t had much of a winter out here but even in Chicago — where it’s been really cold — gas is under $5. And this might be as good as it gets” with the economy slumping.
Double Eagle operates in two of the lowest-cost areas of the Rockies, the Pinedale Anticline and the Atlantic Rim, Campbell told NGI. “We also have 65-70% of our production that is being sold under various hedging contracts that bring us $6.50-7 on average. Still, those hedges won’t last forever for us or for the other producers out here.”
At those kinds of prices, “I think most drilling in the Rockies will come to a halt,” Campbell said.
In the Barnett Shale of North Texas, the total rig count has fallen more than 25% already — to around 132 rigs from last year’s high of 182, said analysts at Tudor, Pickering, Holt & Co. LLC.. If prices remain low, more cuts are likely, said the analysts.
“A number of small/midcap E&P companies with Barnett acreage have drilling rig commitments that are take or pay,” wrote the Tudor team. “Rather than get nothing for something (by canceling contracts and paying off rig contractors), many players are drilling wells, but deferring the completion of the well. Why? First, the completion cost is often just as much (or more) as the drilling cost (this is big dollars in a cash-constrained world). Second, there is not likely any significant reservoir damage to leaving the well uncompleted for a while (no harm done). Third, high initial production rates and steep declines say that 10% of a Barnett well’s production comes in the first six months (and more like 15-20% of the economics).
“And the current gas strip through 2009 doesn’t have a single month over $6.40/Mcf. So waiting for better prices actually does make sense…We ‘guesstimate’ that the current inventory of drilled-but-uncompleted Barnett wells is 300…and could be 400+ by the end of 2009.”
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