U.S. drilling hits a plateau

WORLD OIL STAFF

North Dakota’s Bakken shale has propelled that state to being the second-largest oil producer in the U.S. Photo courtesy of Enerplus Corp.

Weakness in crude oil prices, coupled with uncertainty about the presidential election and future economic performance, has caused U.S. drilling to go sideways. A trend was already present at the beginning of this year, whereby operators were steering large amounts of capital spending away from dry gas drilling. This factor has now been exacerbated by such a shift toward oil and NGL-directed drilling, that it has boosted liquids production fast enough to depress liquids prices in the short term.

Now that oil prices have cooled a bit from their formerly lofty heights, it appears that our initial 2012 U.S. drilling forecast, issued at the end of January, was a little too optimistic. Accordingly, we have pared back our estimate of the U.S. total for this year by about 1,700 wells. There was real concern in the oil patch, when the futures price for WTI crude fell below $80/bbl in late June and stayed there for several days. However, prices rebounded in the back half of July and were hovering near $90/bbl as this issue went to press.

It is our belief that, as long as oil prices remain above $80/bbl for the remainder of this year, operators will, by and large, fulfill their drilling plans. Also, given the competitive situation that is present in the shale plays featuring strong, liquids-driven activity, there will be some companies that will keep their drilling levels elevated, so that they can hold onto leases. Interestingly, natural gas futures prices, which had tanked and gone below $2.00/MMbtu during the spring, have mounted a minor comeback, rising above $3.00/MMbtu in mid-summer. Whether this trend holds, and whether it is enough at some point to stimulate greater amounts of gas-directed drilling, remains to be seen.

As we go through the remainder of 2012, World Oil’s forecast indicates the following:

• U.S. drilling will increase a further 5.7%, rising from 22,482 wells in first-half 2012 to 23,770 in the second half
• On a year-to-year basis, U.S. drilling will be up only 1.5% from 2011’s figure (45,558 wells) at 46,262 wells; this compares to our original forecast of 47,918 wells
• Due to more horizontal wells and greater footage per well, the amount of footage drilled in 2012 will grow at a higher rate than the well count, totaling 327.6 million ft of hole, up 2.6% from the 319.3 million ft drilled in 2011
• The U.S. rig count during second-half 2012 will not grow  measurably above the first-half rate of 1,981 rigs.

U.S. prices. A lot of the reasoning that went into price predictions at the beginning of this year has gone out the window. Back in February 2012, when we assembled our original forecast, the U.S. Energy Information Administration (EIA) was predicting that crude oil prices would average $100/bbl, up $6/bbl from 2011’s figure. EIA had also predicted that the average 2012 Henry Hub natural gas spot price would be $3.35/MMBtu, down about $0.65/MMBtu from the 2011 average spot price. Neither of these predictions has held up.

In fact, on the oil side, EIA has been wrong consistently throughout this year. An extremely optimistic EIA discussion of the agency’s February price predictions said that there was about a one‐in‐15 chance that the average WTI price in June 2012 would exceed $125/bbl, and about a one‐in‐50 chance that it would exceed $140/bbl. For 2013, EIA had expected WTI prices to continue to rise, reaching $106/bbl in the fourth quarter. All of these predictions have now proven to be one giant Fantasyland (apologies to Disney).

To be fair to EIA, the agency has been forced to take its marching orders from the Obama White House, where reality and accuracy of data are seldom consulted. Parroting the administration talking points, EIA based its original forecast this year on an assumption that U.S. real gross domestic product (GDP) would grow by 2.0% in 2012 and 2.4% in 2013, while world real GDP (weighted by oil consumption) would grow by 2.9% and 3.7% in 2012 and 2013, respectively. These predictions have become laughable, as second-quarter GDP growth slowed to 1.5% from 2.0% in the first quarter, and 4.1% in fourth-quarter 2011. That’s about half the growth rate that economists would expect in a healthy recovery several years after a recession ends. The economic performance in Europe has been equally dismal.

Declining growth occurred mainly because consumers reduced spending, and businesses invested at a slower pace. That, in turn, put a lid on oil demand. With recent data showing further weakness in the economy, there’s little reason to think that growth will accelerate anytime soon, thereby keeping the lid on oil consumption. Oil prices will be limited further by the emphasis on liquids-directed drilling, which has pushed U.S. output higher and backed out some imports.

Since EIA’s original February forecast, analysts at the agency have had to backpedal several more times. The latest version of their price forecast, issued in mid-July, now calls for the West Texas Intermediate (WTI) crude oil spot price to average about $88/bbl over second-half 2012 and the U.S. refiner acquisition cost (RAC) of crude oil to average $93/bbl. Both figures are about $7/bbl lower than EIA’s predictions just a month earlier (June). EIA also expects WTI and RAC crude oil prices to remain roughly at these second-half levels during 2013. In addition, EIA is now providing a forecast of Brent crude oil spot prices. They are expected to average $106/bbl for 2012 and $98/bbl during 2013. In light of recent economic data, it is surprising that EIA continues to stubbornly insist on basing the Brent forecast on the assumption that world oil-consumption-weighted real GDP grows by 2.9% in 2012. The agency has cut its 2013 figure from 3.7% to 2.9%, as well.

U.S. rig count. The Baker Hughes U.S. rotary rig count stood at 1,924 on July 27, up less than 1% from the 1,908 figure recorded during the same week in 2011. For the first seven months of 2012, the U.S. rig count averaged 1975.7, an increase of 10.3% from the average of the same period in 2011. Whereas the U.S. count was still rising at this time last year, it has hit a plateau and even declined mildly during the summer. It is our belief that based on operator surveys (see the next section), there will be some recovery in the U.S. count, as summer ends and the industry heads into autumn. However, we do not expect the rig count to go substantially higher than the first-half average, hence our estimate of a second-half well total not much larger than that of the first six months.

During the first week of January 2012, the split between oil- and gas-directed drilling was 59.3%/40.4%. By the last week of July, that ratio had widened to 73.6%/26.2%. In the 25 years of record-keeping on this split that Baker Hughes has available, this margin in favor of oil is unprecedented.

U.S. operators’ survey. The mid-year version of World Oil’s operator survey includes 10 major U.S. drillers (integrated companies and independents with large drilling programs) and 75 small and medium-sized independents. Together, these two groups will account for 5,753 wells drilled this year, or 12.4% of the revised U.S. total that we forecast for 2012. In terms of first-half activity vs. the second half of the year, the major drillers plan to drill 2,614 wells, or 24.7% more than the 2,096 wells that they drilled in the first half. The major drillers’ wildcats will increase 78.5% in the second half to 232 wells, or about 9% of total drilling. The major drillers will also boost horizontal wells 21% above the first-half level, to 1,423. As one might expect, oil wells outnumbered gas wells 1,290 (61.5%) to 806 (38.5%) in the first half, and that margin will widen to 1,896 (72.5%) oil wells vs. 718 (27.5%) gas wells in the second half.

Among small and medium-sized independents, our sample group drilled 476 wells in the first half, and they plan 567 wells in the second half, for an increase of 19.1%. Independents expect to boost wildcat drilling by a healthy 49.5%, from 97 in the first half to 145 in the second half. The smaller operators will also drill more horizontal holes in the second half, increasing that total 21.6%, to 180 vs. 148 in the first half. It should be noted that in our sample group, less than half of smaller independents’ drilling is with horizontal wells, whereas horizontal completions account for well over 50% of activity by major drillers. Among the smaller operators, oil wells (362 or 76.1%) outnumbered gas wells (114 or 23.9%) in the first half by about three-to-one. That ratio will remain nearly constant in the second half, as independents drill 422 oil wells (74.4%) vs. 145 gas wells (25.6).

State-by-state highlights. As alluded to earlier, oil is now king among operators. Not since the halcyon days of the late 1970s and early 1980s has the oil-directed share of total drilling been this high. In addition, prompted by, but not exclusive to, significant activity growth in the two leading shale plays, the Bakken and Eagle Ford, the use of horizontal wells has increased. Accordingly, the amount of footage drilled per well has increased. This is addition to a trend in recent years, in which vertical wells were being drilled deeper. Suffice to say, it’s a good year for drill pipe and casing manufacturers.

In Texas, there are two major centers of drilling activity driven by oil-directed projects, the Eagle Ford shale of South Texas and the Permian basin of West Texas. The Eagle Ford principally covers Railroad Districts 1, 2 and 3. Combined, those three districts should see drilling increase 12.1% in second-half 2012, totaling 2,023 wells. Compared to 2011’s figures, those three districts, year-on-year, will be up 24.3% at 3,827 wells. In the Permian basin, covered by District 8, oil-directed drilling is expected to gain 10.5% during the second half, to 3,160 wells. On an annual basis, we forecast 6,019 wells in District 8, up 23.5% from 2011’s figure. On the other side of the coin, activity will be down substantially in natural gas-oriented areas, particularly Districts 4 (deep South Texas, along the Gulf Coast), 5 (Barnett shale, East Texas) and 6 (East Texas).

A cautionary note was sounded by the statewide producers association, Texas Alliance of Energy Producers, during its mid-summer Texas Petro Index (TPI) briefing. The TPI is a composite index of upstream economic indicators. Alliance Economist Karr Ingham released the June report, showing the TPI’s first decline in 2 ½ years—a 1.1-point drop to 270.4. “Although a number of core industry economic indicators remain strong—drilling permit applications, the rig count and industry employment—the decline in crude prices, weak natural gas pricing and the impact on the value of Texas production have taken the index down for the first time in this current cycle,” said Ingham. “The question is, are crude oil prices stabilizing at a level high enough to sustain the high levels of activity generated in this expansion cycle, or are we witnessing the onset of a true slowdown to one degree or another in industry activity? The concern is obvious.”

Strong drilling results, combined with the large prospective area, and magnitude of the resource potential, are making the Eagle Ford shale in South Texas a contender for the best tight oil play in the U.S., according to a new report from IHS. According to the IHS assessment, typical well performance, as well as peak-month production of the Eagle Ford’s best wells, exceeds wells drilled in the Bakken Shale, often considered the tight oil standard. The Eagle Ford’s favorable outlook has generated a highly competitive merger and acquisition (M&A) environment, with implied deal values averaging $14,000/acre for Eagle Ford tracts in 2011, while top prices approach $25,000/acre. IHS found that a majority of Eagle Ford wells are producing around 300 to 600 bopd for a peak month production average, compared with 150 to 300 bopd for the Bakken. The best wells in the Bakken have an average peak-month production rate of 1,000 bopd or more, while the Eagle Ford central area’s top wells are even better on a boe-per-day basis.

A majority of Eagle Ford shale wells in South Texas are achieving a higher peak month oil production average than most Bakken shale wells in North Dakota. Photo courtesy of Anadarko Petroleum.

To the north, in Oklahoma, activity is solid and steady. Compensating for a decline in gas-directed wells being drilled, tight oil plays in the western part of the state have more than made up the difference, fueling a rise in the rig count. Rigs running in Oklahoma are up 11.1%, from a 180-unit average in 2011 to about a 200-unit average during the first seven months of 2012.

Louisiana is exhibiting a split personality between the northern and southern portions of the state. In the North, where natural gas dominates, the outlook is poor. Drilling in that half of the state is expected to drop about 17% from the first half (305 wells) to the second half (207 wells), and for the year, overall, it will decline 30.2% from the 2011 figure. In the South, however, activity is expected to be better, remaining flat from one half to the other, at 277 wells, each. A lion’s share of drilling in the South has been redirected toward oil by both major drillers and independents. On an annual basis, the South will also remain even with last year’s drilling total.

It is hard to find the right adjectives to describe the state of activity in North Dakota, where drilling continues to set records. Thanks to expanding development of the nation’s leading shale play, the Bakken, drilling in this state will jump another 13.2% in the second half, to 1,140 wells. For the year, overall, wells drilled are forecast to rise 35% above 2011’s figure, to 2,147. Just in first-half 2012, alone, North Dakota’s oil production has risen about 115,000 bpd, or 21%, to roughly 650,000 bpd, making it now the second-largest producer behind Texas and ahead of slumping Alaska. In neighboring Montana, strong oil activity in the Bakken and Heath shale plays has doubled the first-half rig count average, compared to the same period in 2011.

In the Northeast, Pennsylvania continues to have a tough time, as operators struggle to continue exploiting the Marcellus shale amid low gas prices. However, a bit of a rebound is forecast for the second half of 2012, partially because some operators will have to drill, to keep their lease positions. In neighboring Ohio, the picture is brighter, due to companies focusing on development of oil in the Utica shale. Despite being dominated by gas, West Virginia is holding its own, with a 12.7% rebound seen for the second half. Some oil drilling is beginning to creep back into the state among smaller independents.

Contrasts are emerging in the Rockies, where Colorado has eased off, but New Mexico continues to gain. In Colorado, despite a switch toward more oil drilling, activity is muddling along, with total wells for the year expected to be 23% less than 2011’s number. However, second-half 2012 drilling is forecast to be about 100 wells higher than the first half. A significant factor in Colorado’s activity level is uncertainty about regulations, particularly as concerns fracing. A number of municipalities have passed, or are trying to pass, anti-fracing and other anti-oil-and-gas ordinances. However, the Colorado Oil and Gas Conservation Commission has declared that these towns and cities are infringing on the state’s rulemaking jurisdiction. Indeed, the commission last month sued the city of Longmont for that very reason.

In New Mexico, a more pro-industry regulatory regime, combined with increased fracing and oil drilling in the southeastern portion of the state, has pushed activity higher. Second-half drilling is forecast to rise 6.7%, to 970 wells. For the year overall, drilling is expected to increase 7.7%, to 1,879 wells. The state’s Land Office saw numerous record-setting numbers during its monthly oil and gas lease sales during the 2012 fiscal year. In July and August, combined, $34 million were earned from the monthly oil and gas lease sale at the State Land Office. “I attribute these record revenues not just to higher oil prices, but also to the thoughtful selection of land tracts for lease sale by our employees at the State Land Office,” said Commissioner Ray Powell.

California is dominated by its two largest operators, Aera Energy and Occidental Petroleum. The vast majority of the state’s activity is oil-directed, and given the relatively high prices, a small increase to 1,420 wells in the second half is predicted. Year-on-year, California should drill 2,800 wells, for a 22.1% gain over 2011’s 2,294 wells. However, this year’s gain might be even higher, were it not for Occidental holding back its activity. CEO Stephen Chazen said last month that his firm is waiting to accelerate the pace of drilling in California, where permitting has improved, until the cost per well can be reduced by a third. The company holds about 1.7 million acres in California, including the Monterey shale formation. “If I can reduce the cost, I’ll get more wells for the same money,” said Chazen. “That’s really what I’m after.”

As regards Alaska, Royal Dutch Shell CEO Peter Voser told analysts last month that his firm has scaled back plans to drill up to five wells in Arctic waters this summer. He blamed a series of setbacks, including stubborn sea ice hovering close to Alaska's shores and delays in construction of an emergency oil spill containment barge. The company anticipates completing just two exploration wells in the Chukchi and Beaufort seas. The company now plans to complete just two exploration wells in the Chukchi and Beaufort seas.

About these statistics. World Oil’s U.S. tables are produced with the aid of data from a variety of sources, including the American Petroleum Institute, the Texas Railroad Commission, and other state and federal regulatory agencies. Most importantly, operating companies with drilling programs responded to this mid-year survey. Please note credits and explanations in the table footnotes. We thank all contributors for their time and effort in providing data and analysis.