Shale Drillers Squeeze Costs as Era of Exploration Ends: Energy
The pioneers of America’s shale gas and oil revolution have done their work. Now it’s time for the factory crews to take over.
After spending $53 billion on a land binge to find hydrocarbons, the petroleum industry is counting on technological innovations -- better imaging data, speedier and longer horizontal drilling, among them -- to ramp up the flow of oil and gas from U.S. shale fields where they’re drilling more than 10,000 wells a year.
The techniques are embraced by the biggest producers from shale such as Chesapeake Energy Corp. (CHK) and Newfield Exploration Co. (NFX) to boost shareholder returns by shifting money from exploration, which is winding down, into what’s known in industry parlance as manufacturing. The moves will help producers increase profit at a time shareholders are ousting executives and revamping boards because of poor performance.
“Now that all of the established shale plays are known, companies can start focusing on the economics of these plays,” said Eric Gordon, who helps manage $35 billion at Brown Advisory Inc. in Baltimore. “They are under pressure to reduce drilling time and operating costs.”
In Oklahoma, Chesapeake is blasting cracks into rocks surrounding each well at 10 times the rate of a few years ago. Newfield is using finely tuned mixtures of chemicals and minerals to stabilize wells that slice sideways through crude-soaked rock 10 times farther at half the cost per foot of a decade ago.
Producers that engaged in a land rush yielding vast shale discoveries from Pennsylvania to Wyoming and Texas are now being pressed by shareholders to turn promises into profit, said Brian Gibbons, a debt analyst at CreditSights Inc. in New York. By employing new technology, domestic explorers aspire to catch up with international energy titans such as Exxon Mobil Corp. (XOM) that generate six times as much profit from each barrel of oil.
Measures to cut per-unit production costs also are key to coping with oil and gas prices that are one-third and two-thirds lower, respectively, than their 2008 peaks. Soaring output from wells in North Dakota, Oklahoma and Texas has driven a 3.2 percent increase in U.S. crude production this year, adding to the 19 percent rise in 2012 that was the biggest annual jump in at least three decades, according to Energy Department figures.
Independent U.S. oil and gas companies -- those that focus on production and don’t refine crude into fuels and chemicals -- ended 2012 with an average cash-flow deficit of $1.5 billion, compared with an average surplus of $386 million for the world’s biggest energy producers.
Independent U.S. explorers spent more than $53 billion during the past decade snapping up drilling leases as breakthroughs in horizontal drilling and hydraulic fracturing allowed explorers to access previously impenetrable formations.
Of the 17 companies in the Standard & Poor’s 500 Oil & Gas Exploration & Production Index, Chesapeake was the biggest spender on prospective U.S. oil and gas leases with $19.9 billion from 2003 through 2012, according to data compiled by Bloomberg. The company, whose shares lost 36 percent from 2010-2012, on May 20 said it hired former Anadarko Petroleum Corp. (APC) Senior Vice President Robert Douglas Lawler as its new chief executive.
Chesapeake, the world’s largest driller of horizontal shale wells, said as early as March 2012 that all of the major untapped petroleum deposits in the continental U.S. had been discovered.
“Up to this point, we have been focused on building our asset base,” Chesapeake Acting CEO Steve Dixon said during the company’s annual shareholders meeting in Oklahoma City today. “We are truly at an inflection point. We have exited the capture phase” and entered the harvesting phase.
EOG Resources Inc. (EOG) Chairman and Chief Executive Officer Mark Papa told analysts on May 7 that the company’s exploration unit is now looking for overlapping, oil-bearing geological formations that can be simultaneously tapped to extract “substantially larger” quantities of crude. Houston-based EOG is the largest owner of drilling rights in Texas’s Eagle Ford shale.
The payoff for the deeper-farther-faster approach remains to be seen for Chesapeake and explorers such as Devon Energy Corp. (DVN), QEP Resources Inc. (QEP) and Southwestern Energy Co. (SWN), which have the poorest records of turning untapped reserves into barrels of crude for sale.
Producers use a calculation called the recycle ratio as a measure of profitability, dividing profit per barrel of production by the cost of discovery and extraction. So a $40 profit divided by $20 in costs yields a recycle ratio of 2:1, or 2. A higher number represents more profitability.
QEP’s recycle ratio was 0.69 in 2012 and Chesapeake posted 0.97, data compiled by Bloomberg show. In contrast, Exxon scored a 4.5 and Total SA (FP) had a ratio of 3.3. The ratios include three-year averages for reserves used in calculating costs for the companies.
The best performers in the exploration and production index were Denbury Resources Inc. (DNR), which uses carbon dioxide to coax more oil from wells, and Range Resources Corp. (RRC), the second-largest holder of drilling rights in the Marcellus Shale. Both logged recycle ratios that surpassed Chevron Corp. (CVX)’s 2.5 and BP Plc (BP/)’s 2.8.
Devon and Denver-based QEP said several factors lowered their recycle ratio numbers in the past couple of years, including falling gas prices that cut revenue as they shifted more drilling to oil projects, which are costlier than gas.
During the shift, the company is recording higher costs without yet getting the full benefit of bigger profits, said Vince White, Devon’s senior vice president of communications.
QEP incurred costs from an acquisition before production materialized from the assets, said Greg Bensen, director of investor relations at the company. QEP looks at the ratio using a multi-year view, he said.
Though Southwestern has some of the lowest costs in the industry, gas prices that collapsed to a decade low in 2012 reduced cash flow and forced the company to erase some proved reserves from its books, elevating per-unit costs for finding and development, or F&D, CEO Steve Mueller said in an e-mail.
“As the gas price increases, the F&D will drop dramatically as reserves are returned to the books and the yearly recycle ratio will be one of the best in the sector,” Mueller said.
Jim Gipson, a Chesapeake spokesman, declined to comment.
Analysts expect rising profits and stock prices will come to producers who embrace a manufacturing model, according to data compiled by Bloomberg.
Chesapeake, which reported on May 1 a first-quarter profit of 30 cents a share excluding one-time items, is expected to see adjusted income of 43 cents a share in the comparable period next year and 49 cents a share in the fourth quarter of 2014. At Range, analysts estimate per-share adjusted earnings may almost double to 63 cents in the fourth quarter of next year, compared with 33 cents in the first three months of 2013.
Newfield’s average 12-month target price from analysts’ estimates compiled by Bloomberg is $33.75, 48 percent more than the closing price yesterday. Denbury’s target price is $23.71, a 30 percent increase from yesterday’s closing price.
Energy producers and the oilfield-services companies they hire to help drill wells have continued to refine their techniques and equipment to increase the amount of oil and gas that can be squeezed from shale and other unconventional formations. Drilling sideways through the length of a field puts the well in contact with a larger section of oil-soaked rocks than a traditional vertical well.
Newfield is now drilling lateral wells as much as two miles (3.2 kilometers) long, 10 times the length of the horizontal bores used at the dawn of the shale revolution during the last decade, Clay Gaspar, a vice president at The Woodlands, Texas-based company, said in a telephone interview. In the last 18 months, the company cut the cost of drilling sideways by more than half to about $1,000 a foot, he said.
In Oklahoma’s Cana Woodford region, new techniques and improved materials are giving Newfield’s crews better access to the well bore, allowing them to isolate smaller zones to target fracturing more precisely. Newfield crews are shattering the rock two or three times more frequently in wells with twice the lateral length of the 5,000-foot (1,524-meter) wells they were drilling just 18 months ago, Gaspar said. That equates to clusters of fractures approximately every 300 feet compared to more than 400 feet before.
“The world we live in today is all about manufacturing and it’s trying to get to the point where that experiment that we do becomes repeatable,” Gaspar said. “We’re using a lot of the same efficiency techniques that other manufacturing organizations have used over the years.”
Chesapeake has reduced the time it takes to drill wells in the Eagle Ford shale to 18 days from 25 days a year ago, according to a presentation published on the company’s website on May 13. Chesapeake is aiming to eventually lower that to 13 days. The Eagle Ford will account for 35 percent of Chesapeake’s capital spending this year, more than any other single region, the presentation showed.
In Ohio’s Utica Shale, Chesapeake has lowered its cost to drill wells to $5.9 million each from $8.5 million, a 30 percent decline, according to the presentation. The company has 14 rigs drilling in the Utica region.
Noble Energy Inc. (NBL) is drilling wells in Colorado’s Denver-Julesburg Basin with 9,000-foot horizontal bores that the company’s engineers estimate will ultimately produce the equivalent of 1 million barrels each, Chief Operating Officer David Stover said during an April 25 conference call with analysts. That’s compared with the 40,000 barrels per well that the company was targeting three years ago with traditional vertical wells.
Producers are searching for ways to boost efficiency and curb costs before drill bits even begin chewing into rocks to start a new well, said Gregory Powers, vice president of technology at Halliburton Co. (HAL), the world’s largest provider of hydraulic fracturing.
Three-dimensional modeling of subterranean formations help oil producers predict the nature, location and permeability of crude-rich reservoirs, Powers said during a meeting with reporters at Halliburton’s Technology Center in Houston on May 9. Prospectors also are taking advantage of better technology in steering drill bits to precise locations deep underground.
“How much better is it?” Powers said. “It’s immensely better than just 10 years ago.”
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