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Eagle Ford to Rival North Slope Output at its Peak, Says Wood Mackenzie

Eagle Ford Shale crude and condensate production in 2020 will rival Alaska's entire North Slope field at its peak, hitting an estimated 2 million b/d, according to an analysis by Wood Mackenzie Ltd.

And it's not the only development that's helping to build U.S. stores of oil and gas, analysts said during a briefing on Wednesday in Houston. Tight oil production is forecast to reach 6 million b/d by 2020 in the Lower 48 states, led by output from the Eagle Ford and Bakken shales, and the Permian Basin's Bone Spring/Wolfcamp Shale. Overall liquids production by that time is expected to be almost 9 million b/d.

Bakken output is forecast to hit 1.7 million b/d by 2020. By that time, oil and condensate production from the Permian Basin's Bone Spring/Wolfcamp formation -- still in early development -- now is predicted to reach 800,000 b/d.

The potential of the plays is being tested all of the time as operators successfully produce from the plays within the plays, said John Dunn, who manages Lower 48 upstream research.

"It's about the sub-plays and the stories in those sub-plays that is making all the difference," he said. "We don't see any plays that will be the next Bakken in 2016," but the subbasins in individual plays may offer more potential.

Producers will spend more money drilling wells in the Eagle Ford this year than the annual revenue generated by Bolivia or the North American yoga industry, said analyst Cody Rice. That $27 billion spending this year, $4 billion higher than Wood Mackenzie estimated last fall, is about what it will cost to drill about 3,300 wells in South Texas.

If the Eagle Ford were to hit North Slope production numbers by 2020, that would be about half of the production of Ghawar, the world's largest onshore oilfield, and 150% of the combined Bakken/Three Forks production on a boe basis, according to Rice. Almost 80% of the spend this year is targeting condensate.

The Eagle Ford is considered by most to have three primary development areas: shallow, oily to the north; deeper, gassier to the south, and condensate in the middle. Wood Mackenzie divided the Eagle Ford into nine sub-plays to better determine benchmark comparisons: Karnes Trough, Maverick condensate, southeast gas, Edwards condensate, black oil, Maverick Oil, Hawkville condensate, southwest gas and northeast oil.

Three of the nine sub-plays will comprise 60% of 2020 output, analysts determined. The Karnes Trough, about 3.8% of the acreage, should generate 25% of the total production within six years.

Like real estate, it's location, location, location when it comes to producing condensate in the Eagle Ford, said Rice.

"The gas drive mechanism in the core of the play helps keep initial production rates up," he said. "The core is where you want to be. We have large companies and we have small companies there. Production has grown dramatically and we expect production to continue growing."

The Permian Basin's Wolfcamp Shale, within the Delaware subbasin, is in the same league as the Bakken and Marcellus shales, according to Wood Mackenzie. Although the forecast production to 2020 is below that of the Eagle Ford and Bakken, it's still an emerging set of deeper formations that are more oil prone than many had thought.

The storied play, an oil producer for 100 years, has become a jumping off point to a long and prosperous future for operators, said analyst Benjamin Shattuck. The B bench of the Wolfcamp today is most prolific; it's also one of the most active drilling areas. The A and C benches of Wolfcamp are more marginal, but results will keep improving.

It's the long-time leaseholders in the Permian, those explorers with at least five years of proprietary knowledge, or those that have more than 70% of onshore capex focused on the Wolfcamp, that are outperforming peers, Shattuck said. More derisking will continue across the basin, but through the end of the decade, midstream constraints and labor shortages will make it difficult to expand operations, he said.

The Bakken's economics are improving, but there's not as much enthusiasm for the Three Forks formation. Wood Mackenzie estimates that 21 billion bbl of light sweet crude ultimately will be recovered from the Bakken/Three Forks formation in the Williston Basin. That's higher than the U.S. Geological Survey's updated estimate in April 2013 of 7.4 billion bbl. The amount of estimated ultimate recoveries (EUR) has risen as recoveries have improved. Higher-density development also is accelerating.

The Lower Three Forks commercial development is set at around 3,000-3,500 square miles, based on recent production data covering an 18-month period from mid-2012 to the end of 2013. There remains some potential upside in Three Forks if another formation within it is tapped successfully.

"Like the Wolfcamp, it's easier to increase value by exploring targets deeper on existing acreage than acquiring new acreage," said analyst Jonathan Garrett.

Three Forks is considered a fringe area of the Williston as the Bakken thins to the north and south. As well costs decline, and EUR rates improve, the numbers could improve as well.

"It might not have made sense in 2010 to spend $13 million on a Bakken well with 3,000 boe rate," said Garrett. "Today, it might make sense to spend $6-7 million on a well with 300,000 to 350,000 boe on an EUR basis as the play is becoming more commercial and economic."

Limited pipeline infrastructure in the Bakken has forced operators to rely on shipping crude to market via rail. The amount of Bakken crude transported by rail has more than doubled to 70% recently from 30% in early 2012. Crude by rail today is fetching a price closer to Brent crude than Cushing, OK, prices, taking into account the netback for barrels minus transportation, said Garrett.

And nobody's complaining. "Companies are making money, even though rail is expensive," he said.

Over the next two years, the gap between rail and pipeline capacity should shrink as more pipeline projects ramp up. Enbridge Energy is expanding its pipeline to Superior, WI; Double H has a pipeline to Guernsey, WY; and Energy Transfer Partners is planning a project to carry crude to the Gulf Coast.

Natural gas production from the Lower 48 also is seen rising at a steady pace, primarily driven by the Appalachian Basin. Gas output from the Marcellus Shale is seen rising to 20 Bcf/d in 2018 from around 12-14 Bcf/d. In the Utica Shale, output should increase fivefold to 5 Bcf/d through 2018. By 2020, gas output from Appalachia is forecast to hit 25 Bcf/d.

From a global perspective, it's the reserve additions from the new mainstays of American energy that are strengthening.

Wood Mackenzie found that between 2007 and 2013, international oil companies -- including the majors but not national oil companies -- doubled North American reserves, more volume growth in a single region than other global regions combined.

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