NEW ORLEANS -- Tres amigos rode proudly across the stage as the 42nd annual Howard Weil Energy Conference got under way in New Orleans March 24, providing three archetypal examples of how technologically savvy independent operators are changing the face of oil and gas.

An audience of 600 mostly institutional investors heard a transition story in the guise of Devon Energy Corp., (NYSE: DVN), a legacy development story that turned into an unexpected bonanza in the guise of Noble Energy Inc. (NYSE: NE), and a high-tech execution story in the guise of Marathon Oil Corp. (NYSE: MRO).

Tres amigos represent the main themes woven into the fabric of the current domestic oil and gas scene as operators pursue positive free cash flow in resource plays such as the Eagle Ford, DJ Basin, Marcellus and Bakken by 2015.

For Devon, it’s all about a “go forward” company that is divesting non-core assets in the U.S. and Canada as it transitions to a liquids-oriented company seeking “highly visible growth” several years into the future from five core areas.

Devon’s transition involves transformative strategic acquisitions in the form of the $6 billion GeoSouthern Energy Corp.’s holdings in the Eagle Ford Shale in November 2013. The deal, valued at four times 2014 EBITDA according to Devon CEO John Richel, closed in February 2014, is immediately accretive, and provides the Oklahoma City-based large independent with a third liquids leg to match crude oil assets in the Permian Basin and Canada’s oil sands.

The company also holds optionality to rising gas prices in two core plays in the Barnett Shale and the Anadarko Basin’s Cana Woodford, though Devon will reduce Anadarko Basin activity in 2014 as the corporate focus turns to oil.

Devon’s new Eagle Ford assets are located in the sweet spot of the legendary Karnes Trough, are completely de-risked, held by production and ready for full development.

“All companies do things well, and one of the things we can say that we’ve demonstrated with our other large unconventional development is that we’re very good at management of large development projects when it comes to reservoir optimization and driving efficiencies and reducing costs,” Richel said.

The newly acquired Eagle Ford assets averaged 40,000 barrels of oil equivalent per day (boe/d) in 2013 and should exit 2014 at 70,000 boe/d. By 2017, Richel expects the Eagle Ford acquisition to deliver a compounded annual growth rate of 30% and generate $2.5 billion in free cash flow “and some billions more thereafter.”

Devon will spend $1.1 billion in Eagle Ford development capital in 2014 and drill about 200 wells, mostly in DeWitt County, in a program Richel labeled as self-funding.

“We have a very high degree of confidence regarding the undrilled inventory in this prolific play,” he said.

In all, Devon will spend between $4.8 and $5.2 billion in North America during 2014 while living within cash flow as it pursues the transition in corporate orientation from gas to liquids. Richel said Devon’s 2014 net production would range between 580,000 and 620,000 boe/d with oil and liquids accounting for 55% of output, up from less than 45% two years ago.

Devon merged its midstream assets with Crosstex Energy Inc. in October 2013 to create Enlink Midstream LLC, a master limited partnership (MLP). The initial transaction valued the midstream assets at $4.8 billion, of which Devon retained a 70% majority ownership in the general partner for the MLP and a 53% stake in the MLP. Equity markets currently value Devon’s Enlink ownership at $8 billion, or 30% of Devon’s market capitalization, Richel said.

The company is also pursuing divestitures to underwrite its corporate transition. The company recently sold Canadian conventional gas assets for a net $2.7 billion in a transaction expected to close in the second quarter 2014. The proceeds will pay down debt associated with the November acquisition of GeoSouthern’s Eagle Ford acreage.

Devon has an additional 56,000 boe/d in non-core gas-weighted conventional assets for sale in the Rockies, Gulf Coast and Midcontinent.

Noble’s Great Expectations

For Noble Energy, the transformational development of a liquids rich resource play in a legacy gas conventional field has become an integral component in the company’s five-year plan to top 629,000 boe/d in production and $8.3 billion in discretionary cash flow company wide by 2018, according to CEO Chuck Davidson. The five-year plan calls for the company to move production to more than 302,000 boe/d in 2014 led by the maturing development effort in the DJ Basin where the oily Niobrara has superseded a formerly conventional dry gas stacked play in Wattenberg Field.

The company will spend $4.8 billion in 2014 with about two thirds of expenditures targeting the DJ Basin and the Marcellus Shale.

The main story is the DJ Basin, where Noble will drill 320 horizontal wells, including 55 extended laterals, and pursue downspacing to as many as 32 wells per section on a $2 billion capital program. Davidson placed the DJ Basin Niobrara play in context by comparing his company’s current five-year plan to his Howard Weil presentation from five years ago.

“When I go back to 2009, we were drilling all vertical wells,” Davidson said. “Now they are all horizontal wells. We were very excited about our net risked resources. In 2009 the net risked resource in the DJ Basin was 700 million barrels. Today, it is 2.6 billion barrels. We had a projected growth rate in 2009 of 5%, and I’m sure I made it sound very good versus a growth rate this year of 23%.”

Davidson said a review of the company’s 2009 long-range plan of expectations for the Wattenberg by 2018 forecast production to be less than 50,000 boe/d. The current 2018 goal calls for more than 200,000 boe/d out of the DJ Basin.

Furthermore, the technology that opened the Niobrara is transferrable. Similar efforts in the Marcellus Shale, including extended laterals to 7,000 feet and downspacing tests as close as 500 feet, will increase recovery efficiencies and drop Marcellus well costs by 20% during the two-year period ending in 2014, according to Davidson.

In Appalachia, Noble has climbed the learning curve in the Marcellus over the last two years with 15 trillion cubic feet equivalent in net risked resources across its 350,000 net acres in the southwest fairway, a number that doubled since 2012 and now incorporates 9.6 billion cubic feet equivalent in estimated ultimate recovery (EUR) per well at a finding and development cost of 83 cents per Mcf.

Marathon Ventures Into The Chalk And The SCOOP

For Marathon, an emphasis on technical proficiency is producing measurable results as the company expands domestic drilling activity from 22 to 28 rigs in 2014.

The company is focusing on the domestic market to accelerate recovery of 2.4 billion barrels of oil equivalent in 2P reserves from 4,500 net well locations in three resource plays. About half of those well locations are in the company’s 200,000 net acre Eagle Ford location, which features 1.7 billion barrels of oil equivalent in resource potential.

CEO Lee Tillman outlined significant gains in drilling and completion practices that have placed Marathon among best-in-class performance in the Eagle Ford and Bakken shales. The company is targeting 30% production growth year-over-year in 2014 and allocating 60% of its $5.5 billion in capital spending to domestic resources plays, including an expanded presence in the Anadarko Basin.

The company has also opened a data room on its U.K. and Norway North Sea assets and expects to open bids in the second quarter 2014.

Tillman outlined a number of technical initiatives that are increasing recovery factors through completion efficiency and infill drilling. Zipper frack well stimulation on multi-well pads has had a material impact on production volumes with Eagle Ford 30-day IPs up 97% from 2011 to 2014 to more than 1,200 boe/d and six-month cumulative production up 57% through 2013. Tillman projected additional increases in 2014 wells as the company tweaks fluid volumes, pumping rates, cluster spacing and proppant loads.

“These productivity improvements are a result of systematically varying the stimulation design parameters across our acreage position and pad development and closer lateral spacing,” Tillman said. “The net effect is these improvements in well performance are effectively mitigating any impacts from the increase in well density. “

Tillman also revealed greater detail on Marathon’s five-well foray into the Austin Chalk.

“Our early work in the Austin Chalk continues to be encouraging with results competitive with the Eagle Ford,” Tillman said. “It is important to note that we are pursuing an Austin Chalk interval that is very different than the Pearsall and Giddings field analogs or, as we like to say internally, this is not your father’s Austin Chalk.”

The formation is partially self-sourcing for oil and produces without conventional traps. Marathon plans to test the resource potential in 2014 by co-developing the Chalk in a five-well program with the lower Eagle Ford.

Marathon is also increasing 2014 activity in the Anadarko Basin, including an expanded drilling program in the SCOOP play where it will employ a four-rig program to drill 20 wells in Grady and Stephens counties while participating in more than a third of all industry SCOOP wells. The company currently has 100,000 acres prospective for the SCOOP and access to stacked reservoirs including the Granite Wash, southern Mississippian Trend and Granite Wash on 35% of its Oklahoma acreage.

Tillman cited a 158% increase in cumulative six-month production to 200,000 barrels of oil equivalent between 2011 and 2013, which prompted the company to expand its Anadarko Basin effort.

Contact the author, Richard Mason, at rmason@hartenergy.com.