EOG Resources’ (NYSE: EOG) quarterly losses grew to about $455 million for first-quarter 2016, but the company completed an EOR project in the Eagle Ford Shale that could increase recovery by 30% to 70%.

The company also said it has “cracked the code” on its Austin Chalk acreage.

Despite the loss, the company posted a beat and raise on U.S. crude production, said David Tameron, senior analyst at Wells Fargo Securities LLC.

This comes as EOG, among the leading U.S. shale producers with a handful of international assets, shifts to what CEO Bill Thomas called premium drilling, targeting wells that can generate at least a 30% return, after taxes, at $40 oil. The shift, which is permanent and “not a temporary high-grading process in a low-commodity price environment,” requires capital discipline, higher standards for spending and greater efficiency.

Like its peers, EOG’s profits have been pummeled by lower oil prices, which have forced companies to slow production and seek smarter, cheaper ways to get oil and gas from the ground.

In 2015, the company posted a $4.5 billion loss compared to income of $2.9 billion in 2014. Wells Fargo estimates the company will lose $1.4 billion in 2016.

“We do not need 50 rigs drilling thousands of wells per year. It will take far less capital to grow production at strong double-digit rates,” Thomas said during a May 6 conference call.

EOG is capable of hitting triple digit direct rates of return at oil prices as low as $60 per barrel, he said. “If history is any indication we will continue to push the oil price needed for triple-digit returns even lower.”

EOG believes a $60-$65 oil price and 12 months of lead time will be needed to deliver growth in the U.S.

But the company’s technical prowess may give it a leg up on other E&Ps.

EOG’s first successful EOR horizontal shale project and gains in the Austin Chalk will help the company reach its goal of becoming one of the world’s lowest cost oil producers, Thomas said.

“When the market balances and prices recover to moderate levels, our leading asset quality, best in class technology and low cost structure will become apparent with how quickly we can resume high return oil growth.”

For now, the priority in 2016 is funding its capital program with cash flow and lowering debt through property sales, some of which are in the late stages of negotiation.

The months ahead will also include a 32-well EOR pilot project in the Eagle Ford as EOG works to learn more about the potential applicability of its proprietary EOR technique to other parts of the play.

Enhancing Recovery

Billy Helms, executive vice president of E&P for EOG, could not give details about the EOR technology but spoke to its economic and recovery potential as well as the Eagle Ford’s attributes.

“We have long discussed barriers that encase the Eagle Ford and provide vertical containment for completions. This unique feature also plays a significant role in keeping the injection in contact with the targeted reservoir,” Helms said. “The injected gas is thus able to become miscible with the oil in the reservoir and subsequently drive incremental oil recovery.”

He added that EOG’s acreage position in the optimal, thermal maturity of the play is beneficial.

Moreover, the economics are favorable, “enhanced by the scale of EOG’s footprint in the play, the infrastructure and facilities that are utilized in primary development across the field,” Helms said.

More than three years of testing on the four pilot EOR projects led to these takeaways:

  • The EOR technique is not capital intensive and requires no incremental drilling. Additional capital costs average about $1 million per well;
  • The process uses associated gas that is already available;
  • Production response occurs within the first two or three months, unlike typical secondary and tertiary recovery projects, and remains steady for longer;
  • For each dollar invested, EOR delivers at least twice the net present value created as primary drilling; and
  • Models indicate the process will increase recovery by 30-70%, Helms said, noting these are incremental potential reserves, not accelerated production.

“While this is a significant technical and economic breakthrough, rolling out this effort will take time and is dependent on the pace of primary development drilling and field development,” Helms said.

It’s unclear how much of EOG’s acreage could benefit from the EOR technology.

Charting The Chalk

The South Texas Austin Chalk has been described as a play with inconsistent production and varied returns.

“Using proprietary petrophysical analysis we discovered how to apply new geologic concepts to the Austin Chalk and drill prolific wells consistently,” said David Trice, executive vice president of E&P. “Our high density completions create complex fracture systems close to the wellbore, significantly improving well performance.”

Precision adds benefits.

Trice said the Chalk can be as thick as 140 feet in some places. EOG confines the drillbit to the best 20 or 30 feet of rock and, when combined with EOG-style completions, well performance is at a premium, he said. Plans are to drill seven additional wells this year in the Austin Chalk, which sits atop the South Texas Eagle Ford shale.

First-quarter drilling highlights included:

  • The Leonard AC Unit 101H test well coming online with a 30-day production of 2,715 boe/d; and
  • The Denali Unit 101H well, brought online in April, averaging 3,130 boe/d for the first 20 days.

In the Permian/Delaware Basin, EOG’s focus is on the Wolfcamp oil window, where it aims to generate returns while learning more about the shallower Bone Spring sands, Trice said. Next steps here include extending laterals and improving completion designs.

EOG said it is already seeing cost and drilling improvements in the basin. Well costs fell 8% to $6.9 million, while drilling days dropped by 14% to 16.1 days, he said. Further savings, about $150,000 per well, are expected when EOG starts using brackish water for its New Mexico completions.

In all, EOG lowered costs and decreased its exploration and development expenditures, which fell about 61% for the quarter compared to a year ago.

Total crude and condensate production also fell for the quarter, down by 10%, compared to first-quarter 2015, while gas production fell by 3%. Capital guidance of $2.4 to $2.6 billion was maintained, said Tim Geders, CFO for EOG.

Company executives said the market rebalancing continues and a pickup is expected in the second-half of 2016.

Velda Addison can be reached at vaddison@hartenergy.com.

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