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Despite posting earnings slightly below Wall Street's expectations, EOG Resources Inc. beat its production guidance and set a record for oil in the second quarter, thanks in large part to gushers it drilled in four oily plays across the country.
The Houston-based company also increased its production growth targets for the rest of 2017 while leaving its capital expenditures (capex) budget unchanged, adding that it is "actively engaged in a robust exploration program to lease and test multiple new prospects."
EOG produced a record 334,700 b/d during 2Q2017, a 25% increase from the year-ago quarter (267,700 b/d), and easily beat its total oil production guidance of 322,200-332,400 b/d. The company also bested its total production guidance for natural gas liquids (NGL) and U.S. natural gas -- which ranged from 72,000-78,000 b/d and 710-750 MMcf/d, respectively -- by producing 86,600 b/d of NGLs and 755 MMcf/d of natural gas from U.S. plays in the second quarter.
The company also reported beating its targets for lease operating expenses (LOE), transportation costs, and depreciation, depletion and amortization (DD&A) costs -- which had ranged from $4.60-5.00/boe, $3.20-3.60/boe, and $15.70-16.10/boe, respectively. A slide presentation that accompanied an earnings call Wednesday to discuss 2Q2017 reported DD&A expenses of $15.75/boe, based on the midpoint of 2017 guidance, as of Tuesday's date.
"Our goal remains delivering cash flow, covering capital and the dividend," CEO Bill Thomas said during the call. He added that "premium drilling is already having a substantial impact on our production, finding costs and DD&A. Compared to 2016, oil production is forecast to grow 20%, while our DD&A rate is forecast to decrease 9%."
Completing wells across four oily plays
EOG was busy completing wells all over the place in the second quarter. It focused on oil targets in the Delaware sub-basin, the Eagle Ford and Bakken shales, the Powder River Basin (PRB) and the Denver-Julesburg (DJ) Basin.
In the Delaware, the company completed 25 wells targeting the Wolfcamp Formation with an average treated lateral length of 6,500 feet per well and average 30-day initial production (IP) rates per well of 3,010 boe/d. EOG also completed 19 wells in the sub-basin's Bone Spring Formation, with an average treated lateral length of 5,600 feet per well and average 30-day IP rates per well of 2,130 boe/d. An additional three wells were completed in the Leonard Formation, with laterals averaging 5,400 feet per well and average 30-day IP rates per well of 1,615 boe/d.
EOG completed 51 wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day IP rates per well of 1,960 boe/d. The company also completed 22 wells in the Bakken with an average treated lateral length of 8,400 feet per well and average 30-day IP rates per well of 1,450 boe/d.
Rounding out its activity, EOG completed eight wells in the PRB's Turner Formation in the second quarter with an average treated lateral length of 8,700 feet per well and average 30-day IP rates per well of 1,745 boe/d. In the DJ Basin, it completed 10 wells with an average treated lateral length of 9,000 feet per well and average 30-day IP rates per well of 885 boe/d.
"As we've said many times before, the key to great wells is high-quality rock," Thomas said. "Our multi-decade database and learning curve gives us a huge lead in identifying the best rock to add new and better drilling potential to the company."
Looking for new plays in a 'robust manner'
During Tuesday's call, Thomas said the company was "focused on capturing high quality rock and the sweet spot of new premium plays with strong leasing efforts underway this year." But during the Q&A portion of the call, he kept details over those efforts close to the vest.
"It's been a very steep learning curve in the last few years," Thomas said. "[This year, we are taking] that proprietary knowledge...in a very robust manner to look for new plays, and we believe we have a lead on the industry and we have a unique opportunity window, particularly this year, to add additional acreage in those kinds of plays.
"We have increased exploration spending this year to do that. And so the whole process of gathering that data and collecting that data and analyzing that data has been a huge part of that, and we're taking that advantage and using it this year."
EOG left its capex budget for the full-year 2017 unchanged at $3.7-4.1 billion. It also maintained its plan to complete 480 net wells.
The company said it expects total oil production will range from 335,500-345,700 b/d in 3Q2017. It also projected total NGL production of 77,000-83,000 b/d and U.S. natural gas production of 720-760 MMcf/d. Meanwhile, LOEs were expected to be $4.40-4.80/boe, while transportation costs would range from $3.30-3.80/boe and DD&A costs of $15.55-15.95/boe are projected in the third quarter.
For 2Q2017, EOG reported net income of $23.1 million (4 cents/share), compared to a net loss of $292.6 million (minus 53 cents) for the same period last year. Adjusted net income was $46.7 million (8 cents), compared to an adjusted net loss of $209.7 million (minus 38 cents) in 2Q2016. In a note to clients Tuesday, analysts with Wells Fargo Securities LLC said Wall Street had expected adjusted net earnings of 11 cents/share.