Executives at EOG Resources Inc. said 2013 was the company's "best year on record," with the Eagle Ford Shale driving a 40% year-over-year (y/y) increase in total crude oil and condensate production and overall production climbing more than 9%.

The Houston-based company reported total production of 48.9 million boe during 4Q2013, up 16.9% from 41.9 million boe produced in the preceding fourth quarter. For the full-year 2013, EOG produced 186.2 million boe, up 9.1% from 170.7 million boe from 2012.

Domestic crude oil and condensate production shot up 52.8%, from 154,100 b/d in 4Q2012 to 235,400 b/d in 4Q2013. From full-year 2012 to 2013, domestic crude and condensate production rose 42.1%, from 149,300 b/d to 212,100 b/d.

In the Bakken Shale, EOG focused on drilling in the core area of the play in 2013 but also forayed into the Antelope Extension area. The company said results from the Bakken had exceeded its expectations, thanks to improved drilling and completion techniques and the switch from drilling one well per section to four.

"What was a steady development drilling program [transformed] into a high rate-of-return crude oil growth play," EOG said Monday.

The company said two wells drilled in the Bakken core -- Wayzetta 30-3230H and 31-3230H, of which EOG has a 59% working interest (WI) in each -- began production at 2,510 and 2,540 b/d, respectively. A third core well, Wayzetta 35-1920H (60% WI), had initial production (IP) of 2,240 b/d with 1.2 MMcf/d of rich natural gas. The wells were all drilled in Mountrail County, ND.

EOG drilled a fourth well, Hawkeye 2-2501H (80%WI), in the Antelope Extension. The well, located in McKenzie County, ND, had an IP of 2,075 b/d and 3.8 MMcf/d of rich natural gas.

The company said the Permian Basin also contributed to its growth in domestic crude oil production.

Although it tested multiple zones across three horizontal plays in the basin last year, EOG initially focused on the Midland Basin Wolfcamp, followed by the Delaware Basin Leonard and Wolfcamp. After compelling well results, it shifted to the Delaware Basin Leonard in 2H2013.

Two Leonard wells, Vaca 24 Fed Com #5H and #6H (both 89% WI), had IP of 1,520 and 1,380 b/d of crude oil, 265 and 170 b/d of natural gas liquids (NGL) and 1.5 and 0.9 MMcf/d of natural gas, respectively. Both wells were drilled in Lea County, NM.

EOG exited 2013 with 2.12 billion boe of total net proved reserves, including 900.5 million bbl of crude oil and condensate, 377.2 million bbl of natural gas liquids (NGL), and 5.04 Tcf of natural gas. Total net proved developed reserves increased 18.7%, from 949.8 million boe at the end of 2012 to 1.13 billion boe for year-end 2013. Potential reserves in the Eagle Ford grew 45% to 3.2 billion boe, net after royalty.

EOG said it plans to spend $8.1 billion to $8.3 billion on capital expenditures (capex) in 2014, a figure that includes funding for production and midstream infrastructure expenses but not land acquisition costs.

The company plans to drill approximately 520 net wells in the Eagle Ford in 2014 and will rely on the play to help it achieve its goal of growing total crude oil production for the year by 27%.

During a call to discuss 4Q2013 and full-year 2013 results on Tuesday, CEO Bill Thomas said downspacing across the Eagle Ford would vary depending on the local geology.

"Some places we can drill wells as close to maybe 30-35 acres per well, and in some places it's more like 50-65 acres per well," Thomas said. "It is quite highly variable. The number of wells that we have -- 7,200 total wells -- is based on actual well locations that we have put on the map, in regard to the individual geology of each unit and the configuration of the leases. These are not spreadsheet numbers.

"There is some interference in some areas, and there are some places where there is not any interference. We've been able to overcome the interference and increase well EURs [estimated ultimate recovery] with our frack [hydraulic fracturing] technology. The frack technology has definitely enhanced the productivity of the wells. We have quite a bit of confidence that the average EUR for the 7,200 wells we have is 450,000 boe per well."

EOG also plans to drill 80 net wells in the Bakken and Three Forks formation, slightly more than it drilled there in 2013. The company will focus mostly in the core area of the play, but will also drill in the Antelope Extension. EOG said it also plans to test additional benches in 2014.

In the Permian, EOG said it will shift its capex program from the Midland Basin to the Delaware Basin, based on tests results there. The company said it will focus on the Leonard play, followed by the Wolfcamp, as it looks to develop more efficient drilling patterns and test additional prospective zones.

EOG reiterated that it does not plan to allocate capital toward dry gas drilling in North America in 2014, and expects dry gas production on the continent to decline 6% as a consequence.

The company's production guidance for 2014 ranged from 547,200 to 591,300 boe/d. That range includes production of 268,100 to 291,700 b/d of crude oil and condensate, 68,600 to 77,800 b/d of NGL and 1.26 to 1.33 Bcf/d of natural gas.

Thomas said EOG's prime markets for oil remain the Gulf Coast and Cushing, OK, at Louisiana Light Sweet (LLS) and West Texas Intermediate (WTI) prices, respectively.

"Our crude by rail system gives us a lot of flexibility, and we believe that will come into play as we go forward," Thomas said. "As we have seen over the last few months there's been some variance in the differentials between WTI and LLS prices, and we've been able to take advantage of that by switching back and forth."

Thomas added that EOG hasn't front-loaded what it believes will be better performing wells at the head of its 12-year inventory.

"Our drilling is very well equally spaced," Thomas said. "As we look forward we really need to be thinking about the Eagle Ford as one play. The western and eastern wells are relatively the same in the average EUR per well. There's a little bit of variability, but there's really not much difference across the whole play.

"We believe our well results would be very consistent going forward. They certainly aren't front-end loaded with the best wells. You can look at the 12-year inventory as very strong and consistent and we'll have good results every year."

EOG posted adjusted net income of $2.2 billion ($8.04/share) for the full-year 2013, compared with $570 million ($2.11) for full-year 2012. For 4Q2013, adjusted net income was $580 million ($2.12) compared to a net loss of $505 million ($1.88) in the preceding fourth quarter.

The company said its board of directors had approved a two-for-one stock split in the form of a stock dividend. It will be payable to record holders as of March 17 and issued on March 31. The board also increased the cash dividend on common stock by 33%.

In a note Tuesday, Wells Fargo Securities LLC analyst David Tameron said EOG was placed on a neutral outlook, pending the company's earnings call.

"Considering that EOG checked off most boxes...[the] initial take may appear positive, but a couple of factors lead us to neutral with today's conference call likely to serve as the final arbiter," Tameron said. "2014 capex guidance came in roughly 11% above consensus, which adds a capital efficiency question that some may connect to increased western Eagle Ford activity, but we do note that the bulk of capex increase versus us is due to higher gathering-related infrastructure.

"All-in, another solid year officially in the books, but a few questions, including EOG's wide production range left to be addressed before getting the nod of approval from investors."

Shares of EOG were trading at $183.80/share Tuesday afternoon on the New York Stock Exchange, a $3.40/share (1.88%) increase over the day's opening price of $182.85/share.

Tuesday's earning call was the first since the departure of Mark Papa as executive chairman (see Shale Daily, Nov. 12, 2013).