After a fourth quarter when Permian Basin pure-play Diamondback Energy Inc. nearly doubled its core acreage position, the company reiterated plans to be more conservative in 2019, even as it realizes synergies from several mergers quicker than it expected.

The Midland, TX-based independent trimmed its 2019 capital expenditures (capex) for drilling and completion (D&C), as well as midstream and infrastructure to $2.7-3.0 billion. It expects to complete 290-320 gross horizontal wells, with an average lateral length of 9,400 feet, using an 18-22 drilling rig program. It also unveiled full-year production guidance of 275,000-290,000 boe/d (68-70% oil), marking a 27% increase in production growth over pro forma production for 2018.

Although the production guidance and rig count were unchanged from preliminary guidance issued last December, capex was trimmed from $2.7-3.1 billion for drilling and completions and by $350-400 million for midstream and infrastructure costs. The low end of wells expected to be completed was also raised from 280, as was the average lateral length from 9,200 feet.

“Commodity prices declined dramatically in the fourth quarter and as a result of this volatility Diamondback outspent cash flow for the quarter,” CEO Travis Stice said during a quarterly earnings call Wednesday. “This is against our core operating philosophy and we reacted as quickly as possible.”

Diamondback dropped three operated drilling rigs and two completion crews after closing on the acquisition of Energen Corp. last November. The company currently has 21 operated horizontal rigs and eight completion crews deployed.

According to its investor presentation, Diamondback has seen synergies from its acquisition of Energen come faster than expected. The company had targeted savings of $233/foot in D&C costs by 2020 in the Permian’s Midland sub-basin, and up to $50/foot in D&C savings long-term in the twin Delaware sub-basin. To date, Diamondback has realized $215/foot in D&C savings in the Midland, and $55-60/foot in the Delaware. This year savings are projected to total $140-150 million in the Midland and $25-30 million in the Delaware.

“This savings is not only attributed to the immediate implementation of Diamondback best practices on Energen acreage, but also due to some efficiencies the Diamondback team has learned and implemented from legacy Energen best practices,” said COO Mike Hollis. “The benefit of size, scale and buying power on service costs have been greater than originally anticipated.

“Running these savings through, 40% of our Midland basin well count for the year results in almost $150 million in capital savings.”

Diamondback reported production of 182,800 boe/d (71% oil) in 4Q2018, up 97% from the year-ago quarter and 49% sequentially. Full-year production, excluding the Energen acquisition, beat guidance and averaged 121,400 boe/d (73% oil) in 2018, up 53% from 2017.

“We’ve got a pretty good long-term strategy laid out at $50/bbl,” Stice said. “As commodity prices improve — in the back half of this year, maybe into 2020 — you could look at us to perhaps add one to two rigs in 2020 and beyond with the significant free cash flow,” or FCF. He said the company made a “strategic pivot” last December, in anticipation of a coming “wave” of FCF.

“The pivot is that we’re not going to redeploy that all back into the ground; we’re going to start returning that to our shareholders,” Stice said. “We began that again this year by increasing our dividend as well. We’re committed to continue to look at that, even as commodity prices improve.”

During the fourth quarter, Diamondback drilled 55 gross horizontal wells and placed 48 into production. Of those 48 wells, 31 targeted the Wolfcamp A, while another eight wells targeted the Lower Spraberry and five were drilled into the Wolfcamp B. The Second Bone Spring, Third Bone Spring, Jo Mill and Middle Spraberry intervals were also targeted by one well each. The average lateral length for wells completed in 4Q2018 was 9,306 feet.

For the full-year 2018, the company drilled 189 gross horizontal wells and placed 176 operated horizontal wells into production.

Diamondback cited several operations across Texas, including in the northern Delaware sub-basin of the Permian in West Texas, where it took over operations from Energen at the end of November. Before the takeover, Diamondback said Energen completed three wells targeting the Wolfcamp A in 4Q2018 with an average lateral length of 4,546 feet and an average peak 30-day two-stream initial production (IP) rate of 436 boe/d per 1,000 feet of lateral (71% oil). An additional three Wolfcamp B wells with an average lateral length of 4,897 feet achieved an average peak 30-day IP rate of 261 boe/d per 1,000 feet of lateral (64% oil).

In Pecos County, the company recently completed four wells targeting the Wolfcamp A interval with an average lateral length of 10,183 feet and a peak 30-day IP rate of 173 boe/d per 1,000 feet of lateral (89% oil). Another well in Pecos, the Blackstone State 1-12 B 1SB, targeted the Second Bone Spring with a 10,081-foot lateral and recorded a peak 30-day IP rate of 153 boe/d per 1,000 feet of lateral (91% oil).

To the north, in central Martin County, Diamondback completed three wells targeting the Lower Spraberry with an average lateral length of 7,503 feet and a peak 30-day IP rate of 177 boe/d per 1,000 feet of lateral (90% oil). Meanwhile, in neighboring Howard County, TX, the company completed six Midland wells targeting the Wolfcamp A with an average lateral length of 9,316 feet and a peak 30-day IP rate of 207 boe/d per 1,000 feet of lateral (85% oil).

Diamondback reported net income of $306.1 million ($2.50/share) in 4Q2018, compared with year-ago profits of $129.6 million ($1.16). For 2018, net income totaled $845.6 million ($8.06/share) versus $516.8 million ($4.94) in 2017. Revenues totaled $633.1 million, compared with $399.2 million in the year-ago quarter. Full-year revenues totaled $2.18 billion in 2018, compared with $1.2 billion in 2017.