Noble Energy Inc., which has turned its U.S. onshore focus mostly to Texas and Colorado, struck a deal to sell its Marcellus Shale acreage that runs across 385,000 net acres in northern West Virginia and southern Pennsylvania for $1.225 billion.

The transaction with an undisclosed buyer was announced Tuesday, one day after Noble unveiled strong first quarter production results. The deal includes upfront cash of $1.125 billion and an additional contingent amount of $100 million, structured as three separate payments of $33.3 million. The contingent payments would be in effect if the average annual price realization at Dominion South were to exceed $3.30/MMBtu in individual annual periods from 2018 through 2020.

“The Marcellus has been a tremendous asset in terms of productivity, a direct result of the success of our employees’ efforts,” CEO David Stover said during a conference call Tuesday morning. “However, the expanded inventory of high-return investment opportunities in our liquid-rich basins, which now totals over 7,500 drillable locations at around 4.5 billion boe potential, has resulted in minimal capital allocation to the Marcellus.”

Current Marcellus production is 415 MMcfe/d, 88% weighted to natural gas, with proved reserves of 1.5 Tcfe. The buyer is assuming responsibility for up to 430 MMcf/d of firm transportation contracts established to support the production. Noble is retaining its dedication to Cone Midstream Partners LP for gas gathering, and Noble’s interest is not included in the transaction. Noble and Consol Energy Inc. each hold a34.2% stake in the midstream operator.

The transaction is set to be completed by the end of June, with proceeds used to pay down essentially all of the debt from the $2.7 billion Clayton Williams Energy Inc. deal announced in January and completed in April, which expanded its holdings in the Permian’s Delaware sub-basin in West Texas.

”Scratching the Surface’ in Onshore

“With the recent portfolio enhancements I’m completely confident that our U.S. onshore position has the best assets, our teams will deliver the best execution, and combined, this generates industry-leading production and cash-flow growth for years to come,” Stover said during a conference call Tuesday. “We’re just scratching the surface on increasing our onshore resource potential from enhanced completions and staff pay. Our growth from the U.S. onshore is also becoming more visible as activity levels accelerate, and we drive sequential increases in our liquids plays throughout the remainder of the year.”

Noble continued to be a gassy producer during the first quarter. U.S. onshore volumes came in at the top end of guidance at 240,000 boe/d, 49% weighted to natural gas, 31% to oil and 20% to NGL. The Denver-Julesburg (DJ) Basin in Colorado averaged 107,000 boe/d, the Eagle Ford Shale in South Texas averaged 43,000 boe/d, and the Permian’s Delaware averaged 14,000 boe/d. Sales volumes in the Marcellus averaged 433 MMcfe/d, with the remaining 4,000 boe/d from other onshore areas.

Sales volumes in the Gulf of Mexico also hit above the top end of guidance at 30,000 boe/d, reflecting strong output from the Big Bend, Dantzler and Gunflint fields. Meanwhile, Noble sanctioned the first phase of the Leviathan gas project offshore Israel during the first quarter, with production slated to begin in 2019.

The big focus during the conference call was the U.S. onshore, where between January and March, Noble maintained on average seven operated rigs — three in the Delaware and two each in the DJ and Eagle Ford. In the DJ, the company drilled a record long lateral well of 9,700 feet in less than 4.3 days. Meanwhile, compared to 2016, the average drilling cost/foot in the Delaware during 1Q2017 fell 30% from drilling time reductions and lateral length extensions of 20%.

To keep ahead of the strong growth in the Delaware, Stover highlighted Noble’s majority ownership in Noble Midstream Partners LP, which launched last year. “A first central gathering facility will commence start-up in the Delaware Basin in the next few months with a second by the end of the year.” The partnership also expanded its Delaware operations earlier this year by acquiring with Plains All American Pipeline LP a crude oil pipeline system.

In the Delaware, three Wolfcamp A wells ramped up during the first quarter with average 30-day initial production rates of 1,730 boe/d, or 365 boe/d/1,000 lateral feet. In the DJ, oil increased as a percentage of total production to a record 52%, driven by the Wells Ranch and East Pony development. Higher proppant concentrations continued to outperform the DJ type curve by more than 50%, including initial tests of enhanced completions in East Pony.

Operations chief Gary Willingham provided more context about growth in the DJ, Delaware and Eagle Ford during the conference call.

DJ Optimization

“With just a few small changes, we already expect completion cycle time for long laterals to improve by 10% in the DJ Basin,” he said. “And on well productivity beyond proppant concentration, we are honing in on optimal stage length in cluster spacing, assessing ways to improve the fracture effectiveness and generate even greater capital efficiency per well. We’re also devoting more resources to advance analytics to generate faster analysis of completion design performance and allow for even quicker design modifications that will deliver the most effective completions possible.”

In the Delaware, he said, “there is a lot more to come…We just finished drilling and completing our first pad of 10,000 foot laterals, including our first third Bone Spring well. The wells are timed to commence production with the startup of Noble Midstream’s central facility around midyear.

“With 10 to 15 wells coming online in the second quarter, and 20 wells per quarter by the end of the year, we’ll be gathering more data on the effectiveness of different completion designs and the result of these wells will provide much greater visibility for our long-term growth.”

Eagle Ford production growth from South Gates Ranch completion also has ramped up, with wells producing more than 500,000 boe over about 120 days drilled with 7,000-foot laterals.

“Already, robust rates of return have been enhanced even further” in the Eagle Ford because of recent improvements in natural gas liquids realizations, Willingham said. “Production from the Eagle Ford is currently trending around 55,000 boe/d and will continue to ramp up with close to 30 of these highly prolific wells online by the end of the year.”

The Houston-based operator reported net income of $36 million (8 cents/share) in 1Q2017, reversing a year-ago loss of a loss of $287 million (minus 67 cents). Operating expenses fell 12.7% to $1 billion. Total organic capital expenditures were $616 million, with more than 75% directed to the U.S. onshore. Another 20% was spent in Israel.

Commodity price realizations benefited from continued transportation optimization, with U.S. onshore crude oil differentials about $2/bbl less than West Texas Intermediate (WTI), while NGL pricing represented 47% of WTI, and U.S. onshore natural gas averaged slightly above Henry Hub. Operating expenses in 1Q2017 including lease operating expenses (LOE), production taxes, and midstream expenses, averaged $8.83/boe, with LOE/boe about 5% lower year/year.