French oil major Total SA has exercised its preferential rights to leapfrog over a prospective buyer and become sole owner and operator of the Barnett Shale leasehold it has co-owned with Chesapeake Energy Corp. since 2009. Meanwhile, Chesapeake is boosting its annual production growth target — even with the Barnett sale — and forecasting cash flow neutrality in 2018.
The transaction, announced Friday, would allow Total E&P USA, which already holds a 25% stake, to assume Chesapeake’s 75% interest in the North Texas play, where they have partnered since 2009 (see Daily GPI, Jan. 5, 2010). The deal includes 215,000 net acres, 2,800 operated wells, leases, minerals, buildings and properties. The leasehold is 96% weighted to natural gas.
Total’s strike trumps a deal put together by Chesapeake last month that would have conveyed the Barnett stakes by the end of this month to First Reserve Corp.-backed Saddle Barnett Resources LLC (see Shale Daily, Aug. 11).
“Over the six years that we have been involved in the Barnett, we have gained an in-depth understanding of the play and the technology,” said Total E&P CEO Jose Ignacio Sanz. “With the new conditions created by the exit of Chesapeake and the associated restructuring of the midstream contracts, we believe that we can extract significant value from the substantial, well located resource base of the play by combining focused upstream operating efficiency, streamlined midstream contract management and marketing savvy through Total’s trading affiliate Total Gas & Power North America.
“As an operator, we look forward to working with all stakeholders, our leaseholders, the Dallas-Fort Worth and other authorities, Williams and other midstream partners, and our customers. Increasing our stake in the Barnett shale supports Total’s global strategy to be a leader in natural gas.”
As part of the deal announced with Saddle, Chesapeake was to terminate its costly Barnett gas gathering agreement with Williams Partners LP, which processes around 80% of the gas, and agreed to pay the partnership $334 million to terminate projected minimum volume commitment (MVC) shortfall payments and fees. Under the new agreement, Total would pay Williams another $420 million, which Saddle already had agreed to, as well as $138 million to be released from three midstream capacity reservation contracts.
With the Williams payment, Total expects to achieve “a fully restructured, competitive gas gathering agreement, free of any MVC and with a Henry Hub-based gathering rate instead of a fixed per Mcf fee.”
The preemptive deal and the associated transactions are subject to third-party consents. All things being equal, Total expects to have the entire Barnett leasehold in hand by the end of the year.
Production in the Barnett currently stands at about 65,000 boe/d, versus Total’s entire U.S. output last year of 89,000 boe/d. Total in late 2011 discreetly joined Chesapeake as a one-quarter partner in its Utica Shale development (see Shale Daily, Nov. 11, 2011; Nov. 5, 2011). In the Gulf of Mexico, Total has an interest in two deepwater facilities, Chinook (33.3%) and Tahiti (17%). It also is working with Cobalt International Energy LP on strategic deepwater projects (see Daily GPI, April 7, 2009).
During a presentation at the Barclays CEO Energy-Power Conference in New York City on Thursday, Chesapeake CFO Nick Dell’Osso said the company now is targeting 5-15% annual production growth for 2016-2020. Cash flow neutrality should be achieved in 2018, as the company continues to slash its total leverage, which is now down by half from 2012.
Since the start of this year, Chesapeake has completed an estimated $1.1 billion in asset sales and expects to sell another $900 million before year’s end, said the CFO. Debt by the end of 2016 should fall by $2-3 billion.
“On the $2-3 billion, it really depends on a number of things, but when you think about a good portion of that being achieved this year through the remaining assets that we have in front of us, we know we’ve got a good head start,” Dell’Osso said.
Nowhere is Chesapeake’s turnaround more striking than in its reduced capital expenditures, which have fallen to about $1.3-1.8 billion this year from a whopping $14.7 billion in 2012. Regardless, production has remained relatively flat over the last four years at 618,000-638,000 boe/d versus 648,000 boe/d in 2012. Cash costs in the past four years also are down by about half to $4.10/boe from $7.80, while lease operating expenses have fallen to 80 cents/boe from $2.28.
Production-wise, the Haynesville Shale still is the big daddy for a lot of near-term gas growth as efficiencies and longer laterals help Chesapeake step up its game. Last month during the 2Q2016 conference call, CEO Doug Lawler cited the “three major gas assets” as the Haynesville, Eagle Ford and Marcellus shales,” each able to produce more than 30 MMcf/d (see Shale Daily, Aug. 5). He spent considerable time promoting the Haynesville, where the largest completion in company history used more than 30 million pounds of sand.
Said Lawler, “We call this new era in completion technology, ”proppant-geddon.’ We’ve not yet reached the point of diminishing returns in the Haynesville, and we plan additional tests up to 50 million pounds in the back half of the year.”
Dell’Osso backed up the renewed Haynesville enthusiasm in his presentation, pointing to a well in DeSoto Parish, LA drilled with a 10,000-foot lateral, resulting in initial production of 38 MMcf/d.
“The pressure stayed very high, the drawdown per day has been very low, and this well continues to perform extremely well,” he said. “We don’t think we found a point of diminishing returns yet” in the big gas play.
Longer laterals also should benefit drilling in the Eagle Ford Shale, where a “traditional” well costs about $2.1 million to complete. “You put that against the higher oil recoveries of a 10,000-foot lateral…and it’s pretty attractive.” A “little bit” more capital may be directed to the Utica next year, but it’s not the priority — for now.
“We have that flexibility in each one of our plays, whether it be the Haynesville, the Eagle Ford, the Utica, the Marcellus…to go back in and fully develop these areas to their highest and best use,” he said.
© 2021 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 1532-1266 | ISSN © 2158-8023 |