LONDON (Reuters) - Having turned round its North American shale business, Royal Dutch Shell is putting so-called unconventional energy at the heart of its growth plans, and believes lessons from the revamp can be applied across the company.
Greg Guidry, head of the Anglo-Dutch group's unconventionals business, told Reuters a drive to slash costs and streamline decision-making had put his division largely on a par with leading rivals in terms of productivity and efficiency.
And now the rest of Shell could reap the benefits too.
"The executive committee charged us to be a catalyst for change within the broader Shell," Guidry said in an interview.
He also said Shell planned to make small acquisitions near its existing North American shale areas, notably from producers struggling in the current industry downturn, and hoped to launch an early production well this year in Argentina's Vaca Muerta, considered the world's No.2 shale resource after North America.
That's quite a change in fortunes.
As recently as late last year, Shell Chief Executive Ben van Beurden was considering jettisoning the unconventionals business over concerns it would drag down group profitability after the group's $54 billion acquisition of BG Group in February.
Shell and rivals including Chevron and Exxon Mobil were late to the shale revolution at the end of the last decade and struggled to match the success of smaller independent producers that increased U.S. output by around 4 million barrels per day between 2008 and 2015.
Oil majors' often cautious pace in complex, high-risk projects was ill-suited to the nimble needs of shale, which requires drilling hundreds of wells and injecting water at high pressure to break the rock that holds oil and gas.
So Shell moved to adapt.
In recent years, it has shed half of its North American unconventional assets for around $4 billion to focus on four areas in the United States and Canada.
It has cut its technical check-list for drilling shale wells from 20,000 requirements to less than 200 and given managers "end-to-end" control of the production process from well exploration through to well abandonment, Guidry said.
The division's efficiency has risen by 50 percent over the past three years, production has grown by 35 percent and capital spending is down by 60 percent to around $2.0-$2.5 billion.
Today, Shell makes a profit from shale oil production in "sweet spots" in the Permian or Duvernay in Canada with crude prices of $40 a barrel, Guidry said. After dipping below $30 in January, Brent crude is currently trading around $48.
"In terms of execution, we are completely competitive and have aspirations to be leading," Guidry said, adding the business could now compete with leading shale producers such as Pioneer Natural Resources and EOG Resources though costs still could be reduced.
Advances in technology meant there was scope to increase oil recovery from shale rock from today's 7-9 percent by another 1-3 percent over the coming years, Guidry added.
"That is billions of barrels. We absolutely can reach that," the 55-year-old American said.
And unlike multi-billion deepwater projects, shale can be turned on "with the drop of a hat," Guidry said.
At around 300,000 barrels per day, shale today represents around 8 percent of Shell's overall production. However, Shell holds shale reserves of around 12 billion barrels, roughly as much as its deepwater resources, Guidry said.
The shale business got its reward earlier this month when Van Beurden identified it as a key growth priority for Shell in the next decade along with renewable energy.
What's more, Shell engineers are now using the experience in the shale business to improve deepwater projects, which helped knock out $1.5 billion in costs for the development of the Stones field in the Gulf of Mexico.
As oil producers scrap costly and complex projects such as deepwater fields and sharply reduce budgets in the face of the oil price downturn, they are turning again to onshore shale which offers quicker returns and lower investments.
Some analysts, including at Bernstein, still argue Shell should divest the shale business to focus on core strengths such as deepwater and liquefied natural gas (LNG), which are generating larger profits.
"Surely private equity would have offered some healthy cash proceeds for this business today," said Bernstein analyst Oswald Clint, who rates Shell shares "outperform".
But analysts at U.S. investment bank Tudor Pickering, Halt and Co. see growing value in Shell's unconventional portfolio, particularly in the Permian basin, which they value at $13 billion if oil hits $75 a barrel.
"We believe Shell's North American unconventional portfolio is less core relative to global deepwater and LNG but we do see additional value that should command a premium multiple when compared to its European supermajor peers," they said.
By Ron Bousso
(Editing by Mark Potter)
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A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference
Global liquid fuels
Electricity, coal, renewables, and emissions
Source: U.S. Energy Information Administration, U.S. liquefaction capacity database
On May 31, 2019, Sempra Energy, the majority owner of the Cameron liquefied natural gas (LNG) export facility, announced that the company had shipped its first cargo of LNG, becoming the fourth such facility in the United States to enter service since 2016. Upon completion of Phase 1 of the Cameron LNG project, U.S. baseload operational LNG-export capacity increased to about 4.8 billion cubic feet per day (Bcf/d).
Cameron LNG’s export facility is located in Hackberry, Louisiana, next to the company’s existing LNG-import terminal. Phase 1 of the project includes three liquefaction units—referred to as trains—that will export a projected 12 million tons per year of LNG exports, or about 1.7 Bcf/d.
Train 1 is currently producing LNG, and the first LNG shipment departed the facility aboard the ship Marvel Crane. The facility will continue to ship commissioning cargos until it receives approval from the Federal Energy Regulatory Commission to begin commercial shipments. Commissioning cargos refer to pre-commercial cargo loaded while export facility operations are still undergoing final testing and inspection. Trains 2 and 3 are expected to come online in the first and second quarters of 2020, according to Sempra Energy’s first-quarter 2019 earnings call.
Cameron LNG has regulatory approval to expand the facility through two additional phases, which involve the construction of two additional liquefaction units that would increase the facility’s LNG capacity to about 3.5 Bcf/d. These additional phases do not have final investment decisions.
Cameron LNG secured an authorization from the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as to countries with which the United States does not have Free Trade Agreements (non-FTA countries). A considerable portion of the LNG shipments is expected to fulfill long-term contracts in Asian countries, similar to other LNG-export facilities located in the Gulf of Mexico region.
Cameron LNG will be the fourth U.S. LNG-export facility placed into service since February 2016. LNG exports rose steadily in 2016 and 2017 as liquefaction trains at the Sabine Pass LNG-export facility entered service, with additional increases through 2018 as units entered service at Cove Point LNG and Corpus Christi LNG. Monthly exports of LNG exports reached more than 4.0 Bcf/d for the first time in January 2019.
Source: U.S. Energy Information Administration, Natural Gas Monthly
Currently, two additional liquefaction facilities are being commissioned in the United States—the Elba Island LNG in Georgia and the Freeport LNG in Texas. Elba Island LNG consists of 10 modular liquefaction trains, each with a capacity of 0.03 Bcf/d. The first train at Elba Island is expected to be placed into service in mid-2019, and the remaining nine trains will be commissioned sequentially during the following months. Freeport LNG consists of three liquefaction trains with a combined baseload capacity of 2.0 Bcf/d. The first train is expected to be placed in service during the third quarter of 2019.
EIA’s database of liquefaction facilities contains a complete list and status of U.S. liquefaction facilities.