Deepwater, tight oil share similar growth themes, Both tight oil and deepwater have vital roles to play, WoodMac says

Deepwater, tight oil share similar growth themes, Both tight oil and deepwater have vital roles to play, WoodMac says

 

Deepwater projects and tight oil plays are two upstream growth areas even though offshore and unconventional often are considered at opposite ends of the development spectrum, a Wood Mackenzie Ltd. researcher said.

Deepwater represents large, expensive and complex long-cycle projects best suited to Big Oil. In contrast, tight oil offers flexible short-cycle opportunities more favored by nimbler independents, WoodMac said.

But both have undergone a rapid transformation over the past few years, and many assumptions industry once held no longer hold true, WoodMac continued.

Angus Rodger, director, Asia Pacific upstream, at global natural resources group Wood Mackenzie, said: “In both deepwater and tight oil, costs have come down, while development techniques have improved, allowing vast new reserves to breakeven under $50.

“In mid-2014, 9 billion barrels of oil equivalent (boe) of undeveloped Permian tight oil had a breakeven under $50 per barrel of oil equivalent (boe) (all NPV,15), versus 5 billion boe in pre-FID deepwater. By mid-2019, 33 billion boe breaks even under $50/boe in deepwater, versus a whopping 66 billion boe in the Permian. The latter dominates the pre-final investment decision (FID) future cost curve for oil, which is staggering, given it is just a single basin.”

 

Reinvention sparks deepwater revival

 

He added: “Tight oil’s progression from cottage industry to industrialization is primarily a Permian story, but it is still in its early stages. It used to be all about price-responsive flexibility and well-by-well economics. Now scale is the key differentiator. ‘New’ tight oil is industrialized, and that requires more capital and infrastructure, and longer cycle times.”

At the same time, the deepwater industry has also been reinventing itself, cutting costs, cycle-times and breakevens. The main beneficiaries of this are a handful of advantaged sweet spots, such as Brazil, Guyana and the Gulf of Mexico.

Wood Mackenzie estimates global deepwater project costs have fallen more than 20% since 2014. The research and consultancy firm also said 5 billion bbl of presanction deepwater reserves now breakeven at $50/boe assuming a hurdle of 15% internal rate of return (NPV15).

By comparison there are 15 billion bbl of tight-oil resources in undrilled wells with breakevens of $50/boe or lower at a 15% hurdle rate in WoodMac’s dataset.

Cost inflation is reentering the tight-oil market while deepwater operations costs continue to soften. WoodMac estimates that a further 20% cut in current deepwater costs would bring 15 billion bbl of pre-FID reserves into contention, which is in line with tight oil.

According to the firm’s report, a 20% rise in tight-oil costs would even out the cost curve providing equal opportunities in deepwater measured by volume at $60/boe.

They are two vastly different resource themes, but there are signs of convergence. Deepwater is trying to slim down and shorten its investment cycle to offer a viable alternative to tight oil. And the Permian going the other way, scaling-up capital spend, project footprint and value extraction. This plays into the hands of the Majors, who can use their capital and big project capabilities to lead the next phase of tight oil development.

“There are other similarities too,” Rodger said. “At present, both currently produce around 7.5 million barrels per day (b/d), and each is poised for a sustained period of rising output. Both themes are growing, but tight oil – with its underlying low-cost resource base – is growing faster.”

The philosophy behind Permian development is changing, and projects today look very different from a few years ago. Wells used to be drilled on smaller pads, laterals were shorter, completions less aggressive and subsurface models constantly in flux.  But after drilling more than 10,000 horizontal wells in the play, industry now knows where the best rock is.

Rodger said: “The focus has switched to exploitation, increasing recovery and improving incremental economics. And engineers discovered that bigger really is better. Experiments proved that well economics improved with more aggressive completions and longer laterals.

“Once big became beautiful, the stage was set for the industrialization of the Permian. Pads doubled, then tripled in size. Beneath them operators were targeting every producible zone with an onslaught of drilling.

“This approach requires considerably more capital, planning and infrastructure than the well-by-well model, but the added complexity and upfront capital are worth it if economies of scale can be successfully delivered. And it makes the unconventional model starts to look considerably more conventional.”

 

Resetting the economics

 

Rodger added: “On the other hand, it’s hard to conceive how deepwater could be more like tight oil. But while the nature of deepwater hasn’t fundamentally changed, the investment proposition has.

“There has been an impressive reset of deepwater economics. Pre-FID projects breakevens have fallen 37%, from an average $79/boe down to $50/boe (NPV,15). Average development capex/boe has fallen from over $20/boe in 2013 to under $8/boe today.”

There has been a step-change in development philosophies too. To compress the investment cycle, boost returns and compete with tight oil, companies have focused on bringing fields onstream quicker via simpler development concepts, including more subsea tiebacks.

“Simpler projects are quicker – from 2004 to 2014 the average project took 10 years from discovery to come online. From 2015, the time from discovery to first production has halved to five years. Leading the way are new low-breakeven developments in the US Gulf of Mexico and Angola,” he said.

And the success of fast-cycle development techniques deployed by players such as LLOG and Kosmos has proved you no longer need to be big to create value from deepwater, particularly in the US.

 

Deepwater payback period and lead time

 

woodmac-deepwater-tight-oil.jpgRodger added: “Big Oil will be the big winner from the convergence of tight oil and deepwater. With strong balance sheets that are self-funding at $55 per barrel of oil, each has investment optionality, making choices based on risk and return.

“The Majors’ longer-term investment horizon also allows them to invest through the cycle in both deepwater and tight oil.

“The Permian will be central to driving corporate strategies for players of all sizes. Many US Independents will need to scale up to compete as industrialization gathers pace, but not all have the skills and capital to do so.”

A more concentrated, differentiated corporate landscape will start to emerge. A key theme for all will be to focus on advantaged assets. Rationalization will be an especially important strategic theme for those players with large, low-breakeven tight oil and deepwater inventories. Portfolio high-grading will create more opportunity for NOCs, conventionally focused Majors and internationally focused Independents.

These combined trends may force many of the larger US Independents to reassess the wisdom of abandoning both deepwater and international portfolio positions.

Rodger said: “Having a diverse inventory of low-breakeven oil opportunities will be key to thriving as the energy transition unfolds – and both tight oil and deepwater have vital roles to play.”

 

 

Deepwater and tight oil are two of the great growth themes in our industry, but are often considered to be at opposite ends of the development spectrum. Deepwater represents large, expensive and complex long-cycle projects best suited to Big Oil. In contrast, tight oil offers flexible short-cycle opportunities appropriate for nimbler Independents.

But both are transforming rapidly, and look very different from just a few years ago. Many long-held industry assumptions no longer hold true.

1. 7.5 million barrels a day and rising

Global deepwater and US tight oil both produce around 7.5 million barrels per day. And each is poised for a sustained period of rising output. 

However, the trajectory of growth differs, given tight oil's position on the cost curve. Deepwater is growing but tight oil – like its underlying low-cost resource base – is growing faster.

2. Big becomes beautiful in the Permian

Tight oil's natural progression from cottage industry to industrialisation is primarily a Permian story, but it is still in its earliest stages. It used to be all about price-responsive flexibility and well-by-well economics. That's 'old' tight oil. Now scale is the differentiator. Big M&A, big resource upgrades and even bigger production targets dominate headlines. 'New' tight oil is industrialised, and that requires more capital and infrastructure, and longer cycle times.

 

3. Deepwater evolves to keep up

At the same time, the deepwater industry has also been reinventing itself, cutting costs, cycle times and breakevens. The latter have fallen 37% for pre-FID projects, down to an average US$50/boe (NPV15). The increased use of phasing and subsea tiebacks has slashed time to first production. But the main beneficiaries are a handful of sweet spots, such as Brazil, Guyana and the Gulf of Mexico. Vast areas of the deepwater map refuse to slide down the cost curve and into contention, primarily due to higher local costs and tougher fiscals.

 

 

 

Two vastly different resource themes, but there are signs of convergence. Deepwater, trying to slim down and shorten its investment cycle to offer a viable alternative to tight oil. And the Permian going the other way, scaling up capital spend, project footprint and value extraction. 

The unconventional model is starting to look considerably more conventional in structure. And vice versa.

Does convergence change company investment options? 

The US Independents certainly need to think about life beyond the Permian. There's little support at present from capital markets for international exploration and production. Yet for all the growth it offers on a five-year view, the Permian won't last forever. 

A key theme for all companies will be to focus on advantaged assets. Rationalisation will be an especially important strategic theme for those players with large, low-breakeven tight oil and deepwater inventories. Portfolio high-grading will create more opportunity for NOCs, conventionally focused Majors and internationally focused Independents. Nimbler, specialised smaller players will also be able to capitalise on niche opportunities. The success of fast-cycle development techniques has proved you don't need to be big to create value from deepwater, particularly in the US.

 

 

 

 

 

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We are seeing participation of deep water and ultra deep water players into shale but not vice versa.

 

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While the media is often focused on how multibillions are being poured into energy transition projects worldwide (usually focusing on solar and wind), global oil and gas is busy wooing financial investors--some of which seem wary to stay linked to hydrocarbon projects. The potential problem will not bet be related to a lack of investments in renewables but the reduced availability of available financing for existing and future oil and gas projects. The influx of cash into U.S. shale oil and gas may be hiding the real situation on the ground, which may be bleaker than we realize.

Conventional oil and gas projects are lacking mainstream finance options it seems, countering the prevailing media reporting about the majors' high-profile multibillions in profits and increased dividends for shareholders. The media reporting about Shell’s decision to handout more than $125 billion to its shareholders during the next couple of years, which has made headlines, is distracting focus from the situation of the majority of the smaller operators and oilfield service companies.

The total oil and gas sector is far from out of the woods, as debts have become a real burden for many companies. When looking at the offshore sector, the situation has become dire. Debts are staggering, while investments in offshore upstream projects have been faltering. The latter has resulted in a severe liquidity crunch, hitting offshore drillers and oilfield services companies. The latter situation has been discussed at a oil and gas conference in Oslo, Norway recently, where offshore bankers painted a dire picture. Hit by high debt levels and low dayrates for vessels and rigs, companies are struggling to refinance operations. At the same time, the current volatility in the oil and gas markets has constrained major investments into offshore developments during the last few years. The only current bright spots are in the Arabian Gulf, the Red Sea and East Mediterranean.

Offshore service companies such as Seadrill, Solstad Offshore and DOF are still worried about the future, as the market's slow recovery has not yet resulted in better financing options. Globally, analysts are not expecting a real improvement before 2021. The main issue for most service companies is debt being too high, which could result in restructuring or even bankruptcy. As Bloomberg reported earlier this month, “the global offshore drilling outlook remains bleak, with contract coverage expected to be below 55 percent for the rest of 2019, amid a net rig supply increase of 54 rigs year-to-date.”

Some companies have been able to get loans lately, but the majority are still hunting for cash. With institutional investors and banks mainly looking at developments in the U.S., it may be time to restructure or re-educate financial advisors too. The future may not revolve around U.S. shale and gas, as investments there are going to be very high risk. At the same time, U.S. operators are already struggling to meet their debt reduction goals. Some relief has come from the OPEC+ oil price strategy, but the debt is still suffocating.

Western capital discipline is now a potential threat. If banks are not willing to provide adequate financing, operators increasingly will have to look for alternative financing options. The latter could also lead to a fire sale of assets or companies to incumbents from other regions. Looking at the current developments in the Middle East, North Africa and Africa, it would not come as a surprise if Arab investment funds or “private” oilfield service companies are going to hunt for opportunities that emerge in the West. Some acquisitions have already have been made, but no major offshore oilfield services companies have been targeted yet. Looking at some of the key names in the space and their financial situations, it doesn’t take a rocket scientist to see the opportunity on the horizon.

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WOW, so offshore operators should be forced to shut in their wells too? because costs overruns will create more debt? industry segment will not be profitable? offshore running on the hamster wheel?

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Cost Overruns Threaten Offshore Development

The prospect of oil prices remaining at about $60 a barrel, combined with impressive cuts in development and operational costs since 2014, have encouraged E&P companies to accelerate development of their offshore projects including Mad Dog Phase 2 in the Gulf of Mexico, the Azeri–Chirag–Gunashli in the Caspian Sea and the Tortue and Bonga Southwest field off the coast of West Africa.

Indeed, Rystad Energy expects sanctioning of offshore field projects to rise to around $100 billion a year over the next four years, or double the annual average of 2015-18. But, rushing the final investment decision, especially for tailor-made designs, can increase uncertainty over the final cost by as much as 20 percent either way. Consequently, “for offshore operators, that means the expected variation for projects to be sanctioned during the period from 2019 to 2023 could be as high as $220 billion” according to a June 2019 study by Rystad Energy.

The need for good planning

Quite naturally, the success rate of sanctioned projects around the world varies widely. As Rystad Energy demonstrates, even taking into account funding based on a thorough engineering definition, operators could still see a cumulative $111 billion cost overrun. Indeed, Rystad has found cases in which accelerating a sanctioning decision without proper engineering definition can often result in actual costs exceeding target costs by up to 50 percent.

The $60 a barrel challenge

Matthew Fitzsimmons, VP, Cost Analysis at Rystad Energy, notes that “even if oil prices stay above $60 per barrel over the next five years, final investment decisions could take longer to reach” to allow for sufficient time to mature the engineering definition and “ this will lower the uncertainty that their funding estimates will carry.” He warns that “failure to do so will not only have an adverse impact on the operator’s ability to control cost overruns but also the minority share owners of the field.”

Recent well-publicized cost overruns are a wake-up call and signal the vital importance of proper project planning and implementation. For example, the cost estimate for Shell’s huge Prelude FLNG project was $11 billion back in 2011. Nonetheless, due to the unforeseen mega engineering and fabrication challenges posed by this pioneering venture, development costs ballooned to around $15 billion – an increase of more than 36 percent. The scale of this cost overrun caused the major to cancel its order for another three FLNG units worth around $4.6 billion from Samsung Heavy Industries.

Impact on oilfield support companies

Since the oil price debacle of summer 2014, oil producers have become even more cost conscious and have imposed strict controls over their capital expenditures. This has been achieved largely in-house, with many operators opting for fewer, but better drilled wells, alongside more phases per development, whilst employing the latest technology, modularization and standardization of equipment and parts. The drive to reduce costs has inevitably had a knock-on effect on the profitability of major oilfield service companies including Schlumberger, Halliburton, Transocean and Norway’s Aker solutions, which competed for work in the downturn and temporarily reduced their fees. Indeed, the major oil companies have been remarkably successful in driving the average pre-final investment decision break-even point down to US$49 per barrel of oil equivalent compared with a pre-crisis $78 in 2014, according to a Wood Mackenzie report released November 2018.

While break-even costs of deep-water projects have fallen and industry profits and confidence are up, the supply chain and oilfield service companies will once again try to raise fees as demand for their services rises with increased activity. Simultaneously, industry insiders doubt whether the oil majors have fully factored in Rystad Energy’s findings on likely cost inflation in forthcoming projects.

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