April 2019, Vol. 246, No. 4

Offshore & Gulf of Mexico Report

Future of US Offshore Sector

By Richard Nemec, Contributing Editor  

One of the early lessons of the new year that revealed itself in the first few weeks of January is there is a renewed bullishness in the offshore oil and natural gas potential for the Gulf of Mexico (GOM).

Whether this early enthusiasm turns into a real economic and business development will likely be determined in the first half of 2019 or a little later. In the early days this year, professor Loren Scott, an emeritus member of the Louisiana State University (LSU) faculty and author of Louisiana’s annual economic assessment, was adding his authoritative voice to the growing chorus of GOM optimists.

Scott is forecasting $80/bbl oil by next year, and crude prices will help determine the GOM’s future growth.

In his “2019-20 Louisiana Economic Outlook (LEO),” Scott makes a strong case for renewed growth in the Gulf, but only if oil prices grow higher during the period. For Louisiana, which was hit hard by the oil price dive from 2014 through late 2017, Scott now sees job growth returning after a severe state recession as chronicled in his 37th edition of LEO is published by LSU’s Economics & Policy Research Group.

“The Louisiana economy emerged from a 28-month recession in late 2017 that cost the state more than 23,000 [net lost] jobs,” Scott writes, calling it “odd” because most of the losses were in the oil and gas sector. He counted 37,800 jobs lost in just two population centers – Lafayette and Houma – at the same time that the Lake Charles, La., area was the nation’s fastest growing metropolitan statistical area. LEO turns a lot of this around, assuming there isn’t another global oil price crash.

According to Scott, Louisiana could add up to 60,000 new jobs over the next two years, surpassing the two-million-job mark for the first time. He sees the operations bottoming out this year and beginning their growth spurt especially in 2020. That’s when Scott sees the $80/bbl oil emerging.

Aside from oil and gas, a major driver for the predicted growth is robust industrial expansions along the Calcasieu Ship Channel in Lake Charles and along the Mississippi River between Baton Rouge and the mouth of the river. There are more than $170 billion in industrial expansions pending.

Some of the world’s largest producers are still very active in the GOM in 2019 – BP plc, units of Royal Dutch Shell, Anadarko Petroleum Corp., and Chevron Corp. Furthermore, they tend to expand their drilling near existing production sites in the Gulf.

A lease sale near the end of last year saw only mild interest, but the parcels that did sell went mostly to units of BP and Shell, one analyst pointed out following the sale. And those sales were near the two giants’ existing operations.

Further evidence for GOM optimism is found in an $830 million signing on one of the final business days of 2018 by Switzerland-based Transocean Ltd. for a rig design and construction contract and a five-year drilling deal with Chevron.

The project is described by Transocean officials as “one of its two dynamically positioned ultra-deepwater drillships currently being built at the Jurong Shipyard in Singapore. “The rig will be the first ultra-deepwater floater rated for 20,000 psi operations when it goes into service in GOM in the second half of 2021,” according to Transocean.

Globally at the outset of 2019 a number of positive signs were emerging among offshore drilling rig operators who have consolidated since the crude price meltdown began in mid-2014. Norwegian and Dubai-based Borr Drilling released a report in early January, citing a number of new contracts for jack-up and semi-sub rigs.

Borr’s report added to the optimism for offshore generally. At the start of the New Year, Borr was awaiting up to nine new jack-up rigs being built in Singapore, all slated for delivery between now and the end of 2020. The consensus in the industry now is that the price crash helped clear out all of the undesirable jack-up and floating drilling rigs.

Another key development is that in January, the majors announced 70 new offshore projects. With a host of new, state-of-the-art rigs, contractors are now able to command higher per-day rates and the market is readier to pay them. In January, BP announced plans for an expansion of its third phase in the GOM Atlantis Field where it hopes to produce an added 38,000 bpd by 2020 after its seismic imaging work revealed up to 400 million barrels in place.

The U.S. Energy Information Admin-istration’s (EIA) last look at the GOM included optimistic assessments such as a 31% increase in offshore oil production, 2011-18. Looking forward, EIA is forecasting that the Gulf output will be up another 27% by the end of 2020 to 2.2 MMbpd. EIA also spotted a narrowing in the price differential between light sweet GOM oil and the heavier Gulf supplies.

Sandy Fielden, Morningstar Commodities Research’s director for oil and products research, said in an analysis at the outset of 2019 that the GOM will enjoy a “resurgence in oil output” this year as it should be more attractive in the overall market that he expects over the next couple of years. He cites BP’s moves last year, along with developments by Shell and Chevron, as further support for his rather rosy outlook.

Late in 2018, Chevron produced its first oil from its delayed Big Foot project that was discovered in 2006 and is estimated to produce up to 75,000 bpd over a 35-year life. Also last year, Shell began production from the Kaikias field that was discovered in 2014, just before the global price crash.

“Smaller independent producers funded by private equity are also drilling legacy fields where new wells are tied to existing takeaway and processing infrastructure,” Fielden said.

Traditionally higher priced than onshore shale basins, offshore drilling and production costs are coming down, Fielden notes, citing a late 2018 Wood Mackenzie report that estimated the cost of developing deep-water barrels has dropped by more than 50% since 2013.

 “The difference between break-even costs for onshore shale plays at around $40/bbl and deep-water at $48/bbl has narrowed significantly in recent years,” he said. “The advantage of offshore drilling is that once up and running individual wells can produce as much as 30,000 bpd compared to less than a tenth of that in even exceptional onshore shale wells.”

The decline rates offshore are much slower, too, he added.

Another advocate for the Gulf operators’ ability to keep down operating costs is Moody’s Investors Service’s Sajjad Alam, vice president and senior analyst who has been watching the GOM for years. He doesn’t think exploration expenses will increase a lot, at the current prices, so the E&P activity is continuing to increase.

“If we look out two or three or four years, there will be more new production added,” Alam said.

How about long-term recoverable reserves for the GOM?  “There are definitely a lot of resources, but at what price [as is often said],” Alam said.  “Historically, in the GOM back to the upcycle phase [pre-2014], the break-in costs for new projects would be somewhat north of $60/bbl all the way up to higher than $100, but what has happened in the last four years is that companies have done a lot of work to reduce costs – from design phases to drilling and production phases – through automation and all the other buzzwords you hear about in the industry.”

As a result, some break-even points now are between $35/bbl and $45/bbl. “So, if oil companies are comfortable with prices north of that, they likely will continue to pursue new projects,” Alam noted. “Most of the new project announcements today are close to existing production areas or in existing structures.”

In North America, the ability to reduce oil and gas production costs onshore and offshore has been similar, according to analysts like Alam, who still believe future global prices also will play a role.

 “Companies are spending a lot more time upfront in their designing and planning. In the past, companies used a lot of fabrication and equipment that was unique to a particular project,” Alam said. “Now they are looking very hard at using proven technologies to standardize products used at the drill sites. It is helping bring down costs, and clearly costs have come down big time – onshore and offshore. Rig costs are significantly lower than they were back in 2014-15.

 “There is no doubt drilling costs have come down, but more importantly companies are taking more time in the engineering design aspects upfront. They are spending more time making sure they can develop what they need quicker and more efficiently.”

In assessing the Gulf – either by EIA or the many financial analysts watching the space – the differences from the robust U.S. onshore production is looked at from various angles, including investment, drilling and the very makeup of the crude itself. Geographic locations and technology applications are also part of the puzzle. Alam and Fielden highlight some of these areas in their individual assessments.

For growth in the exploration sector, Alam said Brent prices around $80/bbl are needed, but for expanding the production and periphery of existing areas, lower prices will do the trick.

“Prices between $60 to $80/bbl would probably give us steady growth in the Gulf,” he said. For longer-term growth and development clearly more exploration is needed, he said. “It could take five to 10 and 12 years to bring new discoveries to fruition,” Alam said.

What Fielden calls a “hard fall” in crude prices in the last quarter of 2018 “casts doubt on the economics of any new U.S. crude production, let along shale vs. offshore.” However, he adds that “given recent crude price recovery as OPEC reins in production early in 2019 and interruptions in supplies from Iran, Venezuela and Canada, we see Gulf production remaining competitive in domestic and export markets.”

Among the many market implications for GOM crude supplies is the composition, or quality, of the oil there. Compared to the onshore shale basins’ lighter, sweeter crudes, GOM fields mostly supply medium and heavy crude. The first 10 months last year, EIA indicates that two-thirds of the Gulf output was 30-40 degrees API gravity, and nearly all the rest was heavier, below 30 degrees API. By comparison, most shale supplies are 40 degrees or above, making it more imperative on new shale production to seek export markets.

“These medium and heavy grades are more suited to the U.S. Gulf Coast refineries built to process heavier sour crudes,” said Fielden, who notes a “home field advantage” for GOM supplies in replacing imported feedstock at Gulf Coast refineries.

While remaining a net importer of oil even as it leads the world in production, the United States refineries seek about 17 MMbpd with about 6 MMbpd coming from imports. Last year, imports were higher, about 8 MMbpd because of mismatches in requirements and refinery locations. As a result, last year, nearly 2 MMbpd were exported from the Gulf Coast.

The GOM today includes the U.S. hub for both imports and exports, and the local offshore production can be a factor for both, according to most market analysts. Imports in the Gulf Coast have been declining significantly in recent years, but among continuing imports, heavy and medium crudes predominate.

A decade ago, sweet, light crudes made up 21% of U.S. oil imports; today that is down to 2% in the Gulf. Supplies from GOM can replace some of the heavy crude imports that persist, but they are also increasingly in demand for exports, according to Fielden, who notes that OPEC’s cutback this year will increase the possible export market for Gulf crude.

 “This alternative supplier advantage is also true for Iranian crude supplies removed from the market by U.S. sanctions,” Fielden said. “The majority of their output is medium and heavy crude that Gulf production is a better match for.”

Unlike among the onshore shale plays, there are few glaring new “hot spots” in GOM. Companies emphasize expanding out from existing production areas as exemplified by BP’s discovery early this year in the Mississippi Canyon area that has been drilled over many decades. BP has what its officials describe as a billion-barrel find there.

Longer term, the new discoveries might come from offshore GOM in Mexico. “There has been tremendous interest in getting into the Mexican Gulf,” said Moody’s Alam, calling the Mexican offshore a long-term proposition because of the need for a long-term exploration phase.      

Significant production is definitely a number of years in the future, he said, adding that there is a tremendous amount of interest between Chevron and ExxonMobil in winning some of the Mexican offshore leases. “They’re actively bidding for it,” according to Alam.

Another area of commonality between onshore and offshore U.S. plays involves the significant adaptation of technology to the finding and production of new crude supply sources. As one analyst said, “When we talk to E&Ps, and more importantly service companies we ask them what they are focused on and invariably they say ‘automation’.”

It seems advances in monitoring have been critical for both the drilling and production phases – new surveillance tools, all sorts of digital applications, real-time technology that allows for knowing what is happening in the drill bore at any point in time.

Moody’s Alam cites BP’s ability to do seismic work a lot faster with better resolution, giving them a better view of what’s beneath the rock. 

“In the past that work has taken a very long time, but now with super computers it can be done very fast,” he said. “There has been a lot of investment in super-fast computers that can do a lot more data mining, and as a result, they get the output from these seismic shoots a lot faster and with greater precision.”

Seismic technology improvements and monitoring of the wells are the two big areas of technology advances, Alam said. Rather than a lot of fabrication work to suit one drill site, now they try to standardize everything they can to it the cost-saving of mass production.

 “They found the cost of the standardized products to be 50% less,” he said. “They are really pushing standardization and it’s paying off. Of course, the producers are getting much better at operating in the deep waters, too.”

Generally, the presence of four majors in the Gulf (BP, Shell, Anadarko and Chevron) and the continuing favorable economics are projecting GOM prospects as a sweet spot in the next two years. Both Fielden and Alam confirm that their separate analyses say it is one of the regions that growing E&P companies want to be going forward.

BP and the other majors are “very much committed to growing the GOM with multiple projects and billions of dollars invested,” Alam said. “These big companies have mostly deep water assets, and the deep is much more oily than shallow Gulf waters; about 80% of their investments are in the deep plays where the costs have come down.

“There are also mostly shallow water-focused companies, too, and these guys have a focus on maintaining production,” he said, citing companies like Fieldwood Energy LLC and LLOG. The break-evens are close to $50/bbl so the GOM remains quite attractive.”

While declaring that Gulf production should remain competitive with both domestic and export markets, Morningstar’s Fielden said the offshore region’s market advantages are only one factor producers consider.

 “Heavy investment in shale drilling since mid-2016 has produced a flood of new light crude with at least a million barrels a day more expected this year and into 2020,” he said. “Shale producers are unlikely to abandon ship and head for offshore platforms en masse. But as the United States consolidates its position as one of the world’s largest producers and exporters, the long-term value and importance of offshore production shouldn’t be underestimated.” P&GJ


Richard Nemec is P&GJ’s Los Angeles-based correspondent. He can be reached at: rnemec@ca.rr.com

BP, already active in the GOM, had what company officials described as “a billion-barrel find” in Mississippi Canyon. Photo courtesy of BP

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