Offshore in depth

About 15 years ago, I worked for a former oil company president who had become CEO of our large oilfield services firm. He brought us a different world-view, having lived at the top of the E&P food chain. He led his new management team through a lengthy scenario-planning exercise to instill a long-term perspective that was uncommon in service companies. In every scenario, the CEO drove the discussion to one conclusion: “The super-majors always win.”

Flat-footed dinosaurs? In the early 2000s, the conventional view was that national oil companies controlled most of the world’s undeveloped reserves, and could buy technology and expertise from the large service companies. The super-majors were dinosaurs who would soon be extinct. Unconvinced, our CEO contended that the super-majors would remain dominant because they had unmatched financial resources, project management experience and global reach.

By 2008, as shale plays began to take off in North America, the super-majors seemed to be caught flat-footed, as nimble independents ramped up quickly in the unconventional basins. It seemed that the super-majors could only compete by acquiring smaller producers. Now, eight years later, more than 150 independents have filed for bankruptcy, while the super-majors have weathered the storm.

Super-majors rule the waves. While the super-majors may have underperformed in the unconventional arena, they have maintained their dominant role offshore, particularly in deep water.

In the current environment, the super-majors have shared a common strategy of “high grading” projects, investing in those promising the best return in a low commodity price environment, while deferring projects with break-even costs above $70/bbl. Every super-major has demanded price concessions from suppliers, and their efforts to standardize equipment and production facilities have reduced capital costs substantially.

Exxon Mobil, the largest super-major, has conducted an aggressive procurement initiative, obtaining 15% to 50% concessions from suppliers. Exxon Mobil’s capital budget for 2015 was $31.1 billion and is projected to be $23.2 billion in 2016.

Exxon Mobil has about 100 field development projects planned through 2020. It operates high-profile, deepwater fields in Angola, Nigeria, Indonesia and the Gulf of Mexico, and has new projects slated for Australia, Indonesia, Nigeria and Vietnam. Its offshore exploration program includes wells in seven countries. In addition to its operated interests, Exxon Mobil is a partner in more than a dozen other deepwater plays.

Royal Dutch Shell. Earlier this year, Royal Dutch Shell relinquished its leases in the U.S. Arctic, but remains committed to deepwater E&P. Shell reduced capital spending from $47 billion in 2014 (including recently acquired BG’s budget), to $29 billion in 2016. Around $8 billion will be for deepwater projects.

With addition of the BG portfolio in Brazil, Shell expects to have 15 FPSOs producing from pre-salt reservoirs by 2020. In the Gulf of Mexico, Shell operates six major deepwater developments. The addition of Stones field, in 2016, and Appomattox, in 2018, as well as projects in Nigeria and Malaysia, will boost Shell’s deepwater production to nearly 1 MMboed by 2020.

BP. Of all the super-majors, BP has suffered most in the past several years. BP reported a net loss of $1.39 billion for the second quarter of 2016. Still, BP is a formidable company, with $222.9 billion in revenue in 2015, and an offshore portfolio that includes 440 lease blocks in the Gulf of Mexico. BP operates nearly 40 North Sea fields and production platforms in Angola, Australia and Azerbaijan.

At Thunder Horse, a water injection project is expected to add 65 MMbbl of production, and a field expansion is scheduled for 2017. Other major offshore projects for 2017 are planned for the North Sea, Trinidad, Angola and Egypt.

Total, whose 2015 upstream capital budget was $20.5 billion, is a significant player in Africa, with deepwater fields in Angola, Gabon, Nigeria and the Republic of Congo, as well as various exploration licenses off Africa’s coast. The company has extensive operations in the North Sea, and operates Asia-Pacific offshore fields in Indonesia, Brunei and Myanmar. Total produced an average of 2.35 MMboed in 2015.

Chevron has cut operating costs significantly, and reduced capital and exploratory spending from $33 billion in 2015, to an estimated $26.5 billion in 2016. Chevron’s major deepwater projects include Agbami field in Nigeria, and Tahiti, Jack/St. Malo, Caesar Tonga and Mad Dog fields in the Gulf of Mexico. Sonam field in Nigeria is scheduled for startup in 2017. Chevron’s Big Foot TLP is expected to be online in late 2018.

Eni currently produces 1.76 MMboed and has extensive offshore operations, with new projects in Angola, Egypt, Congo, Ghana and Norway slated for startup through 2017.

Since 2008, Eni has achieved an extraordinary exploration record, discovering 10 Bboe of resources. One notable success is the Zohr gas play offshore Egypt, which Eni discovered in 2015. The company’s FID calls for an investment of $13.3 billion to produce 2.7 Bcfgd from 20 wells. Production startup is planned for fourth-quarter 2017.

Winning so far. Despite drastic revenue declines, super-major results have been acceptable. Aside from BP and Chevron, all of them reported profits in the second quarter of 2016. So far, the super-majors have been winning the cost battle, but the service sector may be ready to fight back. Schlumberger CEO Paal Kibsgaard, during a conference call announcing a $2.16 billion quarterly loss, said that reduced supplier costs were not a “permanent improvement in the underlying industry performance.” 

About the Authors

Ron Bitto

Contributing Editor

Ron Bitto has more than 30 years of experience as a technology marketer and writer in the upstream oil and gas industry. RON.BITTO@GMAIL.COM