Energy: More buck, less bang; As oil companies venture further into remote areas in search of the world’s remaining reserves, their costs have soared

April 11, 2013 7:06 pm

Energy: More buck, less bang

As oil companies venture further into remote areas in search of the world’s remaining reserves, their costs have soared

By Sylvia Pfeifer and Guy Chazan

The Bob Douglas will be a giant, a drillship big enough to carry two helicopters, cope with 10,000 feet of water and still manage to pierce the earth’s crust another 30,000 feet.

It is under construction at Ulsan, Hyundai Heavy Industries’ shipyard on the southeastern tip of the Korean peninsula. When it goes to work later this year, its owner, Noble Corporation, will charge $618,000 a day for its use – more than twice what it costs to hire an Airbus A320 for a month.

The new vessel is far more advanced and better-equipped than its predecessors, the result of heavy investment – it can cost upwards of $600m to bring a state-of-the-art drillship to market. But just 10 years ago the best-equipped offshore rigs would have cost one-third what Noble is charging.

Oil exploration has always been an expensive business. Yet even for an industry used to multibillion dollar capital budgets, costs have been rising at a troubling pace, as the Bob Douglas illustrates. Analysis by Bernstein of Europe’s integrated oil companies found their costs soared by 10 per cent last year.The inflation stems from the rising complexity of the energy sector. Oil extraction used to be as easy as sticking a straw into the sand: in countries such as Saudi Arabia and Iraq, it has largely stayed that way.

But resource nationalism means the Middle East is now largely off-limits to western groups. Shut out of the “easy oil”, they have gone to the ends of the earth in search of the world’s remaining reserves. Companies such as BP, Royal Dutch Shell and ExxonMobil have invested billions to turn Canada’s bitumen into synthetic oil, and freeze natural gas into an exportable liquid. They have ventured out into the remote,iceberg-strewn waters of the Arctic, discovered huge new oil reserves under a 2km-thick layer of salt off the coast of Brazil and “fracked” their way through vast shale and “tight” oil formations from Texas to North Dakota.

“Projects are getting bigger in scale and more remote. The oil is harder to find and more expensive to get out,” says Christian Brown, chief executive of Kentz, the engineering and services group.

The increasing sophistication of Big Oil has made crude more costly. That, combined with rising oil demand from the emerging economies of Asia, is partly why the price of oil has more than quadrupled over the past 10 years, from about $25 a barrel in 2002 to $110 last year. That in turn has meant soaring petrol prices that have only exacerbated the economic problems of the past four years.

Yet one of the most alarming elements of the increase in cost and complexity is that the majors have been getting much less of a bang for their buck. According to Schlumberger, the oil services group, annual capital spending for the industry has more than tripled in the past 10 years, reaching $550bn in 2011. But all this expenditure is not delivering. Last year, Bernstein says, the European majors failed to find enough new oil and gas to replace what they had produced, chalking up a reserve replacement ratio of only 92 per cent.

More alarming still is the oil majors’ seeming inability to deliver the new generation of multibillion-dollar “megaprojects” on time and on budget. A recent study by Independent Project Analysis shows the average big exploration and production project is 22 per cent late and 25 per cent over budget.

A standout example is Kashagan, a vast oilfield in the Kazakh sector of the Caspian Sea that has turned into the world’s most expensive oil development project. Italy’sEni and its partners had to house the drilling rig on a specially constructed artificial island to guard it against the Caspian’s mounds of powerful pack ice. They also had to install cutting-edge equipment to battle the deadly hydrogen sulphide gas that Kashagan’s oil contains. The cost of the first phase has ballooned to $46bn, at least three times more than initially planned.

And despite the eye-popping sums being invested, they are not matched by new oil industry production.

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Over the past 10 years the world’s top seven international oil and gas companies have increased their development capital expenditure by 255 per cent. Yet in terms of production, the companies have struggled, says Claudio Descalzi, chief operating officer at Eni, one of the majors. In the past decade, the compound average growth rate has been “practically zero”, as much of the new production has been used to make up for the natural depletion of mature oilfields.

Returns on capital employed are another worry. Analysis by PFC Energy shows that despite oil prices rising over the past three years, ROCE in exploration and production has fallen.

“The industry is locked into a more expensive cost structure,” says Jerry Kepes, head of PFC Energy’s upstream practice. “Companies are also having to explore more difficult areas, such as the pre-salt play in Brazil. The nature of the new source portfolios for companies has changed dramatically between 2005 and 2015.”

A number of the companies analysed have also suffered lower returns after making large investments in North America’s shale gas reserves. The discoveries have led to a glut, with the price of gas in the US dropping to 10-year lows.

Even when they spend billions on accessing new frontiers, there is no guarantee they will produce. Despite investing nearly $5bn on its oil exploration campaign off thenorthern coast of Alaska, Shell has yet to complete a single well. Dogged by regulatory problems, legal challenges and equipment breakdowns, the company is shelving plans to drill this year.

Some oil industry executives believe a key reason for the sector’s loss of control over costs stems from its tendency to outsource important parts of the development phase of projects.

That trend has its roots in the changes that have rippled through the sector over the past 30 years. In the early days, companies were content to sit on vast oilfields in areas such as the North Sea that required little attention. But as the big fields began to decline in the 1990s, they were forced to start exploring again and building out the fields they discovered into big new development projects that required engineering manpower on a huge scale. Yet they no longer had the necessary skills.

“All you have been doing is cost-cutting and improving production efficiency and suddenly you have to be a project manager, which has a lot to do with construction and nothing to do with hydrocarbons,” says a senior executive at a supermajor.

Recognising this, many companies turned to outside contractors for parts of their engineering, procurement and construction. As time has gone on, they have outsourced more, often running down their in-house teams.

“You’ve got a small group managing a big contractor and you just want to get the job done, off the schedule, get the hydrocarbons in place … You get cost overruns because you haven’t been able to manage the contractor effectively,” says the senior executive.

Shell was one of the companies that suffered this way, experiencing big budget blowouts on projects such as its huge Sakhalin liquefied natural gas venture in Russia’s far east and its Pearl gas-to-liquids plant in Qatar.

Unrealistic expectations and bad planning are also hampering the sector. According to Independent Project Analysis, “the drive for unobtainable speed to first oil is crippling the industry”.

“It is driving up cost by many tens of billions of dollars in [capital expenditure] each year, and it is driving down production attainment after first oil is achieved.”

Matthias Bichsel, head of Shell’s projects and technology division, believes there is “no common numerator” for cost overruns, adding that a large international oil company will commonly be working on 1,000 capital projects in any given year so those with problems need to be put into context. The problem is not outsourcing per se, he says, but a case of “managing the supply chain more tightly”.

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The going may be tough but executives insist costs are not out of control and that the industry is much more efficient than it was just a few years ago. There may be some cost “hotspots” such as Australia but companies are becoming more careful about where they invest.

Mr Bichsel believes the situation today is not comparable to the years from 2005 to 2008 when there was “galloping” cost inflation and it was difficult to predict future levels. Costs came down with the recession but are now back up to where they were pre-2008 as demand for energy has risen.

Keeping a tight grip on costs in the supply chain is vital. Shell has built up a list of nearly 200 qualified vendors and suppliers in low-cost countries including China, India, Russia and Mexico. The move has paid off: the company has on average realised savings of 20-25 per cent in these countries.

The group has also agreed long-term contracts with rig contractors, typically for up to 10 years, for ultra-deepwater drillships in exchange for daily lease rates that are 10 per cent lower than the industry average. It is a true partnership, and the companies even exchange staff, but “it does not take away the individual accountability,” says Mr Bichsel.

Paul Siegele, president of Chevron’s Energy Technology Company, says the company has a structured procurement process, exercising its “tremendous buying power” to help secure master service agreements that generate big cost savings while providing a secure revenue stream.

In Australia, home to some of the biggest recent cost overruns, the industry is making a concerted effort to rein in costs. Here, rising labour costs, brought on by the shortage of skilled workers, and the high Australian dollar have been among the main reasons for cost blowouts at several projects.

Both Shell and ExxonMobil are moving ahead with plans to produce LNG at sea using floating facilities – a plan that could shave billions of dollars off an LNG project. Such schemes allow the operators to produce significant parts somewhere else. While the companies will still invest onshore and in the local supply chain through the 25-year production life of the project, they have the option of having the hull of the platform built somewhere cheaper.

Mr Siegele points to the use of technology both to reduce costs and to help get “more barrels out”. In the deep water of the Gulf of Mexico, Chevron has used new technology that has allowed it to save 50 days of rig time on one well. It has also been able to reduce the decline curve on fields from a historic annual rate of 5-6 per cent to one of 4 per cent.

All of these approaches can and do make a big difference. However, says Mr Bichsel: “We have to realise as an industry that the easy oil and easy gas is over. We are moving into areas that are more challenging and that tends to mean the costs per barrel are higher than 10 years ago.”

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Australia: The gas (and budget) boom

Australia is attempting to do something unprecedented in the gas industry: develop seven LNG projects concurrently, writes Neil Hume in Sydney. And the strains from the ventures, worth almost A$200bn (US$210bn), are showing.

Cost blowouts and delays have become common, and there are doubts that a second wave of developments, worth a further A$100bn, will go ahead.

US group Chevron highlighted the severity of the problem in December when it said the budget for its Gorgon project had ballooned by 41 per cent to US$52bn. BG Group and Santos have also experienced cost blowouts at their coal seam gas-to-LNG ventures in Queensland.

Recent studies have shown Australia is the most expensive offshore exploration and production location in the world – three times as expensive as the US Gulf Coast, and slightly more than Norway. Construction wages in remote parts of the country, are about US$120 an hour (and more than US$200 if transport and housing are included), says a study for the Business Council of Australia. This compares with US$68 an hour on the US Gulf Coast.

The Bureau of Resource and Energy Economics estimates Chevron’s Wheatstone project has a capital cost of A$3bn per million tonnes of annual capacity and Inpex’s Ichthys venture A$4bn per million tonnes. The Angola LNG project in southern Africa costs less than US$1.7bn.

The BREE says these are the highest figures in the world. Besides labour costs, the strong Australian dollar, now at a 28-year high, is also to blame. If Australia does not tackle these problems, investment could dry up. Indeed, Woodside Petroleum is reportedly considering shelving its A$40bn Browse project. And Royal Dutch Shell, one of the biggest foreign investors in Australia, says it will slow the pace of final investment decisions.