Thursday, January 30, 2014 by Reuters – John Kemp
LONDON, Jan 30 (Reuters) – Cutting the cost of everything from salaries and steel pipes to seismic surveys and drilling equipment is the central challenge for the oil and gas industry over the next five years.
The tremendous increase in exploration and production activity around the world over the last ten years has strained the global supply chain and been accompanied by a predictable increase in operating and capital costs.
When oil and gas prices were rising strongly, petroleum producers and their contractors could afford to absorb cost increases.
But as oil and gas production have moved back into line with demand, and prices have stabilized, the focus is switching once again to cost control.
“Operational excellence,” a euphemism for doing more with less, is back in fashion and set to dominate industry thinking for the rest of the decade.
Paal Kibsgaard, chief executive of Schlumberger, one of the largest service companies, has been emphasising “smart fracking” and other ways to raise output and cut costs for two years.
Speaking as long ago as March 2012, Kibsgaard warned: “In the past ten years, exploration and production spend has grown fourfold in nominal terms, while oil production is up only 11 percent.”
“In this environment, we believe our customers will favour working with companies that can help them increase production and recovery, reduce costs, and manage risks,” he added.
Schlumberger’s website and those of its main competitors Halliburton and Baker Hughes all prominently feature technologies and processes intended to cut costs, such as dual-fuel diesel-natural gas drilling and pumping engines.
It is just a small example of profound industry shift from an emphasis on increasing production to controlling spending.
Issuing a shocking profit warning on January 17, Royal Dutch Shell ‘s new chief executive pledged to focus on “achieving better capital efficiency and on continuing to strengthen our operational performance and project delivery.”
On Thursday, the company cut its capital budget for 2014, and announced it was suspending its controversial and expensive Arctic drilling programme.
Shell is catching up with peers like BP and Chevron , as well as perennially tight-fisted Exxon, in promising to stick to a tighter spending regime and return more value to shareholders .
The problem is not unique to oil and gas producers. Miners like BHP Billiton, Rio Tinto and Anglo American have all axed projects and pledged to tighten capital discipline after costs spiralled out of control.
The worst over-runs have been on so-called megaprojects – investments costing over $1 billion, sometimes much more. In fact, the bigger project, the worse the cost overruns and delays have tended to be.
Pearl, Shell’s enormous gas to liquids project in Qatar, is now regarded as a success, but was seriously delayed and went wildly over-budget.
Other megaprojects like Chevron’s Gorgon LNG in Australia and the Caspian oil field Kashagan – which is being developed by an industry consortium including ENI, Shell, Total, Exxon and Conoco – have been similarly late and bust their original cost estimates.
It is convenient, but wrong, to blame poor project management for all the days and cost overruns. Some decisions have been flawed, but on projects of this size and complexity, at least some errors are to be expected.
Megaproject managers in 2013 were not, on the whole, worse than in 2003. Unfortunately, the economic and financial environment has become much less forgiving. When projects start to go wrong it has proved much harder to limit the delays and damage to the budget.
By their nature, megaprojects are so big they strain the global construction and engineering supply chain and pool of skilled labour. Megaprojects create their own adverse “weather,” pushing up the cost of specialist labour and materials worldwide.
Attempting to complete even one or two megaprojects with similar characteristics at the same time can strain the global supply chain to the limit. Attempting to complete several simultaneously is a recipe for severe cost escalation and delays. The multi-commodity boom over the last decade created a “perfect storm” for the megaproject industry.
While there is not an exact overlap, massive offshore oil fields like Kashagan, LNG facilities like Gorgon, floating LNG platforms like Prelude (destined for Australia), gas to liquids plants and even simple onshore shale plays like North Dakota’s Bakken, are all competing for the same limited pool of skilled engineers, construction workers and speciality steels.
The result has been a staggering increase in costs and wages. And once a project falls behind, there is no slack in the system to hire extra workers or procure additional or replacement components to get it back on track.
Supply Chain Responds
Rampant inflation and delays have been worst on megaprojects because they require a much higher proportion of very specialist components and the supply chain is least-elastic.
But even simpler projects like shale oil and gas have been plagued by a rapid rise in costs as they stretch the availability of drillers, rigs and pressure pumping equipment, as well as fracking sand, fresh water and guar gum.
Between the end of 2003 and the end of 2013, the number of employees engaged in oil and gas extraction in the United States increased by 70 percent, from 117,000 to 201,000, according to the U.S. Bureau of Labor Statistics.
Soaring demand for specialised workers has produced an entirely predictable surge in wages.
Employees in North Dakota’s oil, gas and pipeline sectors were taking home an average monthly salary of $9,000 in the fourth quarter of 2012, and staff at support firms were making an average of more than $8,000, according to the latest data from the U.S. Census Bureau.
Their colleagues in Texas were doing even better: average salaries in the oil and gas extraction industry were over $15,000 per month, and $11,000 in pipeline transportation.
That made them some of the best-paid employees in the United States. Only financial services employees in New York ($28,000), Connecticut ($25,000), California ($17,000) and a few other states were routinely making more.
Rising wages and other prices were the only means to ration scarce workers and raw materials. But they were also the only way to attract more workers and supplies into the industry.
It takes a long time to train new drillers, petroleum engineers and construction specialists, and give them the experience needed before they can assume positions as experts and team leaders.
Similarly, the expansion of specialist construction facilities and manufacturing firms for items like oil country tubular goods takes years; and companies will only expand or enter the industry if they are convinced the upturn in demand will be durable rather than fleeting.
While the boom in oil and gas prices dates from around 2003 or 2004, the big expansion of exploration and production spending started much later, around 2006 or even 2007, and it has only filtered down to the labour pool and the rest of the supply chain much more slowly.
It is the long delay between an increase in demand for oil and gas, an increase in production and exploration activity, and an expansion of the whole supply chain, which explain the deep cyclicality of the petroleum industry and mining.
Extreme cyclicality is hard-wired into oil, gas and mining markets. Companies like Shell which have tried to ride through the cycle by ignoring short-term price and cost changes to focus on the long term have eventually been compelled by their investors to fall into line.
In the next stage of the cycle, oil and gas prices are set to remain relatively high but are unlikely to rise much further. For exploration and production companies, increasing shareholder value therefore means increasing efficiency and bearing down on costs, including compensation and payments to suppliers and contractors.
For the supply chain and oil-industry workers, capacity and the availability of skilled labour will continue to expand, while demand is set to stabilise or taper off. Major oil companies and miners have already cancelled some projects. Costs, wages and employment will fall, or at least start rising much more slowly.
Barclays James West and Zachary Sadow explain:
Our Base case assumes dayrates continue to slide with UDW dayrates dropping to $475k and total average rates dropping 16% from our bull case. We think this is the most likely outcome as we continue to believe the market still needs to work through excess capacity and that conditions will get worse before they get better. In this environment, we anticipate utilization would drop modestly as well. Overall, we expect EPS to be below our 2015 EPS estimates by 38% (ex-HERO) and EBITDA to be 26% below our 2015 EBITDA estimates. Companies with larger portions of fleets derived from older assets would be the most impacted. Under this scenario, all companies in our coverage universe (except Rowan (RDC)) are subject to share price depreciation with an average pullback of 35% (-28% ex-[Vantage Drilling Company (VTG)]). At these levels, we would expect companies with higher leverage levels to be more impacted and see potential for financing events as equity values contract.
Under this scenario, Rowan could gain 2% while Seadrill could plummet 52%, Diamond Offshore could plunge 45%, Transocean could fall 24% and Atwood Oceanics (ATW) could drop 15%.
Read more: Here
Offshore technology provider AGR Enhanced Drilling, via its subsidiary Ocean Riser Systems, has entered into a NOK120m (USD20m) Letter of Intent (LOI) together with Statoil to deliver the next-generation EC-Drill® Managed Pressure Drilling system.
This latest contract will replace a purchase order made last year, when Statoil joined with Norway-based Enhanced Drilling to further develop its EC-Drill® Managed Pressure Drilling (MPD) solution for floating rigs. The initial phase of the project was worth US$5.1m.
The next-generation EC-Drill® system incorporates state-of-the-art control system capability, enhanced riser integration and multiple other features. Testing of the system is due to commence in the autumn and it will eventually be used on the Norwegian Continental Shelf.
EC-Drill® is a step-change MPD solution, solving a challenge commonly encountered in deep-water wells: drilling within a Narrow Pressure Window. EC-Drill® manipulates bottom-hole pressure by changing the level of drilling mud in the riser, enabling the operator to ‘walk the line’ between pore and fracture pressures. It provides a far greater degree of control than conventional drilling while enhancing safety, plus it is possible to cost-effectively hit deep targets that are simply impractical to reach with more traditional drilling techniques.
David Hine, Executive Vice President at Enhanced Drilling, said from the company’s head office in Straume: “This further commitment by Statoil is another significant endorsement of EC-Drill® as a game-changing technology and the benefits that it brings. This next-generation system is a further step in taking Enhanced Drilling towards the forefront of the MPD market.”
Northern Petroleum Plc announces the joint venture decision to extend current drilling operations on the Guyane Maritime permit in French Guiana.
The GM-ES-3 exploration well is the second well of a four well exploration drilling campaign that commenced in 2012 to follow up the oil discovery at GM-ES-1 in 2011.
The GM-ES-2 well had exploration objectives in the major Cingulata fan system within which the original oil discovery was made in two ages of formation. GM-ES-3 has been planned to deliver exploration information in the subsidiary Priodontes fan system to the north west of the Zaedyus oil discovery.
The GM-ES-3 well intersected a 50 metres gross section of oil stained sands in the lower part of the Bradypus fan which was not a target formation at this location although it is also within the main Cingulata fan system. A 325 metres gross interval of sandstones was encountered in the targeted Priodontes fan, but these were logged with no significant hydrocarbon shows.
It has been decided by the Shell, Total, Tullow Oil and Northpet Investments Limited joint venture that this well provides a suitable location to drill deeper in a plan to penetrate the full post Atlantic rift sequence. The duration of this additional drilling will depend upon results from the formations encountered.
“This information may prove crucial to a fuller understanding of the exploration potential of this very large licensed area. Although this extension may cause a small delay to the further wells in this exploration programme, the earlier the deeper formations are examined, the better the advantages to be gained from its use in the second part of the drilling programme and aid efforts towards discovering more oil,” said NorthernPetroleum in a press release.
The well is now targeted to reach a final depth of 6438 meters subject to operational factors.
Derek Musgrove, Managing Director of Northern stated: “Following the oil discoveries of GM-ES-1 in 2011, the task before us was to explore the licence to ascertain its wider potential. Whilst the sand package in the primary target proved not to have significant hydrocarbons at this location, the oil staining encountered in the Bradypus fan is encouraging of the broader active hydrocarbon systems and potential.
“Northern supports this fuller exploration approach to this well. It is likely to provide Partners with further geological data imperative to gaining further understanding of the complex geology in this area”
To read more on the Joint Venture’s operations in French Guiana click here.
Drilling contractor Pacific Drilling S.A. has announced that Total S.A. has elected to exercise a one-year option to extend the firm contract term for the Pacific Scirocco to January 2015.
The contract provides for a further option, to be exercised at the client’s discretion by April 7, 2014, which could result in two additional years of contract term at a higher dayrate.
The additional one year term increases the drillship’s backlog by approximately $180 million, bringing the company’s total contract backlog as of April 9, 2013, to approximately $3.4 billion. The additional extension for two years would add a further $364 million backlog if exercised.
The Pacific Scirocco is capable of operating in water depths of up to 12,000 feet and drilling wells 40,000 feet deep.
Originally posted on Applied Agrotech, LLC:
- Molly Ryan
- Reporter- Houston Business Journal
The University of Houston has plans to offer the fist subsea engineering graduate program in the U.S.
The local university recently said the Texas Higher Education Coordinating Board approved the school’s proposal to offer a graduate subsea engineering program. The program, which is expected to begin in the fall of 2013, will complement the school’s existing subsea engineering certification program.
UH said it partnered with leading energy engineering companies to create a master’s subsea engineering program with lectures and hands-on software education for subsea systems design.
“UH received tremendous input for both of the subsea programs from industry experts, including Cameron, FMC Technologies and GE Oil & Gas,” Matthew Franchek, founding director of UH’s subsea program and a mechanical engineering professor, said in a statement.
Subsea engineers are expected to design, install and maintain oil and gas drilling and production equipment tools and…
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