yet more evidence that the oil majors are looking at all the costs involved in deepwater exploration and production and not seeing longterm viability when compared to landbased operations and the new technologies available.
Houston-based ConocoPhillips has made the strategic decision to drop out of its deepwater exploration program by 2017, despite a significant program that the company is executing in 2016.
The move to stop exploration will help save the company money for its onshore program, and to cover shareholder payments.
Currently in its exit phase, ConocoPhillips said that deepwater operations might not cease entirely, and will consider continuing should the company see full value for those assets in development.
“Development of the discoveries that we have in deepwater is quite some way off and we may choose to stay with those developments, but we may choose to exit before development happens there,” Matt Fox, ConocoPhillips E&P EVP said in the company’s Q3 earnings call. “So really what we’re in just now is a ramping down of exploration commitments and continuing appraisal on the existing discoveries. We’re not at a development stage yet.”
However, should the company decide not to drill, its acreage positions will be put up for sale. For example, in the Gulf of Mexico, ConocoPhillips has approximately 2.2 million acres, and three existing discoveries.
“Our intention is to not be doing deepwater exploration by 2017. And those acreage positions that we hold that we don’t intend to drill we will be marketing those positions,” Fox said.
In Q3 2015, ConocoPhillips’ reported total revenue dropped almost 42% to US$7.5 million, from nearly $13 million year-over-year, and 13.3% from nearly $8.7 million last quarter.
As the company moves forward with its further reduction in its deepwater exploration spending, ConocoPhillips took a hit this quarter with a Gulf of Mexico deepwater drillship termination fee of $246 million.The Ensco DS-9 newbuild was destined for the Gulf of Mexico in late 2015 as part of a three-year contract.
“Despite our stated plans to reduce deepwater exploration spending over time we’re continuing to fund activity based on existing commitments while we also progress possible monetization options. This is important for protecting the value we’ve created from our existing program,” Fox said.
Fox said the company expects to invest $800 million in 2016 for its deepwater exploration and appraisal space.
“That’s the order of magnitude on the capital side that we wouldn’t be spending if we weren’t doing deepwater exploration and appraisal for one year. And then there’s G&G and G&A associated with that as well,” Fox said.
Current deepwater operations
Of its Gulf of Mexico acreage, ConocoPhillips recently had successful results at the Shenandoah appraisal well. Currently, the company is drilling the Vernaccia and Gibson exploration wells, with the expectation to spud the Melmar prospect this quarter.
Offshore Canada, the Cheshire exploration well was spudded off Nova Scotia this month, the first of two exploration well commitments.
For Europe, Q3 production averaged 192,000 boe/d, with several major turnarounds across the UK that were all completed successfully, the company said. Development drilling also continues at Ekofisk South and Eldfisk II offshore Norway.
For Asia Pacific and the Middle East, ConocoPhillips produced 332,000 boe/d in Q3, a 10% jump year-over-year, that company said was party due to Gumusut, offshore Malaysia. Gumusut underwent its first major turnaround, which was completed ahead of schedule.
not good news at all for the GoM in the next decade at least because if Conoco-Phillips is thinking this so are BP, Shell. Exxon-Mobil and all the big independents like BHP, Anadarko, et all.
[QUOTE=c.captain;172833]yet more evidence that the oil majors are looking at all the costs involved in deepwater exploration and production and not seeing longterm viability when compared to landbased operations and the new technologies available.
not good news at all for the GoM in the next decade at least because if Conoco-Phillips is thinking this so are BP, Shell. Exxon-Mobil and all the big independents like BHP, Anadarko, et all.[/QUOTE]
The truth is, the oil companies need all resources and diversified portfolios. Deepwater will not go away; pricing is adjusting to the current market although slowly. 5% of the world’s production has to be replaced on an annual basis due to natural decay rates.
Land based operations have it’s limits. 70% of the oil production comes from 30% of the wells with 20% annual decay rates. The technology has been there, and it’s not new. The price structure is whats been new, allowing the US to double production in 7 years time.
A good reference is to read up on the Barklay’s or other banker conferences with the Oil executives. It’s pretty interesting stuff.
Deepwater will not go away, and will expand in the future. Now, if technology increases “hit rates” in deepwater past the 75 percentile, you couldn’t keep the oil companies out.
[QUOTE=anchorman;172846]Deepwater will not go away, and will expand in the future. Now, if technology increases “hit rates” in deepwater past the 75 percentile, you couldn’t keep the oil companies out.[/QUOTE]
wishful thinking in my mind because no matter what you say, the costs of developing deepwater fields is in a couple of orders of magnitude greater that land based oil and if the majors can use new technologies to increase the yield of the landbased plays they’ll go there first. This is obviously what Conoco-Phillips is saying in their decision to suspend their deepwater program.
Conoco is not a “major.” They’ve always tried to employ a nimble and focused strategy. The advantage of tight oil plays is that you can quickly ramp production drilling up or down. Deepwater vertical wells of course require multi year commitments but have much slower depletion rates once production begins, and so are generally more profitable in the long term. The private oil industry will continue to invest in deepwater plays as well as tight oil plays.
[QUOTE=The Lash;172943]Conoco is not a “major.” They’ve always tried to employ a nimble and focused strategy. The advantage of tight oil plays is that you can quickly ramp production drilling up or down. Deepwater vertical wells of course require multi year commitments but have much slower depletion rates once production begins, and so are generally more profitable in the long term. The private oil industry will continue to invest in deepwater plays as well as tight oil plays.[/QUOTE]
Horizontal wells have been drilled offshore a long time before the so called “revolution” of drilling and fracking wells in shale.
In 1989 Norsk Hydro drilled horizontally in the Troll field to prove that it was possible to produce the thin oil layer that existed over a large area. The oil layer was only 5 m. thick, with water below and gas above. If the bore hole had gone above or below the well would have been ruined. The first Rig report pulled out at the Morning Meeting in town was always from the rig drilling that well (Polar Pioneer) They were NEVER out more than 50-90 cm, (2-3 ft.) from the intended track over a length of 1,800m. horizontal section.
In 1990 the possibility of piping multi-face well fluid over long distances (40 Km.) was proven by the same company in a project called TOGI (Troll/ Oseberg Gas Injection)
How do I know? I was Marine Consultant in Norsk Hydro at the time and part of the Morning meetings and planning of the TOGI project.
While the Troll Field had been considered as a Gas field only, this expensive experiment made it possible to develop Troll Oil, which is still producing today.
So horizontal drilling and fracking is nothing new, contrary to what is being claimed.
Correction: Deepsea Bergen drilled the initial well. Polar Pioneer was used on the TOGI project. (Senior moment)
ConocoPhillips’ declaration that it will be out of the deepwater oil and gas search by 2017 is perhaps indicative of things to come in the sector.
In the wake of ConocoPhillips’ impromptu declaration that its exiting deep-water exploration during an analyst call last week, the sector itself appears to be bleak territory.
Tudor Pickering Holt & Co. said in a Monday note to investors that the industry has been moving away from deepwater exploration.
“In a lower for longer environment, [COP’s departure] is likely the right move as a dearth of industry success combined with long lead investment cycles on development continue to put pressure on capital budgets in an uncertain world,” TPH said, adding that other exploration and production (E&P) companies heavy in deepwater may have to turn to mergers and acquisitions (M&A) to survive.
Since 2013, TPH estimated $90 billion has been spent on deepwater exploration. At today’s market prices, that could buy plenty of cash flow and known development opportunities.
At Evercore ISI, analysts noted that offshore day rates are hitting new lows. Newbuild floater numbers are down and those that are contracted are expected to be delayed.
“The industry continues to seek out the stability needed for a sustainable offshore recovery, and the offshore sector as a whole remains bleak in our view,” Evercore said.
Of course it’s all doom and gloom, you tell everyone it’s bleak, stock price tanks, you buy on the cheap. Two years from now the stock quadruples, sell high, pay no taxes, rinse, repeat.
Royal Dutch Shell plc said Tuesday it is planning for a prolonged downturn due to low oil prices as the firm announced a reorganization of its upstream operation would increase accountability for performance and align the company to deliver on its strategy.
In a statement to coincide with the firm’s ‘management day’, Shell said that both its net investment and dividend payments have been covered by operating cash flow in the year to the end of the third quarter of 2015 – a period during which oil prices averaged $60 per barrel.
Shell highlighted cost cutting that has seen a 10-percent reduction in operating costs and a 20-percent reduction in capital spending during 2015, together amounting to $11 billion. The firm’s drive to reduce costs and simplify its business has led to the announcement of jobs losses for some 7,500 staff and direct contractors so far in 2015.
Shell showed recently that it is prepared to be hard-nosed when it comes to certain upstream projects after it announced Oct 27 that it would shelf an oil sands project in Alberta into which it had already invested billions of dollars. The move to abandon the Carmon Creek heavy oil project followed its decision in late September to cease exploration activity offshore Alaska.
Shell said Tuesday that it is also being “highly selective” on new investment decisions.
The firm expects to complete its takeover of BG Group in early 2016 and it has identified a further $1 billion of pre-tax synergies to bring cost savings from combining the businesses to a total of $3.5 billion by 2018.
As part of its restructuring, Shell will make its Integrated Gas division a standalone entity in order to reflect its enlarged scale (it has grown from being a $2 billion cash flow business in 2009 to one that has generated $11 billion of cash during the last three years). This new business will be headed by Maarten Wetselaar.
Meanwhile, the new upstream organization will be led by Marvin Odum – who is Shell’s current Upstream Americas director.
Shell CEO Ben van Beurden commented in the firm’s management day statement:
"Low oil prices are driving significant changes in our industry. I am determined that Shell will be at the forefront of that, and emerge as a more focused and more competitive company as a result.
"BG rejuvenates Shell’s upstream by adding deep water and integrated gas positions that offer attractive returns and cash flow, with growth potential. These are industries where Shell has significant capabilities and technologies. With enhanced positions in both of these themes, Shell can focus on the best positions, and deliver a more structured and predictable investment program.
“We are re-shaping the company and this will accelerate once this transaction is complete. Upstream will be reorganized to increase accountability for performance, and to better align the organization with the company strategy. Asset sales and hard choices on capital spending, such as the recent announcements to cease exploration in Alaska and the development of Carmon Creek heavy oil in Canada, all underline the changes that are underway. Integration planning for Shell and BG is progressing according to plan and today we’re announcing a 40-percent increase in synergies expected from the recommended combination.
“Shell is becoming a company that is more focused on its core strengths, a company that is more resilient and competitive at all points in the oil price cycle and that has a more predictable project development pipeline. We’ll grow to simplify.”
Updated - - -
it’s cash flow, cash flow, cash flow my good squid
In light of the “lower for longer” oil price scenario going into 2017-2018, companies have reduced upstream CAPEX spend in 2015 and beyond.
With Chevron Corp. and Exxon Mobil Corp. rounding out third quarter 2015 earnings calls Oct. 30, some major themes have emerged for the integrated oil companies and large independents. In light of the sustained low oil price environment that has prevailed over the last 16 months, and expectations for a “lower for longer” scenario going into 2017-2018, companies have reduced upstream capital expenditures (CAPEX) in 2015 and indicated more dramatic cuts for the 2016-2018 period.
BP plc announced CAPEX plans of between $17 billion to $19 billion through 2017 in its Oct. 27 call, which represents a 30 percent cut from previous guidance. Similarly, Chevron plans to cuts its capital expenditures through 2018; and in 2016, the company anticipates capital outlays in the range of $25 billion to $28 billion (down 25 percent versus 2015), and expects somewhere between $20 billion and $24 billion for the 2017-2018 period.
For the companies that reported a profit during the quarter, e.g., Total S.A., Chevron and ExxonMobil, earnings were sharply down from previous periods, with the companies’ refining and chemicals operating segments compensating for drastically reduced profits (and, in some cases, losses) in the upstream part of the business. Although many companies increased crude output for the quarter, the higher volumes were not enough to offset lower realized prices. (The average Brent price in the third quarter 2015 hovered around $50/bbl).
During last weeks’ calls, some management teams from companies that posted losses for the quarter, which included Royal Dutch Shell plc, ConocoPhillips, Hess Corp., and Anadarko Petroleum Corp., took the opportunity to unveil major strategic shifts in asset portfolios. Most notably, was Shell’s announcement that it was exiting its 80,000 barrels per day (bpd) oil sands project in Alberta, Canada, and would take a $2 billion charge for the third quarter. Meanwhile, Total’s 69 percent decline in earnings versus the same time last year was largely attributable to a $650 million write-down related to its remaining 29 percent stake in the Fort Hills oils sands project in Alberta, Canada. ConocoPhillips made a surprise announcement that it was going to cut exposure to future deepwater exploration by 2017, and will implement a “phased exit” from the space, which would include the eventual sale of a major position in the Gulf of Mexico (2.2 million acres), with three existing discoveries.
Many companies revised down guidance for 2017 production targets, and signaled further deferments of major/long-cycle projects, which, in turn, was a reason to lower capital spending going forward. It is important to note, however, that management in many calls, emphasized that lower capital outlays over the next two to three year period indicated a structural shift in costs. Management from several companies stated that new, lower break-even Brent oil prices were now within reach: BP at $60/bbl; Shell at $55/bbl; Total at $60/bbl; and, Eni S.p.A at $63/bbl.
Some onshore operators cited cost savings exceeding 40 percent from service cost deflation and from drilling efficiencies. For offshore operators, there was mention of considerable service cost and equipment savings. The reductions were not to the same order of magnitude as for onshore operations, where batch drilling and other efficiencies have led to a significant contraction in the average drilling and completion time per well.
Although anticipated by the market, Occidental Petroleum Corp., confirmed in its earnings call, that it was exiting the comparatively high operating cost environment of the Bakken shale, with the sale of its properties in the area, for $600 million (to an undisclosed buyer). The company also intends to shed assets in the Middle East and to focus more on the lower-cost Permian Basin, where many companies are seeing the greatest benefit from operational efficiency gains and cost deflation. ExxonMobil, in its call, confirmed that it had added 48,000 acres to its 135,000 operated net acre portfolio in the Midland Basin of the Permian. The Energy Information Agency (EIA) issued a report Oct. 30 on U.S. oil production for August 2015, where it showed that in the majority of tight oil plays across the country, production was falling off. Only in the Permian was production ramping up – with the EIA estimating that it increased by 64,000 bpd from April to September.
we are seeing the mid 1980’s all over again with this downturn so expect the bankruptcies to begin in earnest in 2016
[QUOTE=ombugge;172992]Horizontal wells have been drilled offshore a long time before the so called “revolution” of drilling and fracking wells in shale.
In 1989 Norsk Hydro drilled horizontally in the Troll field to prove that it was possible to produce the thin oil layer that existed over a large area. The oil layer was only 5 m. thick, with water below and gas above. If the bore hole had gone above or below the well would have been ruined. The first Rig report pulled out at the Morning Meeting in town was always from the rig drilling that well (Polar Pioneer) They were NEVER out more than 50-90 cm, (2-3 ft.) from the intended track over a length of 1,800m. horizontal section.
In 1990 the possibility of piping multi-face well fluid over long distances (40 Km.) was proven by the same company in a project called TOGI (Troll/ Oseberg Gas Injection)
How do I know? I was Marine Consultant in Norsk Hydro at the time and part of the Morning meetings and planning of the TOGI project.
While the Troll Field had been considered as a Gas field only, this expensive experiment made it possible to develop Troll Oil, which is still producing today.
So horizontal drilling and fracking is nothing new, contrary to what is being claimed.
Correction: Deepsea Bergen drilled the initial well. Polar Pioneer was used on the TOGI project. (Senior moment)[/QUOTE]
I’m no driller, although my father was, but I am aware of offshore horizontal drilling through narrow pay zones. This is distinct however from tight oil fracking which requires frequent workovers and refracking due to the high depletion rate. Even horizontal wells offshore do not deplete at nearly the rate as tight oil wells. They cost more to put in but they last longer with less maintenance drilling so you may very well end up with less lifetime cost per barrel, depending on the well. I have heard for instance that Exxon’s break even point offshore is at $18 a barrel for certain projects. Deepwater has a lot of existing infrastructure that lowers the cost of new drilling and it isn’t going away anytime soon. Yes there will even be new structures put into place no matter how hard c.captain tries to wish then away.
[QUOTE=The Lash;173036]I’m no driller, although my father was, but I am aware of offshore horizontal drilling through narrow pay zones. This is distinct however from tight oil fracking which requires frequent workovers and refracking due to the high depletion rate. Even horizontal wells offshore do not deplete at nearly the rate as tight oil wells. They cost more to put in but they last longer with less maintenance drilling so you may very well end up with less lifetime cost per barrel, depending on the well. I have heard for instance that Exxon’s break even point offshore is at $18 a barrel for certain projects. Deepwater has a lot of existing infrastructure that lowers the cost of new drilling and it isn’t going away anytime soon. Yes there will even be new structures put into place no matter how hard c.captain tries to wish then away.[/QUOTE]
Yes there are differences in how the wells are brought on line and maintained, which brings the cost of producing a barrel of shale oil up.
My point was about the technique to drill long horizontal sections with such precision that it is possible to produce even very thin oil layer, whether in shale or otherwise.
[QUOTE=The Lash;173036]Yes there will even be new structures put into place no matter how hard c.captain tries to wish then away.[/QUOTE]
I am not wishing anything away but just pointing out a very clear trend by the big players to seriously cut their offshore E&P spending. No way around the reality that the costs to play in the deepwater are far greater than on land so unless massive finds are coming in regularly, nobody is going to be taking the risks to spend more than a $100M per well when they can just sit and wait for the recovery. There is plenty of in situ production available to fill world demand now and likely for the next decade so no reason why that money needs to be spent at this time when the cash flow is half what is was a year ago. When that available oil starts to decline enough to get the price back up to over $90/bbl then everybody will be back wading in the offshore just like before except many of the old players might be bankrupt and gone or merged with someone else. Who is going to be the first to fall is my biggest question? Which drillers and which service vessel owners?
if this is true then the bloodletting for the offshore is only just begun…much more needs to be bled from the body before it can ever heal. The trouble is that it will be very pale and weak when the recovery starts.
Written by Elaine Maslin Wednesday, 04 November 2015 11:17
Some 40-50% of savings or efficiency gains need to be made if the industry is going to survive the low oil price regime we are in, an industry event was told in Aberdeen today.
“For us to survive this long-term, to get by on the oil price as it is, and right now two years is a life time, we need to take 40-50% cost out or efficiency up, and no industry has done that without transformation. It is not just cutting costs,” said John Pearson, Group President Northern Europe and CIS, Amec Foster Wheeler.
“All are saying we have a problem,” he told the one-day Oil & Gas UK-run Share Fair event in Aberdeen. “We [in the North Sea] are spending more than we earn and we haven’t seen that since the early days of the basin.” But, he added: "I think it is an opportunity, if we grasp it. You can either surrender or get on with it and I don’t fancy surrendering.”
The industry’s problems were highlighted by a staggering admission by a senior BP boss that on-hire equipment was left offshore for, “in some cases months and in some cases years,” still on hire, costing the operator how much it would have to pay for the equipment outright three times over.
A presenter from Shell said better planning and communication was a priority after admitting to incidents such as a contract engineer being kept on standby for 21 days, again at the cost of the operator.
As another example of inefficiency in the industry, the event heard some 22 MMboe is lost per year due to unplanned compressor shutdowns - an issue which is now being addressed.
Wood Mackenzie estimates US$1.5 trillion of investment does not break even at $50/bbl and says while exploration companies have been pushing supply the chain to reduce costs, additional measures will be needed to reset the cost base.
Opening the event, aimed at connecting the supply chain with operators, Oil & Gas UK CEO Dierdre Michie said the industry is going through a tough time, with high cost inflation and low efficiency compounded by low oil prices.
“Last year the basin spent more than it earned,” she said. “To turn things around we need to remind ourselves of Einstein’s oft quoted wisdom - ‘to keep doing things the same way and expect a different outcome is,’ to paraphrase, hardly a good way of doing business.”
While the presentations given during the event gave plenty of examples of where industry was finding ways to cut costs and improve efficiencies, from making better use of helicopters, to sharing platform supply vessels and spare parts inventories, more would need to be done, she said.
“Given the position the industry finds itself in, we all need to do more,” Michie said. “We have a limited window of opportunity to drive a different way or working. It’s quiet simple, it’s about better communication, about increasing transparency about issues and performance, and it’s about bringing the supply chain in early in project planning.”
Oil & Gas UK is leading an initiative to help the industry make efficiencies. Pearson, who is leading the Efficiency Task Force, outlined some of the goals within the initiative, which covers three areas; business process, standardization and subsea.
In business process area, the group is looking at RB211 issues – i.e. the compressor shut downs losing 22 MMboe a year. Six operators are working together on this issue, says Pearson.
Under standardization, well plugging and abandonment, which is 40% of decommissioning costs on the UK Continental Shelf, are also being looked at, as well as valves.
“Valve repair is about half cost of replacement, yet only 25% are repaired,” says Pearson. “For one type of valve we found 250 specifications on the spindle size column. Could the industry have one size type of valve? Probably not. But if we narrowed that down a bit it would make an impact.”
Under cultures and behaviors - a behavioral charter for the industry is being drawn up. “It’s about learning to trust each other,” says Pearson. “There’s been a fall in trust in each other. It’s opening our ears and listening and up-taking [ideas]. The flip is if promise something you can’t deliver will set each other back.”
In addition, Andy Leadbetter, PSCM Regional Director – North Sea Region, BP, outlined the newly set up Rapid Efficiency Exchange, a portal for the supply chain to submit ideas which can be accessed by companies looking for solutions.
I wonder where the industry stands now regarding cost cutting to date? I’d say around 25 to 30% from a year ago so only half way there…
having a chat to an oil exec the other day, he says yes we would like to be drilling BUT several years of huge expenses but now no payback due to low price so not its all about preserving cash ( as mentioned above)