[ROCKMAN]

Deep Water GOM still looking good. But just like every oil/NG play ever developed it will eventually fall away:

Deepwater Gulf of Mexico production is expected to reach a new peak of 1.9 million barrels of oil equivalent per day in 2016. New developments and the expansion of older oil fields are expected to lift deepwater Gulf of Mexico production of 1.9 million boepd in 2016, the first new production peak seen since 2009. However, production is expected to plateau for the remainder of the decade following the 2016 peak due to the depletion of legacy fields and a limited number of new projects coming onstream.

Next year production is expected to rise 21 percent from 2014’s production level. Deepwater Gulf production growth also will be augmented by the redevelopment and extension of older fields. Fifteen field development projects are expected to come online between 2014 and 2016, while only eight developments will come online from 2017 to 2020.

{I suppose some credit should be given to the POTUS (the "greenest national leader in US history) for the improvement since most has happened on his watch. Fortunately the worst environmental disaster in US history did not inhibit his support for the development of oil/NG on the govt's offshore leaseholds}

Discoveries are being made in increasingly deeper waters and emerging plays that require complex drilling and more advanced, capital-intensive technologies. To meet Wood Mackenzie’s production outlook, $17 billion in capital expenditures will be required, 30 percent higher than 2013. The region will face difficulty in growing over the next decade unless the oil and gas industry can overcome challenging economics due to high costs, technological limitations and low recovery rates. "We forecast that production will start to decline after plateauing out at 1.9 million barrels of oil equivalent per day in 2021,” said Imran Khan, GOM analyst at Wood Mackenzie. “The current slide in oil prices does not help the long-term outlook either, especially if the downward trend continues for a prolonged period,” Khan noted.

[ROCKMAN]

And one of the negatives about Deep Water field development (long lag times from discovery to production) is actually a benefit during times of sliding oil prices as we've just seen. Companies that invested $billions years ago are now taking a bit of a hit but it doesn't matter with respect to production rates: they have to keep producing. But projects just starting:

Reuters - Hess Corp. said on Tuesday it would proceed with the development of the $6 billion Stampede project in the U.S. Gulf of Mexico, one of the biggest energy investments announced during the current oil price slump. Hess, the operator of the deepwater project, has a 25 percent stake in Stampede. A unit of Chevron Corp, Norway's Statoil and Nexen Petroleum Offshore will also each hold a 25 percent stake. Hess said first production from the project is expected in 2018. By then, the market may well have recovered from a dip that has cut the price of barrels by more than 20 percent since June to around $80 each.

[Subjectivist]

What are the odds anyone will bid on these leases?

$this->bbcode_second_pass_quote('', 'T')he U.S. government will open nearly 45 million acres in the Gulf of Mexico to oil and natural gas development later this month, at a time when low prices are forcing producers to cut back sharply on their exploration budgets.

But the industry’s troubles have had little impact so far on oil output in the region. In fact, unlike onshore production, which has been tapering off as oil prices decline, Gulf of Mexico production is on its way to setting a record in 2017.

“Production in the (Gulf of Mexico) is less sensitive than onshore production in the Lower 48 states to short-term price movements,” the U.S. Energy Information Administration wrote in a recent

[ROCKMAN]

sub - Not predicting it but the Rockman wouldn't be shocked if a lot of tracts are leased...especially Deep Water. Remember it can be the better part of 10 years between winning a lease and first production. So what oil/NG prices would you use for your new offshore field's first production in 2026?

[AdamB]

$this->bbcode_second_pass_quote('ROCKMAN', 's')ub - Not predicting it but the Rockman wouldn't be shocked if a lot of tracts are leased...especially Deep Water. Remember it can be the better part of 10 years between winning a lease and first production. So what oil/NG prices would you use for your new offshore field's first production in 2026?

[Subjectivist]

$this->bbcode_second_pass_quote('ROCKMAN', 's')ub - Not predicting it but the Rockman wouldn't be shocked if a lot of tracts are leased...especially Deep Water. Remember it can be the better part of 10 years between winning a lease and first production. So what oil/NG prices would you use for your new offshore field's first production in 2026?

[ROCKMAN]

Adam - I've never worked close with a team that had to make such an economic model for such huge and far out project. But I can tell you the economics we just ran today on a small onshore acquisition. We ran multiple NPV runs at different FLAT prices: $24/bbl to $34/bbl. The NPV was negative at all prices under $30/bbl. And at $34/bbl it still didn't warrent a very big purchase price...a good bit less then the sellers expectation.

But guess what price platform they used: initially $30/bbl and then increasing $5/bbl EVERY 6 MONTHS until it topped out at $80/bbl. It took every bit of professionalism to just politely decline to make an offer instead of simply telling them to go f*ck themselves. LOL. Seriously.

[tita]

Tell me if I'm wrong, but regardless of the price producers may expect 10 years from now, they also have to replace their depleting production. And it's not like there is a lot of opportunities around to do this. They are not sitting on a continuous output, and this is their main revenue stream.

[Tanada]

$this->bbcode_second_pass_quote('tita', 'T')ell me if I'm wrong, but regardless of the price producers may expect 10 years from now, they also have to replace their depleting production. And it's not like there is a lot of opportunities around to do this. They are not sitting on a continuous output, and this is their main revenue stream.

[ROCKMAN]

tita - As T points out there are two primary ways to grow reserves: with the drill bit and thru acquisitions. But there’s also risk there just like with drilling. Consider the XTO acquisition by ExxonMobil back in 2010. They gave XTO shareholders $41 BILLION in XOM stock based upon the assumption that the NG prices would soon be increasing. They were wrong…very wrong: “Tillerson added that ExxonMobil underestimated the US natural gas industry’s capacity to keep growing output through the low price period. “We missed, slightly, the industry’s pent-up capacity. Maybe we were off a year or two,” Tillerson said.” And XOM continued to sell NG at those lower prices

But here’s the problem with taking advantage of the current market conditions: the assets Big Oil needs must be long lived. Acquiring $40 billion in producing shale assets today actually makes the situation worse from the standpoint of reserve replacement if much of that shale production is still in the high decline phase. They would represent even more pressure on a Big Oil to find even more new reserves to replace that depletion.

That’s why the “growth thru acquisition” model isn’t going to work as well today as it did decades ago. There is very little long life reserves available today compared to past busts. Even acquiring major Deep Water GOM production doesn’t work very well: while their decline may be slower than the shales most would deplete just 4 or 5 years after an acquisition. As many here already know the US oil industry is dying. There might be occasion signs of recovery as we just saw with the shales. But that wasn’t a remission of the cancer killing the oil patch but just a momentary pause on the way to the morgue. LOL.

[Tanada]

$this->bbcode_second_pass_quote('ROCKMAN', 't')ita - As T points out there are two primary ways to grow reserves: with the drill bit and thru acquisitions. But there’s also risk there just like with drilling. Consider the XTO acquisition by ExxonMobil back in 2010. They gave XTO shareholders $41 BILLION in XOM stock based upon the assumption that the NG prices would soon be increasing. They were wrong…very wrong: “Tillerson added that ExxonMobil underestimated the US natural gas industry’s capacity to keep growing output through the low price period. “We missed, slightly, the industry’s pent-up capacity. Maybe we were off a year or two,” Tillerson said.” And XOM continued to sell NG at those lower prices

But here’s the problem with taking advantage of the current market conditions: the assets Big Oil needs must be long lived. Acquiring $40 billion in producing shale assets today actually makes the situation worse from the standpoint of reserve replacement if much of that shale production is still in the high decline phase. They would represent even more pressure on a Big Oil to find even more new reserves to replace that depletion.

That’s why the “growth thru acquisition” model isn’t going to work as well today as it did decades ago. There is very little long life reserves available today compared to past busts. Even acquiring major Deep Water GOM production doesn’t work very well: while their decline may be slower than the shales most would deplete just 4 or 5 years after an acquisition. As many here already know the US oil industry is dying. There might be occasion signs of recovery as we just saw with the shales. But that wasn’t a remission of the cancer killing the oil patch but just a momentary pause on the way to the morgue. LOL.

[marmico]

Enno Peters has compiled an interactive Bakken data base.

http://shaleprofile.com/index.php/2016/ ... l-2015-12/

It appears that 2007 vintage Bakken wells are producing ~20 b/d eight years later.

[Lore]

Like Maxwell House Coffee, it's good to the last drop!

[ROCKMAN]

Pstarr - the conversation mutated to how reserve additions can still occur even in a bust. Essentially it's the transfer of reserves from the crippled to the healthy.The GOM connection was the relatively short lives of Deep Water fields.

It also relates to the low level of residual reserves in the shale wells after several years. While there are reserves to be acquired their low production rates indicate how small those individual numbers are.

And while the late 20 +/- bopd in the Bakken might be a shock to some it's even worse for many of they 20 +/- bopd Eagle Ford wells: they could be uneconomical to continue producing, They have to be pumped for rather deep and can have a significant about of produced waters to dispose.. Both aspects can be expensive

Just more factors that will result is a good bit less useful reserve acquisition to deal with the reserve replacement problem then we've seen in past busts.

[Zarquon]

$this->bbcode_second_pass_quote('ROCKMAN', 's')ub - Not predicting it but the Rockman wouldn't be shocked if a lot of tracts are leased...especially Deep Water. Remember it can be the better part of 10 years between winning a lease and first production.

[ROCKMAN]

Z - Here's a realistic time line. Exploration phase: acquire 3D seismic and construct geologic model: 1 to 2 years. Wait for area of approved prospect put up for auction: 1 to 4 years. Win lease covering prospect...or another company wins lease. Once lease is awarded schedule DW rig to drill first wildcat: less the 1 year to 3 years depending on rig demand. Drill first exploratory well: less then 6 months. The first well might justify field development but usually not. So schedule rig for confirmation well: less then 1 to 3 years depending on rig demand. Second well confirms develoment potential. Design production infrastructure: 6 to 12 months. Construct infrastructure: 1.5 to 3 years deornding in part of shipyard space available. Deploy and install infrastructure: 12 months to 1 year. Schedule rig to drill devlpment wells: 1 to 3 years depending on rig demand. Drill and complete, let's say, 8 development wells: 1.5 to 2.5 years.

Timing could be shorter if company has long term contracts for rigs. But a risky move: 6 months ago and operator cancelled it's long term contract for 2 rigs. The penalty they were willing to pay TO NOT DRILL THE WELLS THEY HAD PLANNED: $400 million. Yes...they paid the drilling contractor $400 MILLION TO NOT USE ITS RIGS.

You can add up the possible time lines but even just counting from the point a company is awarded a lease it can easily be 5 years and up to 10+ years. And even longer: it might be 10+ years for that company that paid the $400 million to abort their plan to start the process again. Or maybe they never do.

[Tanada]

$this->bbcode_second_pass_quote('pstarr', 'T')here is little or no more money for deep water. Tupi, deep-water Angola nothing happened at $100. Not after the blowout. Not with $40 oil.