[Graeme]

Here Are The Breakeven Oil Prices For Every Drilling Project In The World

$this->bbcode_second_pass_quote('', 'O')n Thursday, OPEC announced that it would not curb production to combat the decline in oil prices, which have been blamed in part on a global supply glut.

And now that oil prices have fallen more than 30% in just the last six or so months, everyone wants to know how low prices can go before oil projects start shutting down, particularly US shale projects.

In a note last week, Citi’s Ed Morse highlighted this chart, showing that for most US shale plays, costs are below $US80 a barrel.

[Subjectivist]

The problem with this spiel, in my opinion, is how much profit margin does it take to service existing debt and avoid default? Saying you break even at $60.00 is all well and good, but nobody invests to break even. People, mostly in the form of mutual funds, invest to make a profit. If break even is $60.00 and WTI is also $60.00 then investors will probably refuse to invest in anything that breaks even at $50.00 or more. Even worse if the market is volatile they won't invest at $50.00 either because the risk reward ratio is too hazardous.

[eugene]

My read the BS is flowing big time. Truth? Who knows?

[ROCKMAN]

Eugene - Or put differently: there is no such thing as a "breakeven price" for any play. And that isn't a hypothetical position. I can show a great many Eagle Ford wells that wouldn't breakeven at $120/bbl and many that would make a handsome profit at $40/bbl. I've even see a few that would lose money at $200/bbl.

The price of oil won't determine if wells are drilled in a play or not. But the price of oil will determine HOW MNY WELLS ARE DRILLED. And that will determine what future oil production will be developed in each play. So again: a wells profitability isn't determined by the price of oil/NG. It's determined by the difference between what you sell it for and what it cost you to get it out of the ground. As I've posted before the best profit I've ever generated was from 23 NG wells which I sold the production for 1/3 the current low price.

If shale drilling does drop off significantly the cost of drilling/frac'ng will also fall. A $10 million Eagle Ford well drilled 6 months ago might only cost $7 million in 6 months. This might not keep every EFS well on the drilling schedule but a number will hang in there.

[AndyA]

I'd add that there are reasons for drilling, other then current price. Companies may have hedged like they have done with fracked gas, it's pretty common for commodity producers to hedge a certain portion of production, whether they do it through comex or directly with end users makes little difference. Another reason for continued drilling for fracked gas was that there was some sort of agreement in the land lease requiring the well to be drilled or the lease expired. One more point in favour of continued drilling is for cashflow, the fracked wells have high initial production, while debts usually have long terms, and being optimistic creatures people are likely to drill now and hope for the best.

It would be great for the peak oilers to be proven right as production crashes along with the oil price and the world goes into recession, but I think its a little more complex then that. The inertia in the system is likely to keep oil prices down for longer then many expect. According to some analysts fracked gas is still uneconomic at the current price, but it took a few years of low prices to have a marginal effect on drilling.

[ROCKMAN]

"...but it took a few years of low prices to have a marginal effect on drilling." There is a time lag. But one might want to check the change in the rig count for NG from '08 thru '09. The 70% decline in the number of rigs came very quickly. I doubt many would consider that to be a "marginal decline". And 5 years later the count still remains 70% lower then the peak of such activity. NG production hasn't declined thanks to the associated NG production of the oil shales and the continued development of DW GOM NG gathering systems.

[Tanada]

$this->bbcode_second_pass_quote('ROCKMAN', '&')quot;...but it took a few years of low prices to have a marginal effect on drilling." There is a time lag. But one might want to check the change in the rig count for NG from '08 thru '09. The 70% decline in the number of rigs came very quickly. I doubt many would consider that to be a "marginal decline". And 5 years later the count still remains 70% lower then the peak of such activity. NG production hasn't declined thanks to the associated NG production of the oil shales and the continued development of DW GOM NG gathering systems.

[ROCKMAN]

T - Difficult to predict. OTOH the pubcos will want to replace reservea. But if their stock prices take a big hit they'll blame lower oil prices instead of their unsustainable biz plans. I've seen that spin many times over the last 40 years by pubcos trying to cover up their incompetence. The other big uncertain factor is the debt. Not just how much they owe but future credit lines that will be lowered as oil prices decline. A company might keep current on repayment or keep drilling: but many won't be able to do both.

[shallow sand]

ROCKMAN. I'm sure you can shed some light on this. I assume every year about this time public oil producing companies are in the process of having their reserves revalued. I think I read you post that they used to have to use the strip for oil and Nat gas as it closed on the last trading day of the year, but that has changed?

In any event, assuming oil prices continue to slide, or at least do not rebound, what do you foresee concerning these companies' ability to borrow? I think most PV 10 in 2013 was based upon an oil price of $96 WTI, and then adjusted by the engineering firms depending on location, etc.

I also read on this board that possibly the drilling of vertical holes began to decrease in July, but that unconventional horizontal increased. Guess I am still searching for why traditional lending standards for shale drillers were not followed. Maybe they were, but seems to me they were allowed to borrow a lot more in proportion to their reserves and cash flow than your typical small private conventional company.

I guess in summary, I'm asking how the borrowing really works for these companies and do you see much of the funds being shut off assuming no immediate rebound in oil prices. I know each case is different. I just can't see how anyone would be drilling now on borrowed money.

[Tanada]

$this->bbcode_second_pass_quote('shallow sand', 'R')OCKMAN. I'm sure you can shed some light on this. I assume every year about this time public oil producing companies are in the process of having their reserves revalued. I think I read you post that they used to have to use the strip for oil and Nat gas as it closed on the last trading day of the year, but that has changed?

In any event, assuming oil prices continue to slide, or at least do not rebound, what do you foresee concerning these companies' ability to borrow? I think most PV 10 in 2013 was based upon an oil price of $96 WTI, and then adjusted by the engineering firms depending on location, etc.

I also read on this board that possibly the drilling of vertical holes began to decrease in July, but that unconventional horizontal increased. Guess I am still searching for why traditional lending standards for shale drillers were not followed. Maybe they were, but seems to me they were allowed to borrow a lot more in proportion to their reserves and cash flow than your typical small private conventional company.

I guess in summary, I'm asking how the borrowing really works for these companies and do you see much of the funds being shut off assuming no immediate rebound in oil prices. I know each case is different. I just can't see how anyone would be drilling now on borrowed money.

[ROCKMAN]

Companies once as per SEC regs had to use the closing price on 31 Dec to revalue their booked reserves. But now they use a calculated average price for the previous year. Not exactly sure how this is determines. But here's the significance of the revaluing: not only does it reduce the value of some of the proved reserves it can also change a certain amount from proved commercial to proved non-commercial. Which means the loan value of those reserves go to zero. And the borrowing base of the remaining proved commercial reserves is reduced.

And from that point it can get very complicated and very company specific. Many different forms of leverage: increased interest rates; mandatory (and expensive) hedge placements...hedges that can cause a company to lose beaucoup bucks when prices increase; and many different formulations of "poison pills" to restrict divestitures and other stock manipulations. This can become the time of accountants and lawyers instead of geologists and engineers. And corporate cannibals.

As per the Chinese curse: interesting times.

I don't have much direct experience in this area. But it can get bloodier then most outside the oil patch can anticipate. Careers/fortunes/families destroyed. Last big bust in the 80's led to a couple of suicides I personally knew of. At this point I wouldn't predict such a severe bust. OTOH I wouldn't be surprised if it happens either.

[shallow sand]

I guess a lot of the $$ has been raised from issuing bonds, not directly from banks. Wonder if the bond rating agencies have done a better job on these than they did a few years ago on mortgages? Would think when PV 10 is recalculated the rating agencies should downgrade the bonds?

See ConocoPhillips says they can make good return in Eagle Ford and Bakken at $40 WTI. Seems ironic given EOG just said the same. Wish I knew how they can guarantee EUR of 750,000 on every well.

[shallow sand]

Also, trying to say there is a breakeven price is futile. I bought into that it could be done, but it cannot be. Too much variability. Go to the state websites and look at the production figures. They vary wildly, it is not a manufacturing process.

Go to energynet.com and browse the horizontal interests for sale. Some look great, some look terrible. There is a Cline shale project that closes this week that hasn't drawn a bid and I bet they have several million in the one well they have drilled, let alone the large acreage block that goes with it. I think its made under 30,000 bbl of oil since completion and water is being truck hauled hourly.

There are wells Continental drilled that will need 100+ oil for many years to have a snowballs chance of payout. There is one that mention a fishing job resulted in an extra 1.4 million dollars in costs. Is that figured into breakeven?

This is also why I think breakeven should be somewhat irrelevant. There is too much risk for breakeven to be acceptable. As an example, if you had $10 million dollars would you drill a well that statistics say should break even over 30+ years, but could end up cutting your 10 million to a payment steam over the years of half that amount or less? Better yet, would you borrow 10 million to do that? You can find thousands of middle bakken, three forks, eagle ford, wolf camp, etc. wells that will do just that. Numerous wells that have not made 100,000 bbl in two years gross. Those wont payout with well head prices in 40s or 50s.

There is so much public information out there, even an amateur like me can figure out there are some real problems. For not a great sum of money you have subscription services that have even more info. I assume the Gulf OPEC members have a huge team that has analyzed every unconventional well drilled in the US and has analyzed each on both a production and economic basis. I further assume they have performed analysis on every pubco financial condition. I presume this analysis was discussed in determining what action to take Thanksgiving Day.

My concern is the pubcos are somehow able to get away with statements like, "we will make a 10% return in the Eagle Ford with oil prices at $40". On which well I ask? Sure, the monster that makes a million barrels in year one, it will be ok below $20 per bbl. It also skews the average high. What about the many wells that make under 50,000 in year one and are now under 1,000 bbl per month? They are toast.

I truly hope the mortage meltdown like debt to the shale drillers stops. However, I am pretty sure we want so badly to be oil independent in the US that the money could keep flowing to these guys, despite the fact it likely will never be paid back.

[ROCKMAN]

Shallow - "Wish I knew how they can guarantee EUR of 750,000 on every well." I'll point out what you already know: how much oil a well produces, be it 750,000 or 75,000 bbls, doesn't determine profitability. Nor does the price of oil. Profit will always be a function of how much net revenue a well creates and the cost to drill, complete and produce the well. Wells with 6,000' laterals and 88 frac stages might have very impressive initial rates. But they will cost a great deal more then previous well designs. But if there were one company I would bet on to make their average shale well profitable it's EOG. But unfortunately for EOG it can't dictate oil prices. What net present value EOG projected for their new "fat frac" design it is currently seeing a significant reduction even if the new wells preforms as modeled.

[newman1979]

The real issue is what lending will be going forward in a $60-70 a barrel be? Today most shale players carry huge debt. What lender would loan more when the underlying debt is going down in value fast now? Then if lenders get tight going forward, won't the existing well decline rate coupled with the lower market price weigh on the asset price of both debt and equity? IMO the ponzi nature of the shale oil will soon start to emerge when lenders and regulators understand the risk parameters in sharper detail. No bailouts will be available from the government. How can a lender trust a a future claim from a driller when the risk of not getting whole on the existing loans is growing?