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The Dangerous Economics of Shale Oil

Today's lower prices will kill the shale 'miracle'
Tuesday, December 23, 2014, 2:31 PM

Note: The tables in this article have been updated since its initial publishing.

For years, we've been warning here at PeakProsperity.com that the economics of the US 'shale revolution' were suspect. Namely, that they've only been made possible by the new era of 'expensive' oil (an average oil price of between $80-$100 per barrel). We've argued that many players in the shale industry simply wouldn't be able to operate profitably at lower prices.

Well, with oil prices now suddenly sub-$60 per barrel, we're about to find out.

Using the traditional corporate income statement, it is difficult to determine if shale drilling companies make money. There are a lot of moving parts, some deliberate obfuscation at some companies, and the massive decline rates make analysis difficult – since so much of reported profitability depends on assumptions made regarding depreciation and depletion.

So, can shale oil be profitable? If so, at what price? And under what conditions?

I try to deconstruct all this here.

Technology

A shale well consists of a vertical shaft that drives down into the earth to get to the right geological layer where the oil is located. Then the shaft bends 90 degrees, and extends horizontally 5000-10000 feet. It is in the horizontal section where the magic takes place. At intervals along the horizontal section, the “frac stages” happen, each of which fracture the surrounding rock to release the oil locked inside the rock.

Constructing a shale well happens in two stages. First both the vertical and horizontal sections of the well are drilled, and that costs around $4 million taking perhaps 20 days. Then, the well is “completed” - this is where the frac stages are placed. Each frac stage costs around $70k, and there are often 20-30 frac stages per well. The entire completion process costs around $4M. Once completed, the well starts producing oil and gas.

The initial production (IP) of a new well is a critical number for estimating the total amount of oil likely to be produced over the lifetime of the well (“Estimated Ultimate Recovery” = EUR), along with the expected decline rate. While the EUR is a theoretical number and assumes a recovery time of 10-30 years, from a practical standpoint, companies need to recoup the costs of drilling the well within 3 years.

Shale drilling has dramatically improved over the past five years. Horizontal lengths have doubled, upgraded drill rigs result in fewer breakdowns and faster drilling speeds, pad drilling has eliminated the downtime required to move the drill.

Today's wells (vs wells drilled in 2008-2011) have horizontal sections twice as long, with three times more frac stages, with closer frac groupings, and the wells are drilled in about half the time. This results in wells that produce about twice as much, and take half the time to drill. However at the same time, many of the best spots have already been drilled, so the significant improvements in drilling efficiency have only been able to increase per-well production by a modest amount – perhaps 7%.

Regions, Geography, Decline Rates

There are three primary geographical regions where shale oil drilling takes place: Bakken, Eagle Ford, and the Permian Basin. Total production in these three areas: 4.6 mbpd, or 92% of shale-region oil production in the US. Shale regions provide all the growth in US domestic oil production.

Of these three areas, Bakken and Eagle Ford are the most productive oil shale areas, and of these two regions, I've selected the Bakken for a more detailed analysis.

Decline Rates

The decline rate of shale is the defining characteristic of a shale well, and a shale region. Decline rates vary by region. On average, the Eagle Ford region has a 62% decline rate, the Bakken region overall has a 54% rate, and the Permian region (many wells there are not horizontal wells) declines at a 33% rate.

Individual wells decline more rapidly, and most steeply in their first year of production: Bakken wells decline at a 72% rate for the first year, and then more slowly in the following years. Many Permian wells are vertical wells, and so their decline rates are much more gradual, accounting for the slower Permian region decline rate.

If a well's IP (initial production) is 1000 bbl/day, a 72% well decline rate means that one year later, that well will only be producing 280 bbl/day. With the IP=1000, the first year production is 205k bbls, and the EUR (lifetime theoretical) is 650k bbls. Here is a look at changes in the decline rates of the different regions over time. [source: http://www.eia.gov/petroleum/drilling/]

Drilling Rights

In order to acquire the right to drill on a particular patch of land, the drilling company must purchase these rights from the landowner, and/or another drilling company that has already bought the rights. In the most productive areas such as the Bakken shale, rights are expensive, with recent transactions priced around $10k per acre.

After a fair amount of experimentation, drillers have determined they can put from 1-3 wells on one square mile before the wells start interfering with each other. There are 640 acres per square mile, therefore drilling rights are about $6.4M/square mile. This makes land costs to be around $2M-$6M per well.

Before you can drill, you have to get the rights. Typically, you go into debt in order to buy the rights, then you start drilling to recoup your investment and pay the interest costs on all that debt. Maybe you can even sell those rights to someone else for a profit. That's the ponzi aspect of shale: buying land rights with junk bond financing for $2000/acre, and selling those right off to an unsuspecting oil major for $10,000/acre.

Rights only last from 5-10 years. Failure to drill = wasted money.

Shale Economics

To understand the economics of shale, we view company performance through the lens of accounting. A good accountant is a historian, honestly assessing the success or failure of a particular venture. (A bad accountant – at Enron, for example – is a fiction writer).

So first, some accounting terms:

  • Revenues: barrels of oil sold x the price of oil. Its pretty simple.

  • Capex: capital expenditures. In shale, this is all the costs involved in drilling and completing wells, purchasing equipment, land drilling rights, and other long-lived assets required to run the business.

  • Opex: operating expenses. In shale, this includes all the other expenses the business has:

    • well operations: insurance, repairs, maintenance, pumping costs, etc

    • G&A: general & administrative costs – including paying the CEO

    • interest expense: for bonds, bank loans, preferred stock dividends

    • transport: getting the oil to market

    • royalties: paying the landowner a chunk of your revenues

    • production taxes: paying the state a chunk of your revenues

  • depreciation/depletion: a fraction of capex – it should be the decline rate of each well multiplied by the cost of the land plus the cost to drill & complete.

  • Income = revenuesopexdepreciation

    • here is where the funny stuff happens. If you want your company to look profitable, you will tell your accountant to write a work of fiction rather than be a historian. Instead of having her use your actual 72% well decline rate, you will instead tell her to use, say, 10%.

    • Key concept: understating depreciation increases reported profits. Why would you do this? Well, if you wanted to sell your shale properties to a greater fool, you probably want to look profitable in the meantime. Or if you wanted to get a bank loan, or sell junk bonds, you probably want to look profitable too. Banks are more clever than junk bond buyers, however; they use ratios that depend on EBITDA, not phony “profits.”

  • EBITDA: revenues – opex

    • Simply put, this is “earnings before accounting/depletion fraud.”

    • This is the number I use to study profitability in the shale world. I can then apply my own depreciation based on decline rates and figure out for myself how the business is really doing.

All right, armed with your new degree in shale accounting, let's look at a simple fictional example. The hypothetical One-Well Shale Company obtains property for $10k/acre, then drills and completes a Bakken shale well costing $9M, with an IP of 500 bbl/day, 1st year production: 102k bbl, decline rate 72%. Further, we assume an eventual 3 wells per square mile, and an oil price of $99/bbl.

The income statement shows that with honest accounting, we are barely profitable just looking at the 3-year P&L statement. The price I selected wasn't an accident – I searched for the break-even price and found it at around $99/bbl. 

However, will this well at $99/bbl ever make back its drilling costs? It won't, since in the following years, the “fixed costs” for the company will be a heavier and heavier burden on the well whose production declines every year. Likely, $99/bbl is even too low. We can call it a “best case scenario” - only if we assume One Well Shale sells the well to someone else for $986k (the remaining depreciation) at the end of year 3.

What's more, companies have already spent huge sums accumulating land, on which they've drilled a relatively smaller number of wells, so this “One-Well” shale company is definitely fictional. Take OAS, which has 468 wells in production (45k bbl/day = 98 bbl/well) and 779 square miles of land they've bought for $1.8 billion. That's only 0.6 wells per square mile. However, they've already spent the money for the land, so from a “cash flow basis”, they don't really count the land cost when answering the question: “do I want to drill a well here or not.” At this point, money to buy the land is gone, so from a corporate survival standpoint, all they ask is, “if I drop a well, will it pay me back in 3 years?” And in the current environment, they probably only look at year 1 when making this analysis.

But from an overall economic analysis of shale profitability over the longer term, land cost really is an important factor, so we include it in our accounting. If we were to be hard-nosed, we would probably assume a “wells per sq mile” of 0.6, since that's the “actual debt burden” on the real drillers like OAS.

Now lets drop the oil price to $55/bbl and see what happens to One-Well Shale.

Its a sea of red ink. Clearly this well loses money. It cost $9M to drill, and we get back $2M in EBITDA at the end of year 1, the best year for the well. By the end of year 3, EBITDA is negative. It is definitely not worthwhile to drill this well, not even if we assume the land is free.

This represents the average well in the Bakken. At current prices, the average well loses money, no matter how you slice it. So how will this affect capex budgets in 2015? Here's one data point from OAS, a company for whom 100% of their production comes from the Bakken: they are cutting their capex budget in half, choosing only to drill in their better properties. [Source: an awesome, detailed, fact-filled investor document that Google located for me – one wonders if they meant to release it to the public: http://www.oasispetroleum.com/wp-content/uploads/2014/12/2014-12-OAS-IR-PresentationvFINAL.pdf]

Hedging

Shale producers don't want to expose themselves to bouncing oil prices – they have fixed costs, and so they'd prefer to have fixed revenues too. So they typically engage in oil price hedging to eliminate one big variable from their business plan. One-Well Shale certainly had big problems when oil dropped to $55/bbl; if One-Well had engaged in hedging, it might have been able to ride out the low prices at least for a time.

There are many types of hedges available – our friendly banking establishment stands ready to provide all sorts of financial tools to shale companies to help them out. For a fee, of course. I'll start with the simple ones, and gradually get more complicated.

  • Swaps: buyer locks in a fixed price for oil. No upside, complete downside protection – you know exactly what price you'll get, and on what date. Low cost. This is why futures markets exist. Speculators take the risk, and companies get to operate in a more predictable world.

  • Puts: complete downside protection, unlimited upside. The higher the floor and the longer the date, the higher the cost. Puts are relatively expensive.

  • Collars: complete downside protection, lower cost, limited upside. Buyer writes a call, and buys a put. Upside available up to the call strike price, and the call helps make the put less expensive. As with the standard put, the higher the put's strike price and the farther out the date, the more expensive it is.

  • 3-Way Collars: limited downside protection, limited upside, usually free cost. Buyer writes a call and a put, and buys another put. This complicated beast generally ends up being free, but only is good for maybe $10-$15 of coverage. It's probably a banker's delight. It sounds vaguely salacious.

When you look at the company hedge book, which they report in their 10-Q, understanding just what sort of coverage they have is quite important. Swaps provide perfect coverage, while 3-way collars only protect against a fraction of the drop we've just experienced. And its important to match up the number of barrels of coverage to the oil production, to see the percentage of coverage the company has in place. A survey of shale companies shows a range of from 20-60% coverage, at an oil price of about 90.

Looking at our favorite Bakken company OAS, we see their hedge book below, helpfully provided in their investor document. It looks complicated. So we just look for key words: first, what type of hedges? Swaps, puts, & 2-way collars. Great, that's 100% coverage. Second, how much production do they represent? 1H 2015: 32k bbl day, and 2H 2015: 15k bbl/day. Let's assume OAS keeps production steady at 45k bbl/day. That's a 71% coverage for 1H 2015, and a 33% coverage for 2H 2015 at “around” $90/bbl. Looks like they'll be mostly ok for 1H 2015, but for 2H 2015 they will definitely be losing money if oil stays at $55/bbl.

Hedges can be cashed in at any time. A company with a trader as a CEO, or one that needs to raise cash to stay in business today might well decide to “go naked” and take their chances with market oil prices and close out their positions. One company did this just recently. CLR sold their entire hedge book in Q3 2014, raking in a cool $420 million. They did this (from what I can tell) when oil was trading at about $77 – about $20/bbl too early. They left $500 million on the table. Maybe more. And now they're fully exposed to $55 oil. Factoid: $420 million will fund one month of 3Q capex at CLR.

Shale History & Accumulated Debt

One-Well Shale's “honest income statement” shows that 2014 shale technology is economical at $100 oil, assuming “average well production” - an IP of 500 is average in the Bakken.

Of course, shale companies must survive today, with oil at $55/bbl. Let's assume OAS gets serious, and drills only in their really hot areas. Viewed through the One Well Shale P&L statement, if I set the IP=750, and I set the oil price to $87/bbl, cash flow is $9M in the first year and a 3-year ROI of 67%. Through 1H 2015, OAS will be all right if they can just drill their best opportunities, and rely on their hedge book to keep them afloat.

That's not the the same thing as asking if the wells they drill will be “profitable long term” since that $87/bbl price obtained via hedges will only last through 1H 2015. Once the hedges run out, those IP=750 wells will be just barely above break-even (after 3 years!) at $55/bbl. But for the moment, OAS can stay above water.

I'm deliberately avoiding the question of how long-lived the shale resource is. I am just answering the question: what is the break-even oil price for drilling a Bakken shale well. The answer is, with an average well (IP=500) at a company with an average cost structure is long-term break-even at about $99/bbl, best case, assuming 3 wells per square mile and a property cost of $10k/acre.

Bottom line: the average US shale oil well is uneconomical even with hedging in place, since most hedging is around $90/bbl and the break-even is $99/bbl.

The Risk We Now Face

In Part 2: The Destruction That Awaits, we delve into the important question of the longevity of shale oil supply. The projections we can make from the latest data are quite frightening.

As is the massive impact today's oil prices will have on the shale industry should they persist. Simply put, if oil prices stay at $55/bbl, we will eventually lose the vast bulk of US shale oil production, simply because perhaps 3/4 of even Bakken shale is just not economical at that price.

And this prediction assumes the economy continues along as it has for the past several years. Should there be a serious economic contraction and/or a tightening of the credit markets, and the declines hit harder, many fewer shale drillers will be able to find any sort of funding, property sales will be fewer and for lower prices, and a lot more shale drillers will go bankrupt – and recoveries on those bankruptcies will be lower. Knock-on effects will hose the banks providing credit lines, vendors that provided services to companies and were not paid, and pension (and bond) funds that bought the junk bonds that are now worth pennies on the dollar. All of this will simply worsen the carnage to the shale sector.

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16 Comments

sand_puppy's picture
sand_puppy
Status: Diamond Member (Offline)
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Caption this

I don't mean to detract from the scholarly analysis of DaveF above.  

Caption this:

First:  "OK. We agree that the US Shale projects must die.  I celebrate our agreement by this gift of a bling made of pure barbarous relic."

Time2help's picture
Time2help
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#2

"Tell George and Jeb I said Hi."  "You can tell them in person at the inauguration."

sand_puppy's picture
sand_puppy
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Domestic drop in oil demand??

This graph was offered to support the idea that domestic demand for oil is down and that drop in demand is the driver of the collapsing oil price, not "over pumping" by the Saudi's.  DaveF and Chris--does this sound correct to you?  Is this a signal economic downturn?

And this to predict the drop in rigs that follow price drops, just as DaveF said.

cmartenson's picture
cmartenson
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Yeah, that's the wrong graph...

Sandpuppy - people get that gasoline graph wrong all the time.  That one you have reproduced here is simply for US refinery retail sales of finished gasoline.  I see that one trotted out a lot to purportedly show a huge decline in US demand.

The correct answer lies with the fact that the US imports a lot of finished gasoline mainly from Europe.  They don't need as much gasoline because they use more diesel and we're the opposite in the US.

So the ships pass in the night, gasoline this way, diesel that way.

The correct graph is "supplied finished motor gasoline" and that's this one here:

(Source

As you can see there's a bit of a dip there from 2008 to current, but nothing like what the refiner-only chart shows.

The real story is not about a dip in US demand, but in Asian demand as they have been the main drivers of all demand growth from 2008 to current.

Unfortunately I don't have good info for China/India imports, at least data I feel good about.

Sterling Cornaby's picture
Sterling Cornaby
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Posts: 152
breaking it down for my simple mind

Dave

Thank you for the article, I am just fleshing out ideas in my mind that you presented.

I put this "how I see it" table together which is off a bit on the details:

 

  total costs                  # of barrels      100$/b        70$/b        55$/b
drill'n 11133333   year 1    102,750 10275000 7192500 5651250
year 1 2791902   year 2      40,050 4005000 2803500 2202750
year 2 1724435   year 3      28,800 2880000 2016000 1584000
year 3 1532903          
total cost 17182573   total three year Rev. 17160000 12012000 9438000
      total Rev -total costs -22573 -5170573 -15598573

 

So this is how my non-accountant brain sees 'breaking-even' for this really nice idealized well:

  • At 100$ per barrel I am get very close to breaking-even, at under $100k for total rev.- total costs, to paying off all my expenses, including all the costs for the well.  I am close to paying for this project in three years and getting the full gravy profits in the years ahead.
  • At 70$ per barrel I am still $5M off my total costs, so at least I am catching my drilling cost, (catching up to the red queen sort of speak)  so my gravy profits are still a few years in the future.
  •  At 55$ per barrel I am $15.5M off, which is more than I put into just drilling the well in the first place!  So I am going no where fast, giving my barrels of oil away with a few dollar bills stapled to the side of the barrel.  The red queen is running away.

Anyway this helped me understand this a bit better, so I thought I would post it.

Thank you

Sterling

  

Quercus bicolor's picture
Quercus bicolor
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Dave, I don't understand the

 

Dave,

I don't understand the numbers in the chart above.  The expenses in the rows starting at "Well Operations" and ending at "Production Taxes" add up to about $5.6 million for year 1.  I would expect Opex subtotal to be $5.6 million and EBITDA to be about $1.6 million.  I would then expect the before tax income to be negative even for year one.  What am I missing?

Quercus bicolor's picture
Quercus bicolor
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Posts: 470
Sterling Cornaby
Sterling Cornaby wrote:

Dave

Thank you for the article, I am just fleshing out ideas in my mind that you presented.

I put this "how I see it" table together which is off a bit on the details:

 

  total costs                  # of barrels      100$/b        70$/b        55$/b
drill'n 11133333   year 1    102,750 10275000 7192500 5651250
year 1 2791902   year 2      40,050 4005000 2803500 2202750
year 2 1724435   year 3      28,800 2880000 2016000 1584000
year 3 1532903          
total cost 17182573   total three year Rev. 17160000 12012000 9438000
      total Rev -total costs -22573 -5170573 -15598573

 

So this is how my non-accountant brain sees 'breaking-even' for this really nice idealized well:

  • At 100$ per barrel I am get very close to breaking-even, at under $100k for total rev.- total costs, to paying off all my expenses, including all the costs for the well.  I am close to paying for this project in three years and getting the full gravy profits in the years ahead.
  • At 70$ per barrel I am still $5M off my total costs, so at least I am catching my drilling cost, (catching up to the red queen sort of speak)  so my gravy profits are still a few years in the future.
  •  At 55$ per barrel I am $15.5M off, which is more than I put into just drilling the well in the first place!  So I am going no where fast, giving my barrels of oil away with a few dollar bills stapled to the side of the barrel.  The red queen is running away.

Anyway this helped me understand this a bit better, so I thought I would post it.

Thank you

Sterling

  

Sterling,

Your total revenue - total costs for year 3 is off.  It should be about  $-7.7 million, so some drilling costs have been recovered, but it looks like year 4 revenue will fall below costs for $55/barrel and maybe approach costs for $70/barrel, so the well is a loser over the long term at these prices.  At $100, it seems the well will go into the black in year 4 using your accounting method.

Check out my question to Dave (#6 above).  Based on my reading of the chart, the expenses are higher than reported which would probably make the well a money loser even at $100.

davefairtex's picture
davefairtex
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bad spreadsheet

QB-

Good find, your instincts were right!  It was a bad spreadsheet cell - a leftover "what-if" calculation I had done during development.  And I had another error - shale drillers have to pay perhaps $10/bbl to get their oil to market, but they pay royalties and taxes on their realized price (i.e. WTI - $10) rather than on the WTI price.  So two things changed in the model, not just one.

I'm sending the updated sheets to Adam and he'll update the doc.

New break-even for the average well/average company: $99/bbl WTI.

Its really interesting changing the assumptions to see how different scenarios play out.

If companies can manage to cut some of the non-technology-driven costs: drop tax rate in half, drop royalty payments in half, and cut the interest expense in half, break-even is around $71/bbl for the average well.

Also, if land prices get cheaper (after the ponzi "pop", they'll definitely get cheaper), then of course that will help too.

But right now, with the current (legacy) cost structures in place, companies like OAS have real trouble making money on shale.  It reminds me of gold miners having to pay 10x normal prices for picks and shovels back in the "gold rush" days in California.

If you want to PM me with your email address, I'll send you the spreadsheet so you can play along.  (I'd upload it here, but - quite rightly - they only allow safe things like png files)

jeep's picture
jeep
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EBITDA stands for?

You don't deduct interest if you want EBITDA.  It stands for earnings before interest, taxes, depreciation, and amortization.

davefairtex's picture
davefairtex
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ebitda

jeep-

You are right.

And yet, I really want to retain interest as a part of the cost structure analysis, since it is a very significant part of the shale story.  Junk debt is a big part of what allowed shale to get to its particular point, and it will be the anchor that drags some of these companies under.

What do you think I should call it so I'm not confusing the professionals out there?  EBTDA?  I don't want them to think I'm just a bad speller.

Any suggestion?

 

Quercus bicolor's picture
Quercus bicolor
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Posts: 470
re: bad spreadsheet

Thanks Dave!  I'd love the spreadsheet.  I've been wanting to play with the numbers for a long time, but haven't had the time to do the research to find the missing expense #s.  I'll PM you separately.  I also have a few questions:

  1. Why don't the interest payments decline with time?  Do they just roll everything over and not pay principle?
  2. Are these two assertions correct?  Before the price drop, junk debt rates were 5-6% and a significant proportion of financing was from more conventional sources.   Going forward, though, new wells will have to be financed mostly at junk rates that are now up near 10%.
  3. Is this a correct understanding of depreciation? an agreed upon formula for charging the initial development costs over a number of years based on the well value each year.  Value is based on remaining production.

It would be interesting to do a separate calculation using principle payments instead of depreciation to get an idea of actual cash flow.  Of course, if they're just rolling everything over, there are no principle payments.

Q.B.

davefairtex's picture
davefairtex
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assumptions

QB-

These guys absolutely don't pay down debt, unless they sell a bunch of properties for a profit, then sometimes they do.  Normally however they need ever more money to feed the drilling machine.  If they had to repay it, they'd probably issue new debt to pay off the old debt.

OAS senior secured notes had a coupon of around 7% for 5-7 year maturity.  Not sure when they issued; no way they could get that now.

I adapted freely the concept of depreciation/depletion.  Usually there is some sort of schedule that the company applies to an asset they buy - a computer might be 5 year straight line, a structure (for a building, for instance) might be 27.5 years.  I just took the percentage of lifetime EUR that was pumped that year and multiplied it by the cost of drilling + property rights purchase price.

You can see my spreadsheet here: I uploaded it here rather than fuss around with email: http://www.mdbriefing.com/ows.ods

I found out more about GDP - Goodrich Petroleum.  They're a fascinating case.

GDP bought a whole bunch of land in a new prospective shale area (the Tuscaloosa Marine Shale) for $200/acre.  They borrowed a ton of money to do it, and they are using it to drill and and prove the TMS is a fantastic new place to punch shale wells and get rich.  Their (stated) goal: sell that land for $5000/acre to someone else.

Their wells look good, but I'm a bit concerned they're "homebuilders with a nice house in late 2007."  I.e. the timing for playing this particular game is a bit late in the ponzi cycle...er, I mean, in the commodity cycle...

Quercus bicolor's picture
Quercus bicolor
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davefairtex wrote: I found
davefairtex wrote:

I found out more about GDP - Goodrich Petroleum.  They're a fascinating case.

GDP bought a whole bunch of land in a new prospective shale area (the Tuscaloosa Marine Shale) for $200/acre.  They borrowed a ton of money to do it, and they are using it to drill and and prove the TMS is a fantastic new place to punch shale wells and get rich.  Their (stated) goal: sell that land for $5000/acre to someone else.

Their wells look good, but I'm a bit concerned they're "homebuilders with a nice house in late 2007."  I.e. the timing for playing this particular game is a bit late in the ponzi cycle...er, I mean, in the commodity cycle...

Yes, even in the proven productive areas, land costs are small compared to drilling costs, so that low price for drilling rights won't help them much with a big price decline like this one.

darturtle's picture
darturtle
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Low Oil Price Bad for USA - Shale Gas

Not just ~2/3 of US annual oil consumption produced domestically, most oil produced in USA has high production oil.

Let's see, if US buys a barrel of oil (100/barrel) from overseas, economic activities of the US$100 belongs to the overseas oil producer. On the other hand, if within USA, company A buys a barrel of oil from a domestic producer at the same price, all economic activities of the US$100 is in USA (very little import components). Therefore, if a US oil producer produces oil at US$80/barrel and sells for US$100/barrel, regardless distribution, almost all US$100 economic activities are in USA.

Now, if oil price drops to US$60, people buy US$60 oil, regardless where they are produced. Above mentioned US$80/barrel producer is squeezed out of the market. Worse, if it issued bonds (mostly junk bonds), those bonds go into default.

You can now work out why low oil price cause more trouble than benefit for USA now.

Ironically, EU benefits more as they produce little domestically. However, thanks to politicians elected by PEOPLE (yes, citizens), tax of a gallon of gas is higher than cost of gas therefore, benefit is drastically reduced. An example: a gallon of gas charges US$5 while US$3.5 is tax, even if gas cost drops to US$1, a gallon of gas is still US$4.5.

rjs's picture
rjs
Status: Gold Member (Offline)
Joined: Aug 8 2009
Posts: 445
partially true
darturtle wrote:

Not just ~2/3 of US annual oil consumption produced domestically, most oil produced in USA has high production oil.

Let's see, if US buys a barrel of oil (100/barrel) from overseas, economic activities of the US$100 belongs to the overseas oil producer. On the other hand, if within USA, company A buys a barrel of oil from a domestic producer at the same price, all economic activities of the US$100 is in USA (very little import components). Therefore, if a US oil producer produces oil at US$80/barrel and sells for US$100/barrel, regardless distribution, almost all US$100 economic activities are in USA.

Now, if oil price drops to US$60, people buy US$60 oil, regardless where they are produced. Above mentioned US$80/barrel producer is squeezed out of the market. Worse, if it issued bonds (mostly junk bonds), those bonds go into default.

You can now work out why low oil price cause more trouble than benefit for USA now.

Ironically, EU benefits more as they produce little domestically. However, thanks to politicians elected by PEOPLE (yes, citizens), tax of a gallon of gas is higher than cost of gas therefore, benefit is drastically reduced. An example: a gallon of gas charges US$5 while US$3.5 is tax, even if gas cost drops to US$1, a gallon of gas is still US$4.5.

true, as far as it goes...but as of October, we still had a net petroleum deficit of around $15 billion a month...without digging up the details, let's say we imported $20B of crude, and exported $5B of diesel...if we were importing oil at $90/brl then, and $60 going forward, the savings on the imports will be $6.6 billion...meanwhile, the refinery's pricing is somewhat sticky and they make a killing selling products from that cheap crude to europe & japan..

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kim4dw
Status: Member (Offline)
Joined: Apr 6 2014
Posts: 1
Hedge Fund Blow-Up?

While many theories for the collapse in oil and natural gas prices have been put forth (Saudis attacking higher cost US shale producers, Saudi-US coordination against Iran, Russia, Isis, etc., and overproduction by shale producers because of cheap credit and need to fulfill lease agreements), is it also possible that a hedge fund has blown up? In 1994, Matthew Simmons explained how forced selling by a hedge fund led to a similar price decline http://www.simmonsco-intl.com/content/documents/whitepapers/Crude%20Oil's%20Price%20Collapse-%20Was%20MG%20The%20Culprit.pdf. In that case, the truth did not come out until several months after the damage was done. Perhaps the unwinding of Andy Hall's positions or some other fund has had a similar impact more than 20 years after Simmons' article. In particular, something doesn't smell right about the rapid drop in natural gas prices in the last week. Was it that much of a surprise that the weather was going to warmer for a few days?

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