[rockdoc123]

This is a followup to part 1 of the shale discussion where my intent is to try and bring some factual information to the discussion as it can be confusing for people not directly involved in the business. See part 1 for further description

Here is Part 2 which deals specifically with shale economics.

Economics

There are several ways of looking at economics of these pools. If you are an operator you would calculate them yourself with known inputs. If you are someone sitting on the outside looking in there are some tricks you can use. If you have access to the analyses by some of the larger banks such as Credit Suisse you can take a look at what breakeven cost they have determined for the various shale plays. Breakeven cost is usually calculated based on taking into account all of the possible costs and taxes (excluding depreciation), EUR, IP, decline assumptions, commodity pricing to arrive at what price level a zero NPV (discounted at 10% or 15% usually) is achieved. Some care has to be taken here in that some report breakeven costs as half cycle whereas others report them as full cycle (the latter usually being smaller). For the EagleFord Credit Suisse has been reporting a breakeven cost of $2.60/Mcf for wet gas and $50/bbl for oil. I’ve seen other numbers for gas that are both more and less but the oil number seems to be verified by a few analysts. Interestingly enough Credit Suisse breakeven analysis for the EagleFord is a lot less than it was 2 years ago, the main reason being cost assumptions. Given that current pricing in the Eagle Ford (which receives a bit of a premium to WTI) is around $100/bbl compared to a breakeven of $50/bbl it is clear this is a very economic bit of business for most operators who know what they are doing.

Although commodity price is obviously important to the economics of these plays equally important is costs and how they are managed by the operators. Most of the companies point to cost cutting in their operations as adding significant value to their activities. Pioneer as an example last year was able to lower costs by ~$600 K per well by exclusively drilling from pads and managing the number of active rigs. They dropped a further $700 K from many wells by moving to clean sand as the fraccing propant versus the more expensive silicon beads. These drops are very significant when you think the well cost is around $7 to $7.5 million prior. EOG speaks to having lowered their average well D&C costs from $6.5 million to $5.5 million. It is important to realize that a 10% - 15% cut in costs has an immediate positive impact on the bottom line.
Another way of looking at economics of these wells is to peruse various shale operators filings and/or corporate presentations to see what they report as operating netbacks. The netback calculation basically speaks to how much the operator gets to keep after all allocated capital and operating costs after tax. EOG as an example states their netback as being ~$35/bbl. Argent Energy Trust (hey I own some of this!) notes they receive operating netbacks of around $50/bbl for Austin Chalk and $70/bbl for EagleFord partly due to a premium they receive in oil price but also because their operating costs are so low. Not everyone calculates netback exactly the same but the bottom line generally is if you have a significantly positive netback then the play is economic.

One other method is to look at payback or the time at which all of your costs for a well have been paid out through production. This is more difficult as different operators may report this pre or post tax and not really tell you what their assumptions are. What I have seen is anything from as low as 6 – 9 months (Rosetta) to as high as 3 years (Marathon). Given that all of these wells are expected to produce for more than a decade or 2 there is ample opportunity to make money given the hyperbolic nature of the decline at that point in time.

You can also go to the financial information submitted by various shale companies to the SEC or TSX. As an example in Canada all of those submissions are available on-line from SEDAR. The new IFRS standards can make some of the information hard to find but it is all there. What you are looking for is the free cash flow from operations prior to interest, depreciation and amoritization (sometimes called EBITDA) which will show you how much cash the operation throws off net of all of the operating expenses, G&A etc and net of any income from sale of assets. You simply have to take off the corporate tax rate for the jurisdiction in question and you have an idea of after tax profits before reinvestment. You have to be careful with oil and gas companies however. Unlike manufacturing businesses where there is generally a large capital outlay at the start and then little capital required further along the oil and gas business and especially where shale comes into play can have a number of years of investment. As an example the CHK financials show something in the order of $3 billion in free cash flow from operations net of any asset sales. Capital expenditures are high though so without sale of lands the cash flow they would keep drops down considerably. CHK purposefully tries to offset additional capital expenditures with sale of assets (lands that they do not see as having the highest potential in their portfolio).

And finally calculating it out yourself to do some sense checking. So if we take the lower end of the EUR/well for oil at 200 MBOE, create a production profile similar to a power law function (I used 75% decline rate for the first 24 months and then a hyperbolic style decline to a point at which 200 MBOE was reached and stopped production) and then use the low netback that EOG has specified in their presentations ($35/bbl for oil) , oil pricing of $94/bbl as compared to the actual higher than WTI pricing that is being received currently you end up with ~$16 MM USD NPV10 for a single well that is after tax. If you assume EOG drill costs of $5.5 MM USD and throw in some allocated money for leases, tie-ins, minor facilities etc the it could be an all in allocated cost might be around $7 - $9MM. So the sense check here is if someone said to you …..give me $20 and I will give you back $40 would you be eager to take it even if you had something else you could do with that $20? Of course you would. The answer wouldn’t be as straight forward if they only offered you say $23 for your $20 investment though and that is why companies have moved their focus to the more liquids rich plays…better returns.

So from my view, any way you look at it the Eagle Ford shale has very attractive economics. The same can’t be said for some of the other shales that tend to be more gassy, remote, deep etc. An example would be Horn River shale in NE BC where you need somewhere between $4 and $5 / MCF to breakeven on a full cycle basis.

[sparky]

.
Thanks Rocdoc that was enlightening
one can suppose the costs should decrease as the tech mature further .
that would leave the quality of the field and taxes as variables

Your depletion number are very useful ,on can conceive a drilling front advancing
It's probably not so simple but there must be an optimum number of rigs in action
anything above would simply drain this resource faster for a decrease in local price

[Graeme]

Oh, but OK for you to criticize any threads I post on global warming, arctic or antarctic ice conditions. Double standard here methinks.

The Gas Bubble

Market bubbles come and go, but they all have things in common: a few people get rich, a lot of people get taken, and a mess is left for the taxpayers to clean up. To understand the hydro-fracking bubble, there are some things one must know: each well only produces a little gas (and exhausts relatively quickly), reserves were significantly overstated at the beginning of the game, and most important: Wall Street is very invested and wants its money out.

The process of fracturing rock to create a cavity in a thin layer of shale, deep under ground, to extract the gas trapped in cells there does not create a large pocket. So, only a small amount of gas is produced, and the well is exhausted quickly. Given the low volume of gas produced by a single well, sustained supply depends on the production of many, many wells, which means many leases must be signed with landowners. As the gas rush caught on, there was a big push by gas drillers to sign as many leases as possible, as these "reserves" increased the company's value, and thus its stock price. When those leases began to come due, they had to be exercised, or else they would expire, thus increasing the market glut.

In any resource extraction rush, the easily obtained reserves are the first to be taken, and as they dwindle, more difficult and expensive assets are pursued until such time as extraction cost plus profit exceeds market cost, at which point extraction ceases.


So let's add up all of these facts and draw a few conclusions:
-tremendously overstated supplies
-an overstatement upon which bankers make large investments
-increasingly expensive and difficult reserves remain for extraction
-commitments in place to sell gas overseas in markets with higher prices
-numerous domestic industries (especially electric utilities) implementing technologies to utilize the erroneously projected plentiful, cheap gas supplies
-coal powered electrical generation converted to natural gas to avoid the expense of adding pollution controls
-Wall Street wants its money back before the bubble bursts, so the pressure is on the gas companies to keep drilling wells and producing gas to pay the interest on the loans.

So where will that leave us, the average citizens in the USA?
The first thing that will affect all of us will be a tremendous spike in electricity prices in the next few years as US natural gas prices equalize with world market prices, which will have risen from current levels due to the voracious demand of Europe, Asia, the tar sands, and diminishing world supplies. More importantly, we will be faced with depleted and polluted groundwater, and tremendously degraded farmland here at home as we rushed to keep the bubble inflated.

huffingtonpost

[Plantagenet]

Rockdoc---Thanks for your posts on this topic.

I appreciate you sharing your knowledge with us here.

-------------------

I have a technical question---fracking creates a cylinder of fractures that allows production from the shale surrounding the the horizontal well. How far from the well bore do the fractures penetrate into the shale around the drill hole?

[ralfy]

Related:

http://shalebubble.org/

[Pops]

OK let's try this again, roc put in some time on his analysis and we don't get much of that. Tear it up but respect the topic; the economics of production

[PrestonSturges]

Rockdoc, you need to summarize your key points and the cite the sources up front for those of us with less free time.

[rockdoc123]

Rockdoc, you need to summarize your key points and the cite the sources up front for those of us with less free time.

thought I was being as succinct as could be given the amount of information needed to discuss. Not sure what you mean by sources, this is all my thoughts based on experience and having read myriads of annual reports, 10Ks meeting with WoodMac shale specialists etc.
If you want somewhere to go and look start with corporate presentations from the various shale players.

[careinke]

ROCDOC,

Thanks for your insight into this subject. I seem to remember you stating that EROEI was never a factor in making a decision about drilling a well (or field). How about Money Returned On Money Invested (MROMI)? I mean I could make a case that EROEI may not apply if the energy you invest costs much less than the energy you are extracting, but I don't see anyone paying more dollars so he can sell for less dollars.

I guess my point is, at some time in the future, (whenever that is), the remaining oil/shale/tar sands etc. will be just too expensive to extract. Of course we will already have sealed the fate of civilization by burning to much of the stuff in the first place.

[Quinny]

I think the point has already been made that loss making wells are continued for cash flow reasons.

It's not something peculiar to the oil industry but it is common in the capitalist system. Many loss making businesses are run for years losing money basically extracting cash from the original capital base,

I think it was the airline industry that had made massive losses from it's outset but leeched off investors.

Capitalism - LMFAO!

[rockdoc123]

Thanks for your insight into this subject. I seem to remember you stating that EROEI was never a factor in making a decision about drilling a well (or field). How about Money Returned On Money Invested (MROMI)? I mean I could make a case that EROEI may not apply if the energy you invest costs much less than the energy you are extracting, but I don't see anyone paying more dollars so he can sell for less dollars.

I guess my point is, at some time in the future, (whenever that is), the remaining oil/shale/tar sands etc. will be just too expensive to extract. Of course we will already have sealed the fate of civilization by burning to much of the stuff in the first place.

Yes the industry doesn't base decision on energy value but rather cost and profit. You money returned on money invested would be caught by several metrics that the industry uses...return on capital employed, rate of return and discounted profit to investment ratio.
I don't think any of this is in anyway denying peak oil, it is just delaying it and giving man some breathing room to come up with viable alternatives.