The old treadmill analogy

http://www.bloomberg.com/news/2014-04-30/shale-drillers-feast-on-junk-debt-to-say-on-treadmill.html#disqus_thread

There is this commonly used analogy that because A) shale wells have dramatically declining production compared to initial rates, and B) because many drillers have negative free cash flow that C) the whole thing is a scam and all these companies will eventually be bankrupt.  This is very simplistic and faulty reasoning, although I do agree that owning the high yield bonds of some of these smaller companies sure seems like a really bad idea at 5%.

The old "peak oil" website called theoildrum.com used to call "the treadmill" the "the red queen" 's race, from the Lewis Carrol story.  Drilling more and more wells just to maintain production.  It is true that a lot of the shale gas companies made uneconomic investments, but by and large this was for two reasons.  The first reason was that there was a race to get and hold acreage.  The second reason was that there were huge investments in gas when it was at $5-12 per mcfe, and then the price of gas crashed.  As the land grab phase recedes, I think the economics of the various plays will become more clear, and will continue to improve. 

Range Resources Conference Call

Range missed a bit on earnings and the stock was down 1% on a generally up day.   But every time I listen to this company I want to buy their stock.  They belong to an elite club amongst E&P companies.  They control the core and a huge contiguous acreage of a highly economic play.  There are probably two other companies that I can think of off hand that you could say this about, Cabot in the North East Marcellus, and EOG in the Eagleford.  These are premium companies with premium valuations though.

What it difficult for me is to buy a company like Range growing at 20-25%, with an EV/EBITDA of 20x on a trailing 12 month basis, or 12.5x on a 2014 bloomberg consensus EBITDA basis, and not buy Whiting at 6x trailing EBITDA or 5X current year estimate, and growing at 14% or so.   Range also outspent CFO by 32% last year, vs. Whiting outspend of 9% and Cabot flat.

One thing that Range has that Cabot does not have is a truly massive drilling inventory.  Cabot has plenty of inventory too, but Range's inventory is incredible.  In the core Marcellus of SW PA they probably have to spend about $45b of drilling capex to drill 9,000 wells (~60 acre spacing).  Then they may have that again to spend on their Utica and their Devonian acreage, then they have their dry Marcellus acreage.  Altogether, at $5mm per well, there might be $175B of capex that will have to be spent to drill their current leasehold.  Most of this acreage has a very high rate of return.

A few interesting comments from the call:

They talked extensively about a single "super rich" marcellus pad where they had had a well IP at a 24 hr rate of 6,350 BOED, of which over half was liquids.  This was an infill well on an pad with other 2 year old wells. It was drilled at 900 ft spacing.  They say that their newest wells are doing about 60% better on average than the 2 year old wells per 1000 ft of lateral length (old wells had shorter lateral lengths, new ones are set to average about 5300 ft this year).  The improvement is due to better frac design, more stages, more optimized proppant, and other technical changes.  This well cost $850k less than the earlier wells due to efficiencies from being on the same pad.

They continued to emphasize IRRs, and how they would improve for all sorts of different reasons.  They also emphasized that technical improvements had certainly not run their course, and that there were more improvements to come. 

There is also a dry Utica test coming off one of their SW Marcellus pads, which should be reported in the October call.  They made a half hearted attempt to talk down expectations, but then went on to say that the Utica rock looked as good as Marcellus, and that there was as much gas in place, and at a higher pressure.

Their enthusiasm was very palpable, as it always is.  Even if they did miss expectations a bit, its hard to imagine anyone sold any of the stock after listening to that call.


One other interesting bit- they are running one rig in their NE Marcellus acreage just to maintain production and hold acres.  I wonder if they are only maintaining because they can't get take-away allocation up there or if it is just that they see better returns in the SW, but need to drill to hold onto their acreage.

My biggest misgivings with respect to Range are: growing 20% is very impressive, but they are still running a massive cash flow deficit.  It seems like with 100% IRRs ("half cycle") you should be able to grow at 20% inside of cash flow.  Part of the reason for the deficit is that even this year they are spending $300mm out of $1.5b capex budget on land and seismic.  Why is this spending level necessary given the huge resource position already in hand?  Cabot claims similar IRRs, but is growing much faster and living inside cash flows.

I'm planning to do a Marcellus overview post soon as well.

Comparing productivity of different shale/tight oil regions using EIA drilling productivity reports

There are a variety of different ways of looking at the cost and productivity of the various shale regions.  This is an important topic, especially because I often read people saying that much of the shale gas or tight oil is not actually economic based on the fact that the companies are collectively free cash flow negative.  I’ve already expressed my reservations about the metric of free cash flow in the context of E&P companies, as it is conventionally measured.  (Go to cash flow statement, take cash from operations, subtract capital expenditures).  I argue that sold assets should be added back in, so really it is more useful to take cash from operations and subtract cash from investments in total.  If we do this, the 26 companies that are being studied here had cash from operations that exceeded investments by 9% in 2013, after running a deficit for the previous two years.  They also grew “value adjusted” production (take barrel of oil equivalent production and discount gas by 2/3 and ngls by ½) by about 7% last year.  All this implies that returns are improving.  I think that this is the case, and that there are a number of potential reasons for it.

Reasons returns may be improving for domestic E&Ps:

• 1)      Moving to pad drilling.  In the past most wells were drilled on single well pads to “hold by production” (HBP) all the lease areas.  More on this later, but the gist of it is that oil and gas leases force companies to drill within a certain time span or else they lose the lease.  After leasing up huge swaths of land, they had to go on a very inefficient campaign to drill a well in every 640 acre drilling unit to hold all that land.  Most companies are now moving more and more to drilling many wells on a single well pad, which is far more efficient.  Recent Chesepeake Energy presentations have discussed this quite a bit.
• 2)      More wells are being drilled for the purpose of making money rather than testing the boundaries of a play or searching for new plays.  This is similar to the first point, but you are starting to get some companies saying that the big unconventional plays have been found.  Whether or not this is true, it is clear that the companies are generally more focused on drilling profitable wells rather than finding more resources.  I believe this will lead to better returns.
• 3)      Better well results due to improved well design.  As companies spend more time in certain plays, they are able to learn better how to drill in those areas.  Last year changes in well design that Whiting made in the Bakken has led to wells flowing about 60% more oil over the period studied.
• 4)      A decrease in infrastructure development costs as plays mature. 
• 5)      A decrease in leasehold acquisition costs (it’s all been leased up).
• 6)      Better pricing as infrastructure is built out. 
• 7)      Many companies drilled uneconomic gas wells in the 2006-2009 period based on unrealistically high expectations of future gas prices.  We aren’t seeing this anymore.

     On the other hand, it is also worth noting that a few of the larger companies are milking foreign assets for cash flow while investing in the US, so if foreign assets were excluded there would be somewhat less of a cash flow surplus.  Apache’s Egyptian assets are a good example of this.  It’s been a free cash flow gusher for years now.  It’s also important to point out that these companies are all EXTREMELY levered to the price of oil.  Oil majors like Exxon and Chevron are much less levered to the price of oil because they also make money from refining, but more importantly, much of their production is in low cost overseas regions, where the profit margin is very high, although they only get a small slice of the profit.  A decrease of oil price in the USA by $20 per barrel would be devastating for many E&P companies in the long term, but it only would crimp profits a bit for the oil majors.  The converse of this is that if the price goes up by $20, it will be much more important for the E&Ps than for the majors.

     But of the various plays, which is the most efficient?  For gas, I think its very clear that the Marcellus has the best rock, and best IRRs at current prices, but it remains very limited by infrastructure, I’ll get more into the other gas plays later, but companies considering investing in the Barnett, Fayetteville, or Haynesville need to study the infrastructure plans surrounding the Marcellus.  The only thing holding  the price of gas up is that the area where it’s cheapest to produce is constrained from expanding by current infrastructure.

     For unconventional oil, where the vast majority of investment is currently going, there are three main plays that we will focus on and I’m going to look at two different ways to compare how productive these three regions are.  One way to compare is to look at the reports of the biggest unconventional oil producer, EOG, who is active in all three plays, but unfortunately they are no longer putting out internal rates of returns for the various plays.  They have said repeatedly that Eagleford has the best returns, Bakken next, and Permian is a distant third.  I will try to compare the rates of returns based on company claims, but the different companies use a variety of different IRR metrics in their presentations, usually with limited explanation of how they are calculated.  There are also presumably different methods for estimating revenue from the wells, and there is certainly the possibility of excessive optimism when companies create their investor presentations.

     Then there is a very interesting monthly report from EIA.gov (department of energy).  They come out with a monthly drilling productivity report for the Bakken, Permian, Eagleford, and Marcellus.

     This is a fascinating report.  Basically they say that there are 500 b/d of new production each month per rig.  If we take this times 180 rigs, we get about 90,000 b/d of new production, but then there are declines of 69,000 b/d (a rather astonishing 6.9%) on existing wells, yielding a net increase of 21,000 b/d.  At some point the rigs will only be able to maintain production, and no longer grow it, but it is not yet clear where that production peak will be, it is certainly not in sight yet.

     The eagleford is growing at a 50% faster rate and is already much higher in production than the Bakken, despite only getting going in 2010 vs 2008 or so in the Bakken.  But there are a number of other things to think of when comparing these two charts.  For one the Eagleford has 50% more rigs, so growing faster doesn’t seem as impressive.  Secondly, I think NGLs are being counted as “oil” here, where as in the Bakken it is only black oil.  Third, the eagleford is producing almost 7 bcf/d, which is 1,170 mboe per day.  So the Eagleford produces almost as much energy equivalent of gas as liquids, while Bakken produces negligible gas at 1 bcfd.  If we give the 2/3 haircut to get rough value equivalence, the Eagleford gas is worth another 390 mbbl/d of oil in value equivalence, meaning the Eagleford is already about 1.8 mmbbl/d in total, vs only 1.0mmbbl/d for Bakken despite bakken having maybe 40% more time to get there.  Learning from Bakken definitely carried over to Eagleford though, which probably helped it get a faster start.  Being so near the gulf coast also helped with infrastructure constraint issues compared to the Bakken.  There are so many puts and takes there, but my general sense is that Eagleford is more economic than Bakken by some modest margin.

   

     Now Permian is another animal altogether.

     Permian is growing at only 13 mbbl/d month over month vs 21 for bakken and 31 for eagleford.  This is despite the incredible 500 rigs working there.  Total oil production is about the same as the Eagleford currently (though not for long), and gas production is less at 5 bcfd.  I think it is clear that the Permian is less economic than either of the other two, but one thing should be mentioned.  Many of the rigs in the Permian are vertical rigs, which cost less to operate than a horizontal rig, so the per-rig new oil production rate of 100 bbl/d vs 500 bbl/d for eagleford and bakken isn’t quite as bad as it may at first seem.  Fracs are also smaller and fewer stages for these vertical wells, cutting pressure pumping costs for these companies.  But even so, the difference of 500 bbl/d of new oil per rig vs 100 bbl/d is pretty big.  All this begs the question, why are the Permian focused companies trading at such a premium to the Bakken names on either a daily production basis or an EV/EBITDA basis?  This is a question that I do not have an answer for.

Weekly Price Check

I'm going to start doing a week over week price check on the covered stocks and on the underlying commodities.  I haven't set up my automatic spread sheet yet so for now I'll only list the commodities:

I'm also going to have a weekly price on the recommended portfolio of E&P stocks, and compare those to the performance of the E&P index.  The rules for the game are that I have to be fully invested at all times, and can only switch between stocks on the list.  Then I'm going to compare it to a benchmark.  I'm going to start out with my actual E&P investments as the same as the portfolio.  For now, dividends will not be included in returns for the sake of simplicity.  The dividend yields tend to be quite small, but I would like to factor them in without making this too complicated.

I'll talk more about why I own these stocks later.  But just for a little background: I've held WLL for the better part of a year, APA for almost that long as well, and CHK was only bought a few months ago.  I also have owned Anadarko Petroleum (APC) for part of the last year, but unfortunately sold it and missed out on the nice move they had when they settled the Tronox claims.  WLL has had a great run for me, although the index in general has really moved over the past year but I bought more part way up, so I'm up 35% or so overall.  I can't necessarily say that I've had great stock selection, since APA has really underperformed, and APC did as well until right after I sold it.  The E&P index is 30% in the past year.

I had decided to use the ETF IEO as my benchmark.  It is a market cap weighted Domestic E&P index from ishares.  But then when I looked at the components, there are a few integrated companies and refiners in the mix.  Unfortunately I can't figure out how to get an automated feed of either commodity pricing or the Exploration and Production S&P sub index from yahoo finance, so I may just end up manually entering commodity pricing from EIA.gov and the E&P sub-index pricing from google finance each week.

Reflections on Cabot earnings call

The Marcellus has been the fastest growing gas producing region ever since the Haynesville production peaked in 2012.  The other two most significant shale gas regions, the Fayetteville and the Barnett, have both been flat for years now.  These regions aren't constrained by takeaway capacity, they are constrained by costs.

Just how productive is the Northern Marcellus?  From the period of 2011 through 2013, according to Cabot’s 10k filings, their cash flow for investments totaled $2.17b, and their cash flow from operations was $2.18b.  During this period they grew production from 514 mmcfd to 1,133 mmcfd (average 2013 daily production).  They never ran more than 6 rigs during this period.  This quarter they are averaging 1.48 bcfd of gross production (about 12.5% royalty is included in this).

A typical well has 4600 ft lateral length and will produce 17 bcf of gas based on their 2013 type curves.  That yields a 100% IRR for $3/mcf gas price or 200% IRR for $4/mcf gas pricing.  Another way to visuallize this is to consider that 17 bcf of gas at $4/mcf means $68mm of revenue net of royalties per well, on a per well capital cost of about $7mm.  At $.75 per mcf of opex, operating cost over the lifetime of the well would be about $12.75mm, indicating an operating profit of $48mm per well, truly an astonishing number.  The only reason the price of gas isn’t much lower is infrastructure constraints.  The Marcellus pricing is already priced 75 cents below nymex, a much bigger differential on a percentage basis than any of the oil regions.  Despite the relatively low gas prices, the dry gas northern Marcelus is the highest return region of all the unconventional resource plays.

They say they are going to get to 2 bcfd plus (gross?) by year end, but the key will be getting the space allocations in the pipes.  

The Marcellus production has increased from less than 2 bcfd to about 15 bcfd today.  In 2009, the entire US was producing 57 bcfd average, compared to 69 bcfd average for 2013.  That means the Marcellus growth was larger than the growth of the country overall, and the Marcellus offset production declines in other higher cost regions like the Gulf of Mexico offshore and the Louisiana Haynesville shale.

Appalacian gas has historically traded at a premium to henry hub, I presume because it was closer to the big end user markets in the North East.  Today it trades at a discount (see below).  Northern Marcellus trades at an even more substantial discount, since that is where the big production growth has been.

Screening for value part 2

Using the same methodology as described in the previous post, I’ve now included 9 diversified E&Ps, by which I mean companies that produce in a number of geographic areas, rather than a single area like the Permian or Marcellus.

By this metric the first thing that jumps out is that there is a definite trend here, and that the Bakken companies appear undervalued and the Permian companies appear overvalued.  Note that RRC and AR have valuations that are so high that they are off this chart.

And again using production trends instead of EBITDA trends, the Permian producers appear overvalued.  Some of the diversified companies are growing as fast or faster, with valuations at half that of the Permian pure play companies.  Why are the Permian companies valued so highly?  I certainly don’t have a ready answer for this question.  If these companies were very small, and still in the early land buying and infrastructure building stage it would make sense, but Pioneer (PXD) has a market capitalization of nearly $30b and Conch (CXO) is 14b.  Why should their valuations be so much higher than comparably sized companies with more geographic diversity?

Screening for Value in the Bakken, Permian, and Marcellus regions

In these initial charts, I'm only going to be looking at the companies that are substantially invested in a single region.  Comparing the valuation of the various companies can be very difficult because of wildly differing growth rates, and different investment philosophy.  It is very hard to compare a fast growing company to one that is growing more slowly.  It is also hard to compare one that is borrowing money to invest in growth versus a more conservative one that is financing growth entirely through operating cash flow.

In this chart I have taken the Enterprise value of the various companies (net debt plus  market cap) and divided by the bloomberg BEST estimate of 2014 EBITDA.  This EBITDA number is an average of sell-side analyst estimates for 2014 earnings.  I decided to use this instead of trailing EBITDA because of the rapid rate of growth for many of these companies, and also because the 2013 number reflect a much lower average price for gas, than what we are likely to see in 2014.  NGL and oil prices are not likely to move so much if current prices are any indicator.  Average sales price for gas was at least 20% lower in 2013 vs current spot price.  Then on the Y axis, I have put in expected EBITDA growth.  Now the growth rate for the Marcellus (gas) producers is going to be higher partly just because of the huge price increase for gas, as opposed to the actual rate of growth in production.

UP AND TO THE LEFT INDICATES LOWER AND MORE ATTRACTIVE VALUATION.   The thing that immediately jumps out from the chart above, is that the Bakken producers appear much more attractively valued than the Permian producers.  The Bakken companies at higher growth rates are valued substantially lower than their Permian peers.  Oasis (OAS) and Kodiak (KOG) are sort of outliers because they are financing massive capital investment with debt right now, so their growth rate is high and coming off a low base.  But even compared to the relatively large companies like Whiting and Continental Resources, the Permian valuations seem quite high.

Also a quick word about the Bloomberg analyst estimates.  These are estimates from the "sell side" equity analysts from places like JP Morgan, Bank of America, Goldman, Morgan Stanley, Deutsche Bank etc.  These analysts are much more likely to suggest buying a stock than selling it.  This may or may not be because banks with sell ratings have a hard time getting business from companies to issue debt or advise on a merger or whatever.  Because of this tendency, sell side earnings estimates tend to follow a certain pattern: they start out fairly high, then they are reduced as earnings approach, making it more likely that the company will "beat" earnings expectations.  Because the estimates for 2014 are a projection into the distant future, its very likely that they will eventually be reduced slightly to make it easier for the companies to beat.

This second chart is purely based on production, and does not rely on any analyst estimates.  Again note that the companies furthest up and to the left are the more attractively valued ones.  The metric "value adjusted production" is purely my invention.  Basically I am taking the daily production in barrels of oil equivalent, but giving a 66% haircut to the value of gas and a 50% haircut to the value of NGLs to reflect the lower market price for these things.  At current market prices this may be slightly over generous to the gas and NGL weighted companies, but I want the metric to be fairly simple, and not change it every time gas prices go up 5%.

In this chart again the Permian producers don't look attractively valued.  I may redo this chart without the outliers AR and KOG.  AR has basically bought it's recent growth through a big acquisition.  KOG outspent their cash flow by 400% in 2012 and 200% in 2013 and they are growing off a low base making it really difficult to compare them.

How NOT to compare the efficiency of the various companies- deceptive charts in E&P companies’ investor presentations

This is a good follow-up from the previous post.  Shown above is a highly deceptive chart found on a presentation slide from Ultra Petroleum.  The suggestion is that UPL is the most efficient E&P company.  In fact, this chart is basically just displaying the oil weighting of the various companies.  Unconventional oil is more expensive to produce than unconventional gas on a BOE basis.  Wet gas falls in the middle.  So you have the companies on the right side, Oasis, Kodiak, Marathon, Whiting, which are basically oil companies that produce only small amounts of gas.  Then you have the companies on the left side that are more or less gas producers.  The ones in the middle tend to have more of a mix of oil and gas or are more NGL heavy gas producers.  But because oil sells for more money than gas on a BOE basis, from a financial standpoint, many of the companies on the right side have returns on capital that are as good or  better than UPL.  Also, if you take a company like RRC’s dry gas production and compare it to UPL’s dry gas, UPL will no longer look so attractive.

Many E&P company presentations are riddled with slides like these.  Other common practices that are highly vulnerable to manipulation include comparing initial production rates from wells, comparing cash margin per BOE, comparing F&D costs.  Whenever there is a huge line of companies being compared on some oil and gas metric in a company presentation, it is typically a cherry-picked statistic totally removed from context and intended to deceive people into thinking that this particular company is a superior operator.  They are often are pulled from Wall Street sell-side research so that they seem more impartial, but then are removed from all context.

A cost comparison between tight oil and shale gas

Note that these are rough estimates compiled from company presentations.

These are based on reported drilling and completion costs, and estimated ultimate recoveries (EURs) per well, as reported by various companies.  There are a few things to note here.  Both the capex and the opex related to extracting unconventional oil are much higher than for unconventional gas.  Estimated total direct costs for the most economical oil regions (Eagleford, Bakken, emerging Niobrara region) are in the neighborhood of $40-$50 per barrel of oil equivalent.  Note that this excludes land costs, and perhaps some infrastructure costs- transport costs are included in opex so that handles some infrastructure costs, but it isn’t clear whether this just means cash transport costs, or includes company owned gathering networks.   Wet gas, for the same energy equivalent has direct costs of a little more than a third of this for the most productive regions of the Marcellus.  Dry gas costs are the lowest overall, with capex plus opex direct costs in the neighborhood of $1.25 per mcf or $7.50-$8 per barrel of oil equivalent (BOE).  This massive cost difference on an energy equivalent basis means that gas prices are likely to stay far below oil equivalence for far into the future.  It also means that there would be a huge economic advantage for the USA to shift to cheap gas and away from expensive oil as a transportation fuel.

The reason why there is so much more activity in the oil regions than the gas regions is two fold.  For one, the price of oil is much higher on an energy equivalent basis.  With Brent oil at $109.50 per barrel currently, there is plenty of money to be made in unconventional oil.  Gas at $4.74 is trading at about $26/ BOE.  So gas costs about 1/5 of oil to produce but also earns between ¼ to 1/5 of the price of oil when it is sold.  Gas has also plunged to as little as $2 per mcf or $12 per BOE at times in the recent past, while the oil price has remained quite stable.  Next is the infrastructure problem.  There are infrastructure issues with the oil regions, but they are relatively simple compared to the most economical gas region.  Two of the big three oil regions are in Texas, where pipelines exist and more can easily be built.  These two regions, the Eagleford and Permian, are conveniently close to the biggest oil importing region with the largest refining capacity of anywhere in the world, the US Gulf Coast.  Bakken has proved more problematic due to obstacles related to building intrastate pipelines (see Keystone XL), but this issue has largely been solved by moving oil via railcar, just like they did in the 1800s.  Gas is not so simple.  The problem is that there is limited domestic demand growth, and it is very hard to ship overseas.  Also, the area with the most production constraints, the Marcellus, is also the lowest cost producing region and the threat of more Marcellus production chills investment in other regions.  Even if you can make a return in basins like the Haynesville and Barnett, producers risk major price declines when Marcellus bottlenecks are alleviated, since costs are much lower there.  Besides natural gas pipeline capacity, there have also been limitations on ethane take-away capacity.  Ethane is either left in the gas stream, or used in plastic manufacture on the Gulf Coast.  There are limits to how much can be left in the gas stream, and the fluid is too volatile to be moved economically except by pipeline.  Some of the most economic wells were the wet-gas wells in southeastern PA, but these have so much ethane that drilling has been constrained until they could get pipelines to take the ethane to the gulf coast.  At times there has been so much excess ethane that the price went to $.01 per gallon at one point at the Conway hub.  So despite phenomenally low production costs, the Marcellus and nearby Utica shale production has been constrained by transport capacity issues.

Unconventional oil and gas and the hydrocarbon renaissance in the USA

The combination of high prices for oil and the combination of horizontal drilling with hydraulic fracturing have opened up huge quantities of hydrocarbon resource in the USA over the past decade or so.  It used to be that oil and gas could only be produced out of geological formations that had high porosity, high permeability, had a source for hydrocarbons below it, and had an impermeable trap layer above it to keep the hydrocarbons from moving to the surface, and had sufficient internal pressure to push the oil out of the formation and into the well-bore.  These oil reservoirs ranged from very tiny, to very huge, but all the big ones have likely been found in the USA.

Starting in the 1970s, the focus shifted from on-shore USA to offshore in the Gulf of Mexico, and Alaska.  But although Alaska provided a second lower peak in the early to mid 1980s, the trend in US oil production has been decisively downward since the early 1970s, as oil production failed to be replaced by new discoveries.

But then it was discovered that by using horizontal drilling and hydraulic fracturing, economic quantities of gas could be extracted from vast shale layers.  Drilling took off first in the Barnett shale around Ft. Worth, Texas.  It then took off in the Haynesville and Fayetteville shales of Louisiana and Arkansas.  It was discovered that the Marcellus shale in Appalachia  was perhaps the most economic shale region, although it lacked some of the infrastructure that the southern Mid-West enjoyed, delaying development.  The same techniques were applied to “tight gas” regions as well, like the Permian Basin of West Texas, and the Anadarko Basin of the Central Plains.  This new type of gas drilling came about at the same time that conventional gas production was declining, and import terminals for expensive liquefied natural gas were being built.  The high prices created something of a euphoria around the shale gas producers.  One of the most early shale gas companies, Chesapeake Energy, spiked from $10 per share in 2003 to $65 per share in 2007 before the gas price collapsed in the financial crisis.  

 Note that these projections are a bit silly.  Shale gas production will match demand, and if we were to start exporting LNG in significant quantities, or shift to gas as a transport fuel, production would increase.  Production increases will be constrained by demand, and not the other way around, since the resource size is truly massive.

Subsequent to this rush into shale gas it was discovered that similar techniques could be applied to the production of “tight oil”, sometimes incorrectly referred to as shale oil.  EOG (formerly “Enron Oil and Gas”) drilled a few good wells in the Sanish Field of North Dakota in 2006.  Offset operators like Whiting petroleum quickly expanded the play, then at some point, the vast scale of the play was understood and dozens of companies rushed in.  Similar techniques were also applied to the very mature Permian Basin region of West Texas, reversing the long decline of the region since the 1970s.  The Permian is really a different beast than the Bakken though, since most of its production is through vertical wells that are hydraulically fractured and completed in multiple zones.  Horizontal drilling is increasing there, but it is still a relatively small part of overall Permian production.   After discovering the Bakken, EOG also discovered the Eagleford shale of South Texas.  Technically Petrohawk may have drilled the first real Eagleford well in 2008, but EOG recognized the huge areal extent and aggressively leased up hundreds of thousands of the best acres.  These three regions make up by far the bulk of the onshore US crude oil production growth.

One cause of tremendous confusion is the fact that hydrocarbon production has typically been grouped into the simplistic catagories of oil and gas.  Much of the shale gas is “wet gas” where large quantities of natural gas liquids (NGLs) are also produced.  As a result of this you see may occasionally see statements suggesting that the USA has passed Russia and Saudi Arabia to be the number one oil producer.  This is certainly not the case.  The USA produced about 6.5 mmb/d of crude oil in 2013, compared to 9.8 mmbd for Saudi Arabia and 9.9 mmbd for Russia.  But the US produces a massive quantity of natural gas liquids like ethane, propane, and butane.  If these are included (which they shouldn't be, because they are far less valuable, and have less energy content) then the USA produces more “liquids” than any other country.  Because much of the shale gas production also includes large quantities of these liquids production has increased an incredible pace.  But at the moment there are limited things to do with these liquids, and they can be hard to transport, the prices for some, especially ethane, have been driven down.  Very roughly speaking, Ethane trades for about $.30 per gallon, propane .90, butane 1.20, vs crude oil at $2.50.

See that the growth in natural gas liquids has massively outpaced crude oil production growth in the US.  The "total oil production" includes ngls like ethane, propane, and butane, whereas crude oil production on the left does not.

Coverage universe

Initially I’m going to start with 25 companies broken down into four categories.  All of these 25 companies are all US domiciled and listed.  The groups are as follows:

Geographically diversified large caps (about $20b or larger market cap):

OXY, EOG, APA, APC, DVN, NBL, MRO, CHK, HES.

Permian Basin focused companies (about $5b or larger):

PXD, CXO, EGN, LPI, XEC

Bakken Focused:

CLR, WLL, KOG, OAS, NOG

Marcellus Focused:
RRC, SWN, COG, EQT, UPL, AR

I plan to add other companies later, most likely the larger Canadian E&Ps, and perhaps international, or smaller cap US.  The reason for dividing them up into groups is that it allows us to compare the companies in several different ways.  Does it seem that one particular company is undervalued vs its regional peers?  Does it seem that one entire region may be undervalued?  I’m going to start by going into the three areas where there are a number of pure-play companies.  These regions are the Bakken play in North Dakota, which just surpassed 1 million barrels per day of oil production;  The Permian Basin of West Texas is a massive area that has produced conventional oil for decades, and now is the target of more capital expenditure than any other region in the US if not the world; the third is the Marcellus/Utica region, which has the lowest cost natural gas production, for a resource of its size, of any area of the continental US.  There are certainly other significant regions: the Eagleford is the fastest growing play with the largest production of tight-oil.  The Barnett and Haynesville plays are also significant shale gas regions.  There just aren’t enough companies that are purely focused on these areas to have a group of publicly traded peers that can be compared.

Capital Efficiency

Assessing capital efficiency, along with valuation, is really the second pillar to E&P investing in my opinion.  This may be an unusual concept to investors more familiar with less capital intensive industries.  For instance, when deciding whether to buy Coke or Pepsi, metrics like Return on Capital Employed (ROCE).  The bottom line and the ability to grow the bottom line, are the two key factors for companies in less capital intensive industries, and in many industries these have little relation to the capital efficiency metrics of the company.

With oil companies there is no brand to speak of, and no consumers deciding which type they like best.  What differentiates a successful company vs. an unsuccessful one is their ability to allocate capital in a way that will provide a favorable financial return in the future.  For less capital intensive industries growth in it of itself is usually evidence of good performance, unless the company is buying that growth through acquisitions.  In the E&P business a company that is growing may be paying for that growth by over-investing, and so higher growth is not necessarily evidence of good management.  Because earnings growth is not a reliable metric, we must have other ways to asses management

For very large companies, like the major oil companies, it is difficult to assess the profitability of individual aspects of the business.  The most common measures are ROE and ROCE.  The metric of ROCE is very commonly used, and I believe this was made popular by Exxon in the 1980s or 1990s.  It is calculated by dividing EBIT (operating income) by the total assets minus current liabilities.  A few years ago I was interested in whether the valuation premium of Exxon vs the other oil majors was justified.  Using the Bloomberg “total return” function, which assumes you reinvest dividends in shares, but neglects the effects of taxes, I compared the total compounded annual return of Exxon, Shell, and Chevron since 1990.   Interestingly they were all in the range of 12%.  This was despite the fact that Exxon traded at a significant valuation premium over nearly that entire period.  This indicated that over time, the market was correct in the higher valuation of Exxon vs. the other companies.  The reason for this effect was that Exxon was reliably more efficient with their capital, and earned a better return.  Of course the market was undervaluing oil companies in general in 1990 (which was explicable given the years of low oil prices); the S&P returned a compounded 7.5% over that same period.  Also note that production and refining throughput generally stagnated through this period. The moral of this story is that one company can be trading at 9x earnings, and another can be trading at 12x, and even if both are not growing at all, these relative valuations may be entirely justified.  The less efficient company may have to retain more of the earnings to maintain production, while the more efficient company is free to distribute a higher percentage of earnings through share buybacks and dividends, thus compensating for the higher valuation.

Image from XOM March '14 investor presentation

Valuation Metrics

I wanted to initially discuss a few of the valuation metrics that can be used to compare Exploration and Production companies.  I'm sure my views will evolve over time, but this is my thinking going into this project:

EV/EBITDA- Or total enterprise value divided by Earnings Before Interest Taxes Depreciation and Amortization is probably the most useful and most general valuation marker.  This metric accounts allows the comparison of two companies with very different levels of debt, and different production mix, on a fairly apples to apples basis.  Certainly companies with different growth profiles and different capital efficiency may deserve very different EV/EBITDA valuations, but it is still a very useful metric.

EV/P1 reserves-  This or an adjusted version of this where gas reserves are discounted by perhaps 66%, and natural gas liquids are discounted by 50% versus oil may be useful.  There are a number of issues that we should be aware of with this metric though.  One big problem is the large differences between proved-developed-producing (PDP) reserves and undeveloped (PUD) reserves.  Because of the more capital intensive nature of shale gas and tight oil production, the difference between developed (ie with wells producing oil) and undeveloped (ie they have proved that the oil is there to the satisfaction of auditors, but have yet to drill the wells to take it out) is much more significant than in decades past, where the main difficulty lay in finding the oil rather than extracting it.

Another problem with reserve based metrics is that reserves today may be more vulnerable to being reclassified now than in years past.   When the price of gas went down undeveloped reserves were dramatically revised by companies like Exco and others in higher cost areas like the Haynesville Shale.  The SEC requires that companies intend to bring undeveloped reserves onto production within five years, and do so at a profit, otherwise they cannot count them as proved  (P1) reserves.  Similar revisions would happen in the tight oil plays like the Bakken, Eagleford, or Permian if the price of oil were to decline dramatically.  

The classification of oil sands as proved reserves, starting in 2010 under SEC rules, also makes this metric a bit more complicated.  As with tight oil, the  main cost is associated with extraction and processing, not with locating the oil.  If the price of oil went down significantly, the oil sands would no longer be reserves.  Even if the price didn't go down, a barrel of oil sands in the ground is worth tremendously less than a barrel of oil in a proved-developed-producing conventional reservoir, in terms of the financial benefit it will provide to the company that owns it.

EV/daily production- This is another resource based metric that has some similar problems to the EV/P1 reserves metric, although it doesn't have the problems associated with developed vs undeveloped reserves.  I also would recommend adjusting this to discount lower value NGLs and gas versus oil.

NAV- or "net asset value". This is a method favored by many sell-side analysts.  It basically is a free cash flow model.  The problem is that the moving pieces in an E&P company are so incredibly complex that it is fairly hopeless to create a model like this that provides any sort of reasonable prediction of the future.  Take a company operating in the Bakken and imagine all the scenarios that could drastically alter the future potential of the company.  Well designs could change and favorably improve well cost or recovery (as it has over the past year or so).  The Bakken discount could change dramatically (as it has repeatedly).  Service costs could dramatically change.  The price of Brent or WTI could go up or down.  Free cash flow models have always been notoriously inaccurate because a slight change in the discount rate and "terminal growth rate" of the company used in the model can cause a huge change to the valuation.  A large part of the value is based on factors that are nearly impossible to predict.  The only time when the FCF model can be quite accurate is in periods of high interest rate, where the value of earnings in the distant future is so heavily discounted that it has limited impact on the valuation.  This is not the case at present, with our very low rates, and the uncertainties inherent in FCF models are magnified for an E&P company, making the methodology not very useful.  I don't have access to the sell-side models, and in general will not be attempting to create NAV models myself.

I intend to concentrate on comparing one company to another, and not trying to decide whether E&P companies are a good value vs the rest of the market, which is in many ways a more difficult question.

The shift to shale

My interest in the industry was initially due to the dynamic shift that came about around the time of the financial crisis.  Although the shift had been underway for some years at that time, especially in gas, I had not been aware of it.  The companies that led the way into shale gas, like Southwestern, Chesapeake, Devon, XTO, were not familiar names to me. The shift into unconventional oil and gas production has been almost entirely driven by smaller independent companies, with the larger companies like Exxon, Shell, and Statoil buying their way in later on through acquisitions.  Today, the vast majority of E&P capital spent in the USA is on tight oil and shale gas (though much less on gas at the moment).  Only $30b of an incredible $300b of capital spent on US E&P will be spent by the major oil companies (now considered to be Shell, Exxon, Chevron, BP, ConocoPhillips).  Note that E&P spending globally, ex US and Canada, is projected to be $524b.





Oil and Gas Journal- http://www.ogj.com/articles/print/volume-112/issue-3/special-report-capital-spending-outlook/e-amp-p-capital-spending-to-rebound-in-north-america.html

The shift to unconventional is of momentous consequence that can hardly be overstated.  The ability to find hydrocarbons, once the key for a good E&P company, is no longer of paramount importance.  The Eagleford formation is about 25,000 square miles.  Everyone can find the resource, the key is to be able to extract it at a profit.  Finding the resource does indeed still have some advantages- EOG did terrifically well with their first mover advantage in the Eagleford, as did Southwestern in the Fayetteville shale.  The company that finds the resource can often have a huge advantage in securing the leases, but in many cases the followers do just as well.  EOG was the first to drill successful unconventional Bakken wells, and Chesapeake the first to drill Marcellus wells (I think) but there are other companies that were able to do just as well, or better, in these regions from a financial standpoint.

Going into this project, my prejudiced view is that the companies that have thrived, have generally been those with a keen focus on financial returns on a per-well basis.  Southwestern and EOG had long published IRRs on a per well basis, and this seemed to be a major focus, judging by their conference calls and investor presentations.  EOG has done better than Southwestern, but this is more due to their strategic move of focusing purely on unconventional oil whereas Southwestern has continued to focus on dry-gas production despite the low prices.  Other companies have focused on land acquisition or production growth with more marginal economics.

The question of the day is: how can we value the E&P companies?  The most common metric for the stock market in general, the PE ratio, is generally inappropriate for a number of reasons.  The most obvious reason for this is that accounting earnings are largely divorced from the true economics of an E&P company because of the huge amounts of capitalized expense and depreciation.  In the past there were several common metrics such as a multiple of cash flow, a value per barrel of reserves, or a value based on daily production.  These were always a very approximate way of valuing a company, but they have become even more problematic with the shift into shale.   The buy-side analysts have used the NAV (net asset value) methodology, which may be an interesting exercise, but at the end of the day it is extremely subjective, because of the discount factors and uncertainties applied throughout.  I suspect that in many cases the NAVs are adjusted to the market capitalization, whether consciously or unconsciously.  In other words, if the enterprise value (net debt plus market capitalization) is $10b, you can be sure that the analysts NAV won't come out to be $4b or $25b.

Intro

The purpose of this blog is to track investments and provide commentary on equity investments in  the exploration and production sector of the oil and gas industry.  The blog will mainly be for my own benefit, although I hope to have several friends doing similar blogs for other sectors.  The eventual idea would be to be able to lean on others for stock picks in various sectors that they specialize in.  Perhaps we could also have a central blog designed to track performance over time.

Before publishing a list of stock picks, I initially intend to do a series of several posts that are more general in nature.  Are the US E&P companies allocating capital efficiently?  What is the best way to value these companies?  Which regions are likely to provide the best returns?  These are not answers that I have at the ready, and I will basically be working through them as I post.


NYtimes.com


-FM