Permian Overview 1

 

The Permian Basin is one of the oldest continuous producing oil regions in the USA.  The first hydrocarbons in commercial quantities were discovered in 1925, about two decades after the first east Texas oil boom.  Drilling and production increased in the 1930s, through 1960s.  After this point some of the easier conventional fields were in decline, and despite increased drilling in the late 1970s and early 1980s due to high prices, the Permian was in decline.  According to the Texas Railroad Commission, there are currently 133,000 producing wells in the Permian Basin, a staggering number, and about 11% of all active producing US wells.  The landscape picture above is from photographer Spencer Lowell in the New Yorker.  Almost all of these wells have been drilled vertically and at tight spacing.  Unlike horizontals, where many wells can be drilled from one pad, vertical wells must be spaced apart, leading to a huge surface footprint in areas of the Permian Basin.

 In this image from a Pioneer presentation we can see the historic decline from peak production in the early 1970s.  This coincides closely with the total US peak in conventional oil production around the same time. This decline started to reverse itself in the middle part of the last decade.

From a 2012 Concho Resources company presentation, we can see the total rig count fell dramatically in the mid 1980s when the bottom fell out of the price of oil.  It stayed around 100 before dropping further in the early 2000s, then as the price of oil increased, and new techniques were developed and applied, the rig count has increased in recent years, and production declines have been reversed.  Note that some of the bump in rig count may have also been directed towards gas targets (I'm not really sure), since that is when we started seeing the huge boom in gas-directed rig count prior to the collapse of gas prices in 2008.

  The above chart also illustrates the lack of elasticity of supply for oil production.  As the price dropped dramatically the rig count dropped, but production declined at a slow 3% per year.  One aspect of horizontal drilling in tight formations is that most of the production comes in the first few years.  This may lead to higher elasticity of supply in the future, since production can ramp up or decline much faster in response to the price of oil than it could historically.

This image, from a Devon Energy presentation from 2012, shows the main drilling targets in the Permian region.  Unlike other areas like the Bakken, Marcellus, or Eagleford, drilling in the Permian targets a wide variety of different layers.  Also unlike those regions, where horizontal wells are elusively drilled, most of the wells being drilled in the Permian are vertical wells.  It should be noted that because the horizontal wells are much more expensive to drill, although there are fewer wells, they represent a very large share of the total capital spend and new production.

Here’s another visualization as of early 2012 from Comstock resources.  This shows drilling permits.  As we can see, most of the vertical activity was in the Midland Basin, with much of that in the Wolfberry region.  There was some horizontal drilling in the lower portion of the Midland basin, which was most likely in the Wolfcamp.  Meanwhile in the Delaware basin, there was lots of wolfcamp, Avalon, and bone-springs formation horizontal drilling, and little vertical drilling.  Note that there is also a significant level of vertical drilling activity in the Central Basin Platform between the Midland and Delaware Basins.

This slide from Laredo shows the different Midland Basin Targets.  The Wolfberry vertical wells have multiple targets in different producing zones and are normally hydraulically fractured for stimulation, like the horizontal wells.  Nearly 200 of the active rigs in the Permian were considered to be targeting Wolfberry according to IHS as of 2012.

There is much less concern about take-away capacity in The Permian compared to The Bakken or Marcellus.  There are a number of reasons for this.  Even if the Permain production were to double in the next 5 to 10 years, the only new pipelines would be intrastate Texas pipelines, which can be approved and built quickly.  Also, the absolute distance to the huge Gulf Coast refining and chemical regions is  relatively short.

In part two I'll look at the major companies in the Permian and what they are up to.

What's going on in the Permian?

The rig count in the Permian is and continues to be massive.  But unlike the Bakken or Eagleford, most of the rigs have been vertical rigs.  These are less expensive to operate, so it has always been a bit tough to compare overall levels of activity between the basins.  

But recently there has been a huge increase in the number of horizontal rigs drilling there.   According to EIA reports, these are mostly being directed towards Bone Springs, Wolfcamp, and the Midland Basin Spraberry field.  I had been aware that the rig count there had been generally inching up, but I had been oblivious to the fact that such a high percentage of them were horizontal rigs.  This indicates a huge uptick in capital spend in the basin.  Increases in spend may be a leading indicator that returns are improving there, and indeed we have also heard bits of this in the recent earnings reports.  Rig count increases have not always been an indicator of highly economic drilling returns, as is evidenced by the rush into the Haynesville shale of 5 years ago or so.  But in the case of the Permian, the land is generally all leased up, so there is no land rush aspect to this, and overall companies are acting more conservatively with capital than they were at the height of the shale gas boom. 

The valuation of the Permian companies is a bit of a puzzle to me as I've said before.  Why should they be valued at such a premium when their returns on capital seem to be below Bakken, Eagleford, or Marcellus operators? I do have significant exposure to the Permian by owning Apache, but this is at a very low valuation compared to the Permian Pure play companies.  If I have time this week I'm going to start looking at this region more closely and doing some overview posts.

weekly prices

I get all this data off an excel spreadsheet that queries yahoo finance (I really wish I had access to a Bloomberg), and I forgot to save last week’s.  Hopefully there are no transcription errors here.  I wish I had a better index to use.  Neither of those two ETFs I use are ideal, and Yahoo doesn’t seem to have all the S&P subindexes.  I can find some but not others.  Ideally I would be using the S&P 500, energy, E&P sub-sub index.

Overall it was a strong week for the market, and for most of the diversified E&Ps.  People generally assume that the price of oil is likely to fall somewhat, or at least that it shouldn’t go higher.  This is reflected in the futures market.

I know this chart is barely readable; it was a photo taken of a Bloomberg screen at the free Bloomberg terminals in the NY Business library.  The white line is a WTI futures curve from four years ago, the blue from three, then the red from two, the light green from two, and finally the pinkish white (the one that starts at the highest point) from last week.  What each of these lines represents is the futures contract at intervals going 10 years into the future.  The key observation here is that in each passing year the expectation of future prices far in the future has decreased.  So even though the spot price now is higher than in the past four  years (on that specific date) the future price for five years out has gone down each time.  There have been a lot of issues with WTI because of the oversupply in the midcontinent (WTI is priced in Cushing Oklahoma), but the same basic trend also exists for Brent crude, the more relevant global benchmark now.

Overall for the week, the diversified larger E&Ps did well, along with the Bakken names.  Permian companies were generally flattish and the Marcellus companies were down with natural gas.

Apache overview part 2

An individual investment in the upstream petroleum industry is inherently a risky venture.  Millions are laid out to drill a well, or buy a lease or a producing property, and it always a possibility that all that money will be lost.  A very large company with a sound risk management and investment policy can spread this risk out over so many projects and so many individual wells, so as to mitigate risk, just like a large book keeper might lose money here and there, but given adequate scale, the business isn’t overly risky.

Apache is a very large company, producing about 800 mboed (oil+gas+gas liquids, thousand barrel of oil equivalent per day on an energy equivalent basis.)  For a sense of scale, this is about 20% of Exxon’s production.  But as large as they are, there have been huge investments that they have made that have gone badly, and others that have done well.  Because of the thorough reporting in their 10k filings, it is possible to determine which are which.  In this second part of my look at Apache, I’m going to go through the various operating regions and look at what has done well and what has not.

Although Apache may seem like a very  mature company compared to many of their North American peers, it was fairly small, and almost totally producing oil from on-shore North America at the start of the 1990s.  They started to expand into some early overseas ventures and the US Gulf of Mexico in the 1990s, before going on a rather aggressive overseas expansion in the 2000s.  Most recently they have shifted back to a US onshore focus, although so far this recent period has been notable for lackluster financial performance and growth.  Apache breaks down their production into regions as shown below in their May 2014 investor presentation:

Note that the figures from this chart are lower than the figures in the chart above because of the exclusion of Egypt “tax barrels”, non-controlling interest and so on.  In general, oil production in US companies is reported net of any royalties paid to landowners, but not net of any production taxes.  For foreign production sharing contracts, only the company’s share of production is reported.  As I understand it, if there is a special tax on oil production (as is the case in Egypt) it can be a bit more complicated to report it so as to be consistent and comparable with other companies.

North Sea- good or bad investment?

Apache entered the North Sea by purchasing the Forties field from BP in 2003 for $821mm.  This is widely regarded as a good investment.     9/21/11 -Apache agrees  to purchase North Sea assets from Exxon for $1.75b including the Beryl Field.  Production is 19,000 b/d of oil and 58mmcfd of gas.  68mmboe P1 reserves, $25.74 per P1 boe.  For our purposes here, I’ve only gone back to 2005 for all the regions, but if we went back to the start of their North Sea excursion then it would include a lot of negative FCF for 2003 when the purchase was made.  

This chart, as well as the others below, was built from their 10k filings.  The operating income (EBIT) and depreciation were both from Apache, the other numbers were derived and should be considered approximate.  The key takeaway from this chart is the bottom line.  The bottom line is an approximation for free cash flow for the region, by taking EBITDA and subtracting capex.   They don’t report operating cash flow by region so this is the best we can do.  Sometimes the FCF number does not match up with EBITDA-Capex and this is because I have added back in asset sales for the region.  I tried to get most of the asset sales, although I’m sure I have missed some of the smaller ones.  Overall these charts should be used as an approximation to get a sense of the economic performance of each region.

As you can see from the chart, Apache has spent about $560mm more than they have received in the North Sea in the period from 2005 through 2013.  Overall, it’s hard to say whether the North Sea has been a great investment because of the huge outlay in 2011 for the Exxon assets and drilling capex.  In a few years we should have a better picture of how this region is panning out for Apache.

Argentina- A bad but not disastrous investment

Because they just announced the sale of all their Argentina assets to YPF for $852mm on March 12, 2014, we can tell pretty conclusively how they did here.   Apache entered the region in 2006, buying Pioneer’s producing properties for $675mm, and Pan American’s 7 concessions for $396mm.  Including those purchases they spent about $936mm more than they earned in Argentina in 2005 through 2013, before recouping most of that in the final sale in 2014.  So including the sale they lost about $84mm but they also had about $1b in capital tied up earning nothing through that period.

Australia- poor returns so far

Apache has huge gas fields in Australia, but some of them are in stranded locations waiting on the completion of LNG projects to export the gas.  They also have a stake in the huge and badly overbudget Wheatstone LNG project (13%).  Its hard to get a sense of this region because the delays from Wheatstone LNG have really hurt.  Not only do they not get the cash from their stake in Wheatstone, they don’t have anywhere to sell a lot of their gas.  So although this region has not been good, it is difficult to write the book on this one just yet.  Wheatstone is due to start in 2016, and “first phase” was originally going to cost $30B, though it will probably go way over budget.  

Canada- Similar to Australia, waiting for LNG projects on the Canadian west coast

Canada looked OK as an investment until they purchased billions of dollars of BP assets in the fire sale that followed the horizon disaster.  These assets were in Western Canada, and are mostly gas.  When the LNG plants are built there, they will be in prime position to export, but as it stands now, they’ve spent a huge chunk of cash and are not seeing good returns.  Kitmat construction is just starting up, and first production may be a ways off yet.

Egypt: Apache’s cash flow gusher

When Egypt is mentioned in the same breath as Apache, it is usually to discuss the risk of having asset in a very unstable country like Egypt.  I certainly think this is a huge risk.  Its is not at all hard to imagine Egypt devolving into civil war, and the government massacring Islamism rebels Assad style, or otherwise doing something to get put on the US sanctions list.  This is probably a big reason why they elected to sell 1/3 of their Egypt business to Sinopec last year for $2.95 B.  Management may also be hesitant to talk about it because if they go around crowing about what a great deal they’ve got there, it might be lead to a public backlash in Egypt.

Lets look at two charts side by side:

Now this is gross, much of which goes to the Government.  But the point is that they’ve been able to grow and grow production there.

Now look at free cash flow.  They’ve been able to generate almost $12b in free cash flow here (including the $2.95 from the Chinese included in the 2013 number) while simultaneously growing production consistently.  This is a remarkable investment.  It is a home run.  It is only a slight exaggeration to say that Apache, as a company, basically is in the business of taking free cash flow generated in Egypt and spending it on various and marginally unprofitable enterprises around the world.  And Egypt is only about 13% of pro-forma production (after netting out production taxes).

And finally the USA- a big money pit, but with reasons for optimism

Since 2010 Apache has shifted focus back onto the continental US.  They have focused their attention on the midcontinent region in the Texas panhandle and Oklahoma and in the Permian Basin in West Texas.  More recently they have also been active in the Eagleford.

They had also been acquiring Gulf of Mexico (GOM below) assets, but most recently have sold nearly everything but some shallow-water properties.

To get a sense of how  unfocused Apache's strategy has been in the US, look at the churn in assets below.  Apache had bought up Gulf of Mexico assets from BP, Devon, and Mariner, only to sell it all four to eight years later.  Because operating income is not broke out by region within the USA it is hard for met to tell how good of an investment these were, but based on their overall numbers for the US, I suspect they weren't great investments.

March 2014- Apache agrees to sell Lucious and Heidelberg  Deepwater GOM stake to FCX for $1.4b

5/8/13-  Fieildwood  Energy buys Apache GOM shelf asssets for  3.75b

5/1/12- Apache  announces the acquisition of Cordillera Energy, anadarko basin  PE backed company for $2.85b

11/10/2010- Apache completes Mariner acquisition.  Deepwater and shelf GOM assets plus permian basin assets.  $2.7b not including assumption of $1.7b debt.

7/26/2010- Apache buys BP permian basin assets for $2.5b

6/9/2010- Apache buys Shelf GOM assets from Devon for $1.05b

1/18/2007- Apache buys $1.0b of permian assets from Anadarko.

June 2006- Apache buys  GOM outer continental shelf properties from BP for $845mm.

1/5/2006- Apache buys Amarada Hess's Permian acreage for $239mm.   Seems like a good deal for  27mmboe of liquids and  27BCF  P1 reserves.

So although production has certainly been going up in the US, they have basically been buying that growth.  Cumulatively they have spent about $10b or so more in the USA then they have generated.   Neither the midcon/Anadarko Basin, nor the Permian have proved to be especially economic for the industry, generally speaking.  So what are the reasons for optimism?  I believe that E&Ps that have had the best and most consistent financial returns are those with a significant position in a major play.  They have an informational advantage over the small guys, have better access to services and take-away capacity.   Apache most certainly has this status in those two regions.  Secondly, well performance and drilling efficiency have been consistently improving for years now across all major plays, including in the Permian recently.  Finally, Apache had a disadvantage vis-à-vis certain other E&Ps in that they were not adept at the land game.  There is no doubt that the best financial performance was achieved by the companies that went in and bought land directly rather than buying packages or acquiring other companies.  Whiting or EOG leased land in the Bakken from land owners.  Apache bought their way into the Permian and midcontinent through huge, and relatively expensive acquisitions.  But going forward I think that Apache can now focus on operational improvements, rather than having to do more big acquisitions.  Even if their financial performance in the USA is just less of a drag than it had been that should be very positive for the company.

Summary:

Apache’s recent capital efficiency has been generally bad or mediocre in all regions except Egypt.  But modest improvements in their massive US operations seem imminent, and both Australia and Canada should eventually start to generate cash in 2016-2017 as LNG projects start to come online.  Argentina is sold, and won’t be a drag going forward.  The North Sea could go either way.  Overall this is an OK company with OK management, but with some possible tailwinds and a terrifically low valuation at about 4x EBITDA, +/- a bit depending on which number you are using.   And this is why I have a small position in them.  The main positive development that I’m watching for is if the drilling economics in the Permian Basin were to start to show significant improvement.  If this were to happen I would load up on Apache stock, because they could go on a big run.  The major negative risks are Egyptian sanctions/civil war/expropriations, further LNG delays in Australia/Canada, and (of course, as always) declines in the price of oil.

Apache part one

I’m going to go over a profile of one of the largest E&P companies by production, if not by market capitalization.  I own this company because of its very low valuation, not because of their great execution.  As I’ve said before, I have a temperamental predisposition to invest in companies with low valuations.  Their execution has been marginal at best over the past few years, especially considering the large opportunity set before them.

Apache describes themselves:

“Over the years our strategy for achieving profitable growth has evolved. Over the most recent decade Apache has been an active acquirer of properties, following up each one with proactive exploitation operations, including workovers, re-completions, and drilling, to increase production and reserves, as well as efforts to reduce costs per unit produced and enhance profitability.”- 2005 10k filing

Apache has been a significant independent company since long before the shale boom days.  They would acquire elderly fields and invest in stimulating further production.

At any given time, oil companies must be either producing free cash flow and return capital to shareholders, or growing production.  Doing both at once is preferred, but rare.  If they can’t do at least one of these, then something is going very wrong.   Apache has tended to err on the side of growth, with minimal FCF although they are currently upping their share buyback program, an uncommon strategy among E&Ps currently.  Until the past few years they have managed to grow production buy an impressive 12% CAGR.  Unfortunately this streak has pretty much ended in the three years since 2011.

 I’ve heard people say (and Apache themselves say) that they are good at taking on the mature fields that the oil majors turn away from.  I do think that this is partly true.  I also think it was partly a difference in philosophy between them and the oil majors.  Because the oil companies had tended to grossly underestimate the long term price of oil, which steadily rose throughout the past two decades, they tended to err on the side of returning capital rather than growing production.  In other words if Shell would only invest on a project that met whatever their threshold internal rate of return, which was based on a too-low estimate for the price of oil, they would tend to divest mature properties, when in retrospect it would have been better to invest in them.

The oil majors would also tend to underestimate their cost for new projects, especially the larger and more technically complex ones.  By way of example, look at the Shell gas-to-liquids plant in Qatar begun in 2003.  This plant takes gas and converts it to liquid petroleum using the Fischer-Tropsch process, the same way Nazi Germany produced gasoline from coal during WW2.  The cost was originally supposed to be $5b, and the original cost model suggested it would be sufficiently profitable at $40 long term oil price.  Well the cost turned out to be $24b when it was all said and done, but they were partly saved by the fact that Brent has now been trading above $100 for years.   This is an egregious example but it is representative of a wider trend for projects by the oil majors.  They go way over budget, but luckily the price of oil turned out to stay higher than was originally projected, salvaging the economics of the projects.  But if oil companies had spent that cash on less glamorous projects like stimulating mature oil fields to coax out a few extra barrels (Apache’s strategy) they would have tended achieve better returns than the complex mega projects that have reliably run behind schedule and over budget.

So I’m not really sure if Apache’s long term success has been due to their unique expertise, or because they were able to gobble up small assets that the oil majors shed because they incorrectly assumed the price of oil would be lower than it turned out to be over the longer term.

 An example that Apache likes to tout as their strength is Permian Basin field they bought from Amoco (now BP) in 1991.  The production curve from the time of purchase is shown below.  They bought a field in decline, and made it decline less fast.

But this chart doesn’t show the extra capex that they invested to achieve this.  Was their technical ability the source of this success, or was it simply their more optimistic (and correct) view of the long term price of oil?  It is a difficult question, but it is the type of question that makes investing in this sector so interesting.

More recently, Apache has stalled.  They have produced basically no free cash flow over the past few years, but this is typical of E&Ps right now in this time of production growth.  Unfortunately, Apache has managed to spend all their cash flow while growing production by only ~3% annually since 2011.  This is an unimpressive record considering the very high price of oil during this period.  In the next installment I’ll talk a bit more about why they’ve done poorly recently and why I own them.

Weekly price updates

Dead flat week for the S&P.  Brent and WTI were both up about $2 per barrel, and natural gas was off $.10.  E&P equities were generally off with gas levered names fairing worst.  For E&P companies overall, oil being up 2% is much more important than gas being down 2% in my view, because oil comprises a much larger share of E&P revenues over all.  I’m surprised that the sector under-performed so much with oil trading well.  Chesapeake Energy was off BIG, partly due to gas price, but mostly due to their poorly received spin off of their drilling services division into a separately listed company.  A couple of the mid-cap Permian companies were also off, but I'm not sure why.

Chesapeake spins off drilling services division, very poorly received by the market

Investors had been expecting that the drilling services division would be sold for approximately $4b with the proceeds available for use in reducing leverage.  Instead CHK will get $400mm in a dividend, and the new service company to be called 77 Energy, will take on $1.1b of debt from CHK.  So instead of being able to pay off $4b in debt, they will only be able to pay down $1.5b.  Their debt rating was raised two notches to BB+ at S&P.

I'm not entirely sure why this was so poorly received.  Perhaps people may speculate that they couldn't get a good price for it.  I was surprised that about half of Chesapeake's 11,000 employees will go with the new company.

Also in an unrelated bit of news, CHK won a court decision last week against bondholders related to wether they could call certain bonds that had an unconventional and disputed indenture.  The benefit to CHK would be a bit over $100mm.

OT- CF Industries (nitrate fertilizer producer)

This is a big position of mine, and I thought I'd just talk about why I own this company since it is basically a short US natural gas play.  CF Industries is a large nitrogen fertilizer producer and distributor with operations in the USA.  They take convert atmospheric nitrogen to nitrate fertilizers like ammonia, urea, and ammonium nitrate, with the major inputs being natural gas and energy.


1) USA is a nitrogen fertilizer importer, but we now have among the lowest cost production in the world due to low gas prices.  The only lower cost suppliers are in areas like the Middle East, which has a cost disadvantage from a transport standpoint.

2) I believe that the USA will have sustainable low natural gas prices and will eventually be a nitrate fertilizer exporter.

3) US producers have a major transport advantage vs. importers due to proximity to the US and Canadian customers.  We used to be a marginal producer at the top end of the cost curve due to high and volatile gas pricing.  The shale gas revolution changed this.

4) Even though I believe that natural gas prices will stay low, I think that US gas producers can indeed make money at very low gas prices, which is why I am long certain gas producers like Chesapeake Energy and Apache, and am considering investment even in dry gas only companies like Cabot or Southwest Energy.  CF acts as a hedge for these positions in case the gas price falls dramatically.

5) The valuation of CF is attractive.  They have bought back 20mm shares (vs 52mm outsanding) in the past four years with modest debt issuance, while paying a 1% dividend and investing in a 25% capacity expansion coming online in 2015 and 2016.  I think we are in close to trough earnings over the next few years due to current strong gas prices and near floor level ammonia pricing in the quarter.  Even in these conditions they still earned $4.50 per share, implying a 13.9x PE ratio at $250 per share.

I remain a believer in low gas prices for the long term, but my faith is not limitless.  I must admit that the skyrocketing gas prices this winter gave me pause with this position!  I did sell a bit at $225 or so this winter, vs $248 current price, which I regret.  Fortunately I bought between $180 and $200 last year.

will the new EPA coal rules be implemented?

For those not paying attention, EPA has slowly been regulating the hell out of coal.  Initially it was mostly regulations related to polutants, causing coal companies to upgrade plants with "scrubbers" and other very high cost technology to treat the exhaust and remove sulfer, particulates and other type of polution.  This has caused smaller and older plants to shut down.  This combined with the glut of gas has caused very hard times indeed for the coal industry.  The reason they pick on coal is that it is by far the dirtiest source of electricity in terms of pollutants (ie things that hurt you, not CO2), and it is also the biggest CO2 emitter per unit of energy generated.  Coal is very long chain hydrocarbon, so it has about 2 hydrogen per carbon atom.  Methane, aka natural gas, has 4 hydrogen per carbon atom.  Liquid fuels like gasoline and diesel fall in between these two.  Combined cycle natural gas power plants also have higher thermal efficiency than steam generators used in coal fired plants.  Combined cycle plants have a gas turbine pared with a steam turbine to capture heat from the gas after it has passed through the gas turbine.  A gas turbine can have a thermal efficiency of up to about 42%, and a steam turbine can reach about 31% for a combined cycle efficiency of of about 60% in modern gas fired power stations.


So yesterday this article caught my attention

http://thehill.com/regulation/energy-environment/205902-obama-coal-rules-will-devastate-say-biz-groups

I had heard about the attempts by EPA to regulate CO2 but I didn't look at the details, because I had heard that it only applied to new-build plants.  And no one builds new coal plants anyway.  The article implies that it is for coal plants more generally.  I'm not sure if this is just an effort to drum up right wing histeria or if there actually is a broader rule being proposed.  I still only see the proposed rule applying to new plants:

from september 2013 EPA:
http://yosemite.epa.gov/opa/admpress.nsf/0/da9640577ceacd9f85257beb006cb2b6!OpenDocument

 1,100 lb of carbon per MWH would basically ban any new coal plant that doesn't have carbon capture and sequestration (which none do currently).  That number was clearly selected because modern gas can reach that limit.  Coal can't come anywhere close.  The best coal plants burning the cleanest coal still generate about 2x that amount of CO2 per MWH.  Here's a link from EIA with their estimates:

http://www.eia.gov/tools/faqs/faq.cfm?id=74&t=11


 What will be interesting is that if the EPA is able to set this precedent of regulating CO2, then in the future they could set a more stringent rule that would also apply to coal plants more generally.

EIA may drilling productivity report is out

Highlights from the EIA drilling productivity report released yesterday

4 key highlights:

1. 1      Drilling efficiency is still improving in all plays across the board.
2. 2     Eagleford oil production growth is still the highest, but it is decelerating
3. 3      Permian oil production growth accelerated in the last month significantly.
4. 4     Gas production in the Haynesville went from declining two months ago, to up slightly last month, to slight increases last month and this.

Bakken growth pretty much held steady at 22mbbl/d (vs 21 last month).  Eagleford rate of growth slowed a bit at 27mbbl/d vs 31 last month.  Niobrara region continued growing at its modes 4 mbbl/d rate vs 5 last month.  I’m wondering when we’ll see some more growth there.  There is a ton of talk from APC, WLL, EOG, SWN about new productive fields in the region.

Permian oil production growth accelerated from 13mbbl/d growth month over month in the April report, to 21mbbl/d in this report.  It would be interesting to home in on where the growth is coming from within the region.  Although we are seeing some modest gains in drilling efficiency, the pick up may also be due to the increasing rig count there.  They have now eclipsed the multi-decade high set in 2012, and they are approaching 550 active rigs in the Permian basin.  Just to give a sense of scale, there are about 690 active rigs in all of Europe, Latin America, and Africa according to Baker Hughes.

The growth in Haynesville is the most interesting to me.  Two months ago it was declining, and last month and this it has reversed to modest growth.  CHK had mentioned that they were increasing rigs there.  Drilling efficiency had been flattish since mid 2011 using the EIA metrics, but now appears to be increasing again.  Between increases in drilling efficiency and the higher gas prices, the economics in this play have certainly improved.  Rig count is creeping up towards 50, far below the peaks of 250 set a few years ago.

Overall, there is no doubt that drilling the Haynesville is far less capital efficient than Marcellus.  Using the EIA new gas production per active rig, Marcellus is at about 6.5 mmcfd of new production per rig vs 5.0 mmcfd in Haynesville, but this does not fully capture the difference in economics , since many of the Marcellus wells are producing significant liquids and Marcellus wells are much cheaper.  It’s not clear whether NGLs are counted in this gas production figure, but even if they are, they are worth more per BTU, so the value of an mcf of Marcellus production would be worth more than a mcf of Haynesville production, which is dry-gas only.  Also I believe that Haynesville wells are significantly more expensive because the formation is at 10,000-13,000 ft depth compared to Marcellus depth of between 4,000 and 8,000 ft.  Between all these factors, Marcellus has far superior economics.  But Haynesville has something that Marcellus does not, ample take-away capacity and lower transport differentials.

weekly price updates

Brent-WTI gap closed a bit, so overall mixed weak for oil prices.  Gas prices dropped, although it came after the weekly inventory report I think, so I’m not completely sure about why that was.  The portfolio was up a bit on the strength of good results from Chesapeake and Apache, and outperformed the S&P and E&P indexes.

Bakken news:

Whiting down this week.  There’s been a lot of talk about the rail cars used to carry bakken crude, and the DOT announced voluntary efforts to have companies start using higher spec rail cars due to the number of accidents we’ve been seeing.  There may be some worry that issues with rail born crude my cause a bakken bottleneck at some point.  Bad results from KOG may also have weighed on the sector.  

KOG was downgraded by suntrust to neutral on Monday, after being downgraded by Wunderlich last Friday on weak guidance.  Production for Q1 came in at 34mboed, down 6% QOQ!  This is incredibly bad even with the weather.  There was a bit of good news: they were having great results from downspacing tests.

CLR also missed on Thursday and the stock dropped.  They reported average net volumes of 148,400 boed, a 25% YOY increase for the quarter.  Lots of talk about changing up completions and downspacing tests. 

Oasis beat on Tuesday, coming in at 62 cents per share, implying 19x earnings on an annualized basis.

Overall trends: good results from the large cap companies, some positive results in the Permian as well, boosting stocks in these areas.  Tough results from KOG in the Bakken, and bad news flow made for a rough week there.  Marcellus names were down presumably because gas had a bad week. 

I haven’t had a chance to get through all the large cap earnings calls (and I won’t) but every one I’ve looked at beat.  One other large cap diversified companies is SWN, down 5% on the week due to gas prices.  They beat on Tuesday with operating cash flow of $617mm for the quarter easily exceeding $542 of capex, while growing production 23% YOY.  Earnings of $.66 per share implies a PE of 17x.  If we step back, I think all can agree this is an incredible result, with gas prices that most still consider to be too low.  They have been outspending cash flow for years now, and are turning free cash flow positive now.

Chesapeake had a good quarter but I was surprised at the degree of the positive reaction by the street.

Apache earnings- and another large cap beats

(note this is one of three E&Ps I own, along with Whiting and Chesapeake)

$1.78 vs 1.62 estimates, but shares stayed pretty flat on a down day for the sector.  Bought back $500mm in stock in the quarter (very rare for an E&P right now).  Revenues and production were down YOY but that is due to asset sales of mostly gas assets in Canada for $374mm and all of Argentina for $850mm. 

Why do I own them?  I’m a sucker for low valuations, and they trade at the lowest for an independent E&P.  They have a huge portfolio of mid continent and Permian basin assets, although I’m not convinced that these assets have great economics overall.  Their 150 mboed of Permian production is only just shy of Pioneer’s production, and Pioneer is the largest Permian pure play valued at $30b.  Apache’s EV is just over $40b, and the Permian is less than 25% of their production!   Also, people give them a discount because they have so much riding on Egypt.  But Egypt is an absolute cash flow gusher.  I’m going to do a post on this later, but this is absolutely the best part of the whole company from a financial returns perspective.

Apache basically milks their incredible Egypt assets, and to a lesser extent their North Sea assets, to grow their far less impressive on-shore US production in the Permian where they run 38 rigs and Anadarko/Midcontinent, where they run 28 rigs.   One analyst asked a question that implied that the midcon assets were showing lower returns than the Permian, and if they might shift capital away from the Midcon.  The way they answered the question implied that they agreed with this. They’ve been selling Canadian assets, they just sold all their Argentina acreage, and then they just sold their non-op interest in two GOM projects for $1.4.  They’re clearly looking to sell down their Australian investment in the Wheatstone LNG, and seem to be well along in discussions for this.  They are also looking to sell down the Kitmat LNG project in British Colombia.  Apache is also one of these companies that has tremendous overseas cash, with no way to bring it home without tax consequences.

Although they only have a bit of Eagleford acreage it is interesting to note that they mentioned realocating capital to the Eagleford from the Permian and raising eagleford rig count to 8 from 4.  This is another affirmation that Eagleford returns are significantly better than Permian returns in general.  They are in the condensate window of the Eagleford.

Montney and Duvernay- they've drilled two wells each.  Usually drilling takes off in the winter in Canada because much of it is impassible due to mud later on.  They haven't announced results here but they did mention that they are "stellar" and this could be something to use all the international cash on.

On the Gulf Coast, it sounds like they are basically going for GOM shallow shelf drilling, and selling down deepwater. They say much of the shelf hasn't been explored at deeper layers.  They probably won't be drilling much though until 2015, since there's a lot of technical work to do first.

GOM Transaction- For $1.4b FCX got 55mboed of 3p reserves (an odd metric to report). They bought Apache interest in the Lucious (11.7%) and Heidleberg (12.5%) projects in the GOM deepwater, along with 11 exploration blocks of relatively marginal value.  This gives FCX a total of 35% interest in Lucious.  Anadarko operates with 35% interest, Exxon holds 15%, Petrobras 9.6 and Eni 5.4%.  Heidelberg is also operated by Anadarko (35.5%), with minority partners  Marubeni, Eni, Statoil, Exxon, Cobalt, and now FCX.

It’s interesting that FCX selling onshore operated assets, and buying offshore non-operated assets.  Clearly their focus has been in the Deepwater Gulf with the PXP acquisition right after they bought all the BP assets, and the MMR acquisition at the same time (announced at the end of 2012).  $25/3p barrel all non-producing, doesn’t really seem like a great deal, but maybe they see further upside, or front-loaded production or something.

Following up on the FCX/Encana transaction in the Eagleford

Reminder that this was a $3.2b deal for Encana to buy 45,000 eagleford acres producing 53mboed average in Q1 from FCX.

This transaction looked like a great deal for Encana at first look, and it still looks good as I look more closely.  This is highly contiguous acreage in the prime part of the oil window of the eagleford.  The operating cash flow for the quarter was $327mm vs purchase price of $3,200mm.  This valuation seems very cheap.  It seems to me that you could just let the existing wells produce out, and still get a reasonable return on your $3.2b without drilling another well, even with steep decline curves.

What is the the undrilled acreage worth? Well past transactions have been as high as $25,000/ acre.  You could argue that this acreage should be worth even more, given recent improvements to well results and downspacing prospects.  They say using 50 acre spacing there are 355 producing wells, and 400 undrilled locations.  In any event, this implies that 25,000 of the 45,000 are undrilled acres, so the value for the undrilled acres is $625mm at a minimum.

Even on that basis it looks like a fine transaction, but there is a strong likelyhood that the acres will eventually drilled at 20 acre spacing, implying that there are in fact about 1400 or so undrilled locations there, which would make this a terrific deal.

The only metric it doesn't look great on is 1P barrels.  With 59mmboe of 1P barrels in the ground, implying $54 per 1P barrel.  But clearly there should be a lot of additional recoverable barrels not counted in this metric.

Encana is a pretty big Canadian based company, but with lots of US operations.  I've never followed them too closesly, but it always seemed to me that they were spread out into every play that had marginal economics.  They're in lots of gas plays, but not THE only gas play that has top tier economics.  They are in lots of oil plays, like the Tuskaloosa shale, the Duvernay (canada), the Motney (canada), the San Juan.  None of these have really proved to have outstanding economics.  This does look like a promissing turn for them.

Chesapeake, another beat and raise by a large independent + a brief history

CHK came in at $.59 per share, vs analyst expectation of .48.    Adjusted EBITDA was up 34% yoy, and most amazingly capex at only $850mm was far below cash flow from operations of $1.29b.    Production was more or less flat though they tout that it was up 11% excluding divestitures.   Just a few years ago these guys were spending $14b a year in capex! 

I own some Chesapeake shares because I believe they can turn around and make money through drilling rather than as a real-estate speculator, their previous business model.  I also know how much the investment community hates this company  because of past misdeeds (mainly associated with their former CEO).

I’m going to do additional posts on Chesapeake that go into more detail, but by way of an introduction… they were founded by Aubrey McClendon, a landman.  He was an early adopter of the horizontal drilling and hydraulic fracturing and participated in the early Barnett shale rush around Ft. Worth Texas, the first significant US shale gas play.  Mitchell Energy is credited with making the discovery, and he sold out to Devon Energy in 2002.  Other early players included Chesapeake, XTO, EOG, Range Resources, and Encana. 

Chesapeake early on realized that there were other large plays out there, and set out to lease up huge swaths of territory.  They would send out a small army of landmen to sign leases with all the individual landowners.  In many cases the landsmen would be working for private companies, and may not even know they were working with Chesapeake.  At some points (according to rumor) they employed as many as 10,000 landmen at a given time, mostly indirectly.  Step two was to announce a position in a new play and trump up some well results.  Step three was to sell a share in that interest to a larger company like Statoil, CNOOC, or Total.  Ideally they could fully cover exploration and leasing costs by selling that fractional interest in the play to the other company.  Much of the money was usually in the form of a drilling carry, which means that the other company pays your share of the capex for new wells until that carry runs out.  Chesapeake liked this arrangement because usually the first wells were the least efficient and most expensive, partly because they had to drill lots of lone wells to hold all the leased land by production. 

An oil or gas lease typically involves two types of payment, a bonus and a royalty.  The bonus is a flat fee per acre paid to the landowner.   $1,000 per acre wouldn’t be unusual.  Then the landowner also gets a royalty, which is a negotiated percentage of revenue from the well.  12.5% is sort of the baseline, but 15 or 17% isn’t unusual.  Production that an oil company reports on their financial statements is net of that royalty in the USA (but not Canada).  Terms are usually a closely guarded secret.  After securing the lease and paying the bonus, a company has to start producing from the land within a certain window (2 years in some areas, as much as 5 in others) or they lose the lease.  In some cases the company has the option to repay the bonus to start the timer again.  Once they start producing and paying royalty, the lease is considered “held by production” or HBP.  In most cases the land is “unitized” so that all the land in a square mile is considered one unit.  The landowners from that unit will share revenue equally according to the percentage of land owned by each individual, regardless of whose land the well is actually under.  So under that arrangement, if a company had leased up exactly 100 square miles of contiguous acreage, they would have to drill at least 100 producing wells over that area to hold all the land by production.

Now this is much less efficient than “pad drilling” where a single plot of land has a number of wells on it, each going out in a different direction underground.  Say a company decided to use 60 acre spacing.  A unit has 640 acres.  In some cases 10 wells might be drilled all right next to each other on one plot of land, but underground they are spaced out so as to drain the whole unit.  This is much more efficient because only one well site is prepared, and all the roads and gas gathering infrastructure can be shared easily between wells.  So when a company first leases land, it must drill inefficiently: a well here, then a well over there etc because they have to HBP the land.  But much later it is doing “infill drilling” or “pad drilling” which is more cost efficient.

Chesapeake never really got to infill drilling until recently.  They would lease up huge swaths, sell to a major, and use the cash to drill and hold land, or go and find more land.  The scale of the operation was rather incredible.  In some years they spent $6b and more leasing up land.  They also were running a fleet of 180+ land rigs at times, or 1/10^th of all US land rigs, and a much higher percentage of all horizontal drilling rigs.  The only thing that went wrong was that gas prices crashed in 2008 and is only now showing signs of recovering.  They’ve belatedly followed EOG's lead to diversify into unconventional oil drilling, and they've sold one thing after another during the past few years, to try to pay back some of their $12.5b in long term debt.  Now that they are trying to act like a normal company that makes money by drilling for oil and gas, I do think they’ll ultimately be successful at turning the corner, especially given the recent rise in gas prices.

Freeport McMorran divesting Eagleford oil assets

Freeport McMoran FCX bought Plains Exploration for $16b in May of 2013, along with McMoran Exploration for another $3.4b.  Freeport had been a mining company until then, though it owned a minority stake in McMoran Exploration.  The founder and former CEO of FCX, James Moffet, had moved on to become the CEO of McMoran Exploration, and continued to be a major shareholder in FCX.  So this whole transaction smacked of self dealing.  When the deal was announced in late 2012, the stock dropped from about $39 to $32 and continued to drift downward until after the deal closed, hitting a low of $27.30 in early July of 2013.  I bought some in the $28-29 range and am still holding.  It's in a taxable account and I'll probably wait until a year is up before I sell it.

The constituent components of Plains Exploration, were Eagleford Oil assets, California on-shore oil assets, Haynesville Louisiana gas assets, and Gulf of Mexico offshore oil prospects.  At the time of the transaction they had just bought $5.5b in offshore deepwater GOM assets from Shell and BP as BP shed assets after the Horizon disaster.  McMorran Exploration held GOM assets.  FCX seems most interested in the offshore projects.

Today FCX announced the sale of Eagleford assets to Encana for $3.1b. It's producing 53mboed of oil and gas and 45,000 net acres.  Production appears to be almost 90% oil. That's $58,000 per flowing barrel, though it may be pretty fast-declining.  This seems like a bit of a low price   On a company-wide basis, the lowest any E&P is trading on a production basis is in the $80-85k per flowing barrel range (discounting gas production by 2/3 and NGLs by 1/2).  On a per barrel of reserves basis the price looks more attractive with $54/ 1P barrel, or $46/2P barrel.   But I doubt this is the best metric to look at, since if we know anything about the Eagleford, those reserves will likely increase as they drill more and down-space.  Encana shares are up 4.5% right now on the deal.

US shipping pure ethane to Canada by pipeline for the first time in 25 years

http://www.eia.gov/todayinenergy/detail.cfm?id=16151

I find ethane to be a fascinating part of the energy mix that no one ever pays attention to because it is not something that we ever deal with in our everyday lives.  Ethane, is C2H6, the lightest of the "natural gas liquids".  It is produced mainly in "wet gas" wells.  Wet gas production has gone up tremendously because of the huge quantities of resource produced in some areas like the Southwestern Pennsylvania Marcellus.  Although crude oil has higher values at around $100/bbl, mixed NGLs can be worth $50/bbl or so (it depends heavily on pricing and the ratio of the various constituents) and wet gas wells may produce far more total resource on an energy-equivalent basis, than the best unconventional crude oil wells.  The main problem that arises is what to do with the NGLs.  Black-oil wells tend to produce oil and gas.  Oil collects in tanks until it is trucked away.  Gas goes into a "gathering network" of pipelines which take it to a processing plant.  But NGLs have to go through fractionation plants, which separate out the components, which then have to be shipped to various places.  Ethane can only be shipped by pipeline, while propane and butane are also more difficult to ship than crude.  A problem that has arisen for the E&P companies: what do they do with all the NGLs?


Well they found something to do with the propane (C3H8).  Imports have all but ceased, and exports have gone way up.  They are also using more of it as a feedstock for chemical production.

http://www.eia.gov/todayinenergy/detail.cfm?id=15951

I find statistics on propane production to be incredibly confusing.  Some sources are reporting propane from wells only.  Some are also including propane produced as a biproduct of oil refining.  EIA reports "propane + propylene" production.  A lot (if not most) propylene is not produced from propane, so I don't really have any idea why a stat would be reported this way.

Ethane oversupply is a much tougher problem, because it is difficult to export, and there are more limited opportunities for substitution to replace oil.  It is extremely volatile and has a very low density.  Ethane is used for exactly two purposes.  It is left in the gas supply for its heat value or it is "cracked" to make ethylene, a building block for many chemicals and plastics.  The majority of common plastics, like ABS, PVC, PE, PETE use ethylene as a feedstock.  Ethylene can also be made from naptha, a biproduct of oil refining, or from Propane.   But when NGL production went way up, all the Ethylene producers in the USA that could switched to ethane cracking.  Since then there has also been a substantial increase in propane cracking for a number of reasons, but its a bit complicated to get into that.

At some points in the past few years the oversupply of ethane was dramatic; prices hit $.01 per gallon at the Conway hub at one point.  Meanwhile basic chemical producers have made money hand over fist.  Observe the stock prices of Lyondell Bassell and Westlake Chemical over the past few years.  They produce a global commodities, with a regional input that is in massive oversupply.

But now there are starting to be exports going to Nova Chemical in Canada, owned by Abu Dhabi.  Starting next year there is also a project to export Marcellus ethane by sea out of the east coast called the Mariner East project.  There has been much speculation about where this will go.  Most of the european etheylene capacity really can't take Ethane because it is inland and/or because their crackers aren't really set up for light feedstocks.  It may just end up being blended with gas, since US ethane competes very well with LNG imports into Europe, and may be much cheaper to transport as scale increases.  It will be interesting to see how it plays out.

If seaborn ethane exports work out it would be very good for Range Resources and other eastern ethane producers.  There is only so much ethane that can be "rejected" and left in the gas system.  This limit is sometimes called the "blend wall".  Capacity constraints, either from lack of capacity to separate the constituent liquids out of the gas stream ("fractionation capacity") or lack of takeaway pipelines for either gas or NGLs has been a constant issue in many plays, but the Marcellus particularly, since it is so big and so far from the infrastructure hub on the Gulf Coast where all the chemical plants are.

Anadarko earnings, another beat from a large-cap independent

This stock is up about 25% in the last month.  It started going up only days after I sold my modest position I'm sorry to say.  The reason I sold it, is that I really hadn't kept up with them, and I already had positions in WLL, CHK, and APA which I felt more comfortable with.

Anadarko is a premier offshore explorer, operating 10 offshore deepwater drillships at the moment and going up to 12 this summer.  This puts them in the same neighborhood as much larger integrated companies like Shell, Exxon, BP, Chevron.  Only Petrobras has substantially more deepwater rigs going.  10 of these rigs will be operating in the US Gulf of Mexico.  Anadarko has had a string of drilling successes over the last decade.  Besides discoveries in the Gulf of Mexico, they have discovered West African offshore fields, and most notably a huge offshore gas deposit in offshore Mozambique, East Africa.  This area will ultimately be a very significant LNG exporter.  As they always do, after proving up their discovery, they immediately started selling down their interest to monetize their position.


Litigation: They had a minority interest in the Deepwater Horizon well operated by BP, and had to settle their liabilities for $4b in 2011.  Then they've had an outstanding liability from environmental damage caused by the now-defunct subsidiary of Kerr McGee, Tronox.  Kerr McGee was acquired some years ago, and it turned out that they had done tremendous environmental damage at their subsidiary.  The recent stock price spike was investors favorable reaction to a $4.15b settlement of this liability.

Besides their deepwater activities, they are heavily investing in four US onshore plays, Watenberg (Colorado), Eagleford, Delaware Basin Permian, and the dry North Eastern Marcellus.  They also have about a $10b equity stake in WGP, a publicly traded midstream MLP.  If you net that out, they are certainly looking more attractive.

My sense is that they are a very good operator, growing production at 7% or so YOY while generating substantial free cash flow (if you don't count their $8b + of legal settlements).   I have mixed feelings here on the value after the recent pop.

EOG earnings- impressive production growth while generating cash

EOG earnings- another blow out quarter.  This company has long had a premium valuation, yet it goes up and up.  Every time I listen to a conference call I want to buy the stock, but then I look at the valuation and the price action and I feel like I'd be chasing.  I'm considering finally buying some though.

They are the biggest unconventional oil producer in the USA, mainly on the back of their huge position in the oil window of the Eagleford play.  They grew US oil production by 45% yoy for Q1, and increased full year oil growth guidance to 29%.  They beat on earnings as well, and came in with $2.268b of cash flow from operations vs. $1.824b of cash used for investments (mostly drilling capex).  It is remarkable that a company of this size can be growing at this speed while throwing off cash like they are.  ROE and ROCE lead the peer group and increase every year.  I've always had a problem with their very large enterprise value, now at over $57b.  Their EV/EBITDA is on the high side, but at maybe 8x trailing or 6x current year, it isn't really that high.

What does the market not understand about this stock?  Everyone knows that they are a premier operator.  I think what the market may not understand is how good the economics can get in these plays.  Every quarter we hear about cost reductions, increased drilling speed, downspacing (more wells per drilling unit), better completion techniques, higher EUR (estimated ultimate recovery) per well.  Their Eagleford acreage, where most of their capex goes, will be fully held by production by the end of the year, and after that they will only be concentrated on economics in this massive play.  Production in the Eagleford will grow for them for the next decade, while throwing off cash from this point on.

I'm slowly talking myself into buying some...

The other interesting thing was that they announced for the first time that they have 4 relatively smaller new plays in the DJ Basin and Powder River Basin (eastern Colorado and Wyoming).  This region has long been the next big thing, but now companies are actually announcing high IRRs.  Rather than huge contiguous plays it seems to be more separated into smaller sweet-spots.  But the amount of capex going here has certainly been increasing, and Anadarko, Noble, Whiting, and now EOG are all touting 1st tier 100%+ IRRs.  This region is likely to be the next big thing for unconventional oil, after Bakken, EOG, and Permian, but it's not yet clear that it has the potential to be anywhere near comparable in total size.

EOG also announced that they considered their Leonard Shale play to be a first tier play, competitive for capital with the other 1st tier areas and second only to Eagleford and Bakken.  They are still running a very modest program in the Delaware-Permian basin.

Last thing- they say they'd consider going back to dry gas drilling if the price stayed above $5.50 for a while.  They think the price should go up, but there is a lot of gas acreage out there and they are worried that other companies will overdrill again, so they have no plan to get back to drilling dry gas in the near future.

From the Energy Information Agency (EIA) this week:

 

US commercial Crude stocks closed at their highest level ever this week.  This figure does not include products like gasoline, diesel etc.  It also does not include the strategic petroleum reserve, which holds about 600 million barrels as well.  I don’t know enough about inventory levels to really comment on this too meaningfully, and clearly from the chart above, stocks have been hanging out at or above its all time high for the preceding two years or so.

Natural gas storage is now in the beginning of the build phase for the year.  Stocks are built in the summer and depleted in the winter.  We’re at the lowest storage level in five years, due mainly to the very cold winter.  Storage levels are remarkably low when considering the record levels of gas production in the US currently.  US gas storage inventories affect gas price much more than reported oil inventories affect oil price, because oil is easily transported internationally.  US only uses about 1/5^th of crude oil that is produced, and there is no detailed storage information about the other 4/5ths.  Gas on the other hand must be used on this continent, so an EIA gas storage report can dramatically affect gas prices.

 

Also out from EIA this week.  East coast refineries ran nearly half domestic crude oil in January.   It seems that Bakken Crude, which is substantially moved by rail, is now going to the coasts.  There’s already a lot of Eagleford Crude to feed the Gulf Coast refineries (the largest concentration of refining capacity in the world), and the GC needs to run heavier and sour crudes because it has very complex refineries.  If they’re running light sweet crude in very complex refineries then you are not taking full advantage of the asset.  This is one reason why so much Mexican Mayan blend, and Venezuelan heavy crudes go to the Gulf Coast.  It is also the reason why Canadian oil sands oil ends up in the Gulf, whether by rail car or by pipeline.  It is also the reason that we still import lots of Saudi crude, even though there are other producing countries like Nigeria or Angola that are closer by.   Nigeria and Angola produce lighter crudes that tend to end up in Europe.  The tight oil from Bakken and Eagleford tends to be exceptionally light and sweet crude, which is ideal for the simpler East and West Coast refineries.  If current increases in light sweet crude production continue in the US, it would be curious to see if we ever reached the point where were importing heavy crudes from Mexico and Canada and exporting light sweet crudes to be refined elsewhere.

Although crude by rail costs is a higher cost method of transport than pipelines on a per-barrel basis, it has the great advantage that it can travel to where prices are highest.  This allows flexibility in an era of big geographic price differentials.   EIA calculates that 400 mbbl/d were from crude by rail in PADD 1 (US East Coast) this past January.  This is over 80% of the domestic sourced crude refined in the region.

 

 

Market was up and oil prices were down on strong US inventory numbers and possible Libyan production coming back online.  Natural gas was up.  Equities in the sector were fairly uncorrelated, though gas heavy names and especially Marcellus producers seemed to fair best.  Our energy portfolio underperformed pretty badly for the week.  I do have to do some more work on individual companies here, since stock analysis is the main point of this blog, but I'm trying to catch myself back up on what's going on a macro level as I get this blog started.

 

 

 -FM