keep the bullish inventory data released today in perspective

Today the EIA data release showed 1.3 million barrel build vs 4 million barrel expected build, hence the crude rally today.  Now normally crude inventories peak in may, decline through September, then build again through December.  So we are approaching a seasonal peak right now (see chart below).

This is the third bullish indication we have had in the US in the past week.

1) US Oil Rig count decline of 40 last friday (from baker hughs) represents another downward acceleration after two weeks of very small declines of 10 and 11.

2) Drilling productivity report from EIA earlier this week predicts declines in production in Bakken and Eagleford starting last month.

3) Inventory build rate slowed this week, according to today's EIA release, possibly suggesting a peak.


EIA data is now predicting production declines for this month and the incredible inventory build rate may finally be slowing, and inventories may even be peaking.  We remain a large importer of crude and the timing of those imports, as well as the timing of refinery maintenance has a large effect on inventories, so it will take several weeks to see if we are truly done with the build.  We may indeed be at a turning point both in that production is peaking and that our historic inventory build this winter is running out of steam, but this is not a certainty.

We also need to keep the Iran situation in the back of our mind.  I don't know how to handicap a deal and the end of US sanctions.  But I think that the highly effective sanctions that have been in place since 2010 are coming to an end, one way or another.  The Russians have announced a deal to trade crude for missiles.  This is one of the ways that Iran can skirt sanctions.  The US banking restrictions are a hugely effective tool, and crude exporters must go to great lengths such as buying oil with physical gold, as Turkish traders are almost certainly doing.  If Russia set out to skirt the sanctions using barter: trading grain or weapons for oil, they could probably soak up all the Iranian exports then re-export at a profit.  Even if congress kills a deal with Iran, it is hard to see how the sanctions regime can hold up now.  Because of the actions of Netenyahu and Congressional Republicans, it will appear to the rest of the world that we were not negotiating in good faith.  We need Russian and Chinese cooperation for the sanctions to be effective and it is hard to see how that happens going forward if a deal is not reached.  The bottom line is that I expect Iranian crude is likely to come onto the market this summer one way or another.

middle eastern rig counts skyrocketing, has not been widely reported

I did buy some Whiting Petroleum yesterday.  Partly because of the start of declining production in the USA and partly just FOMO.  It did feel a bit like chasing.  This is my second purchase of Whiting this year after I bought then sold it earlier.



Something that I have not heard discussed often is that the middle eastern countries are increasing their investment and rig counts to unprecedented levels.



There are a number of plausible scenarios for this.

1) They are replacing fields that are in terminal decline.  The additional investment may be a signal that they are having more and more trouble keeping production levels flat.

2) They have changed their policy and started ramping up in 2011 for their market-share grab of late 2014.

3) They want to lower the price of oil and bring forward their production, because they are worried that they will get stuck with "stranded" oil if the world were to switch away from fossil fuels 30-50 years down the road.

It may be several of these and other factors.  But to me, the idea that they are having trouble keeping up production doesn't ring true based on their other behavior.  For one, the fact that the Saudis are now producing at record levels of 10.1 mmbd does not suggest difficulty with keeping up output.  However the ramp up may be in anticipation of a decline at the Gawar Field, which produces over half of their oil.  In fact, Gawar, has produced about 65 billion barrels of oil, or about 60% of total historic Saudi output.  As of 2008 it was supposed to have had another 60 billion barrels of reserves.  This is pure speculation though.

If I were the saudi's I would want to have a lot of spare capacity and inject a uncertainty into the future price of oil that would make it difficult to plan for large high cost projects in high cost areas like Brazil or the Gulf of Mexico.

New EIA drilling productivity report out today shows Bakken and Eagleford peaking two months ago

It seems that production has peaked in three of the two of the three major basins.  It is showing some signs of leveling out in the Permian as well.  Now that the decline has started, I would expect an acceleration in declines as we go forward, especially in the Bakken.  The market may still be oversupplied for some while, even as production declines and maintenance season ends at refineries, but certainly this is a significant moment.

Part of this decline in production may be due to the well documented current tendency of deferring well completions.  Essentially this is oil in storage.  There are a number of reasons to do this.  “Completing” a horizontal tight-oil well can cost substantially more than drilling it.  By waiting as service costs come down, the E&P company can improve the financial return on the well.  They can also sell the oil forward for when they know it will be completed, and since future prices are higher than spot prices (contango) they will lock in a higher price than if they were to sell that oil today into the spot market.  I am aware of this effect, but I don’t think that it should be over-emphasized.

Shell to Buy BG Group, the biggest E&P deal in a decade

Shell announced their intention to buy BG group for $70b.  BG, formerly British Gas, is not so well known in the USA, but they are one of the largest gas E&P companies in the world, and perhaps the largest European E&P.  I think this is the largest E&P deal since Exxon bought XTO during the gas bubble of 2008 for $40 b- a terrible deal for Exxon.

The purchase price of $70b comes out to 7.7x trailing EBITDA.  It also comes out to $10.7 per bbl of P1 reserves (their reserves are about 80% gas), and $115,000 per daily flowing barrel.  These are all pretty high multiples for a gas company I think (even a non-US gas company), but a big part of the price might be their LNG infrastructure.  It is interesting that shell has chosen a company that was not at all distressed, though certainly their share price had fallen over 40% from a high last summer.

A comparison of three large-cap exploration and production companies

Today I have started to review the 10k reports from exploration and production companies with an eye on their year end reserves.  This is a nice time of year to compare various companies because they all disclose so much information in their annual reports.  I also thought it would be interesting to show how “quality” can be analyzed by the historical data presented in their 10k reports.  I’ve focused on three large cap diversified companies .

EOG- Originally spun out of Enron Corporation as “Enron Oil and Gas”, EOG is widely considered the highest quality shale company, and for very good reason.  They have proved adept at discovering new plays (we can give them credit for both Bakken and Eagleford), but also for recognizing an important macro trend in the industry and shifting away from gas drilling early on.  They also have very good cost control and operational performance and have managed to build land positions through leasing rather than expensive purchases from other oil companies. 

Anadarko- this is a well-managed company, though probably a tier below EOG.  They are experts at offshore exploration and have made very large discoveries in East Africa (Mozambique gas), West Africa, and in the Gulf of Mexico.  They boast an incredible 65% success rate with offshore exploration and appraisal wells.   A large part of their business model is discovering new offshore fields then selling an interest to a larger partner, and they have sold $12.5b of assets in the past 5 year period.   They also have a large presence on-shore in the US in the Marcellus, Eagleford, and Watenberg (Colorado/PRB).  They may be the best at deepwater exploration, but I think deepwater is a more challenged business model than the best of onshore tight-oil.

Apache- Apache is not a well run company.  I have owned it in the past based on low valuation, but management has not performed well at all over the past few years.  Their original specialty was to buy up older fields from the majors and milk them with careful investment and good financial management.  In recent years they have tried to make a shift toward shale by buying up US assets in the Midcontinent and Permian regions and plowing billions of capex into development drilling.  Apache’s MO in recent years has been to take free cash flow from their highly profitable Egyptian operations and plow it into marginal or money-losing onshore projects in the USA (and to a lesser extent over budget LNG projects in Australia).

Looking at earnings and PE ratios can be dangerous when analyzing oil and gas companies, unless they have relatively flat production.  PE ratios are more reasonable to use for oil majors, since production and reserves change little from one year to the next.  Their capex and depreciation tend to be more in-line with each other.  In the recent years of the oil boom here in the US, the exploration and production companies are often growing production quite quickly.  It is possible to have a company that is showing little or no profit, but is in fact making very profitable investments.  One thing that I like to do is look at both production and cash-flow growth over time, and then look at free cash flow.   Oil companies don’t need to be free cash flow positive to be a good investment.  They also don’t need to be growing to be a good investment (look at Exxon over time).  But if they are neither producing free cash flow nor growing then there is a major problem.  I find that this is a good starting point when trying to understand a company.   There have been an incredible number of methods at determining capital efficiency of exploration and production companies based on various operation statistics, but to me this approach should be first.

First let’s look at how production has changed at these companies over the past several years

So from this view we can see that both EOG and Anadarko have been successful at increasing their production since 2012, while Apache’s production has declined.  But one thing to be careful of here is that the metric of “MBOE/D”, or thousands of barrels of oil-equivelent production per day, lumps low value gas with high value oil.  NYMEX oil trades at $49 per barrel.  1mmbtu of gas trades at $2.71.  To get to oil equivelant price, multiply $2.71x 5.8 (or 6) and get $16 since one barrel of oil is abotu 5.8mmbtu of energy content.  So 1 "barrel" of gas is only $16 and a barrel of oil is $49.  So a company may be investing mainly in oil and letting gas production decline, and their overall production in terms of MBOE/d might be in decline, but the value of that production may actually be increasing.  So for that reason it is useful to look at their % of oil in their production mix.

All of the companies have been shifting towards greater oil production, but Anadarko’s shift has been quite moderate, while EOG’s has been very dramatic.

The next thing to look out for is whether the reserves are being maintained.  One thing that the oil majors like Exxon, Chevron, Shell, and BP have been doing for years is under-replacing their production.  In other words, if they produce 2 million barrels of oil per day, they add less than that quantity of reserves, so that at the end of the year they show lower levels of reserves than they had the year before.  The other thing they do is replace expensive and valuable oil reserves with less expensive and less valuable gas reserves, and claim to have been successful at maintaining their reserves.  Reserve life ratio, is the number of years it would take to produce out the current reserves at the current annual rate of production.  So for this chart, I have divided 2012 reserves by 2012 average production, then 2013 reserves by 2013 average production and so on.

  

EOG has been growing their reserve life ratio and Apache has shown the most notable decline, but in this particular case all the reserves are at a healthy level.  10x is quite healthy, but significantly lower levels can be a big red flag.  Sometimes if you see very high levels of reserve life, that can also be indicative of a major operational problem.  For instance it is common for gas producers in the Marcellus, who are constrained on capacity to get their gas to market.

Next we must look at their spending pattern.  I have seen people totally ignore free cashflow in their analysis, and I’ve seen others fairly obsessed with it.  I have even heard someone say, “If a company is not generating free cash flow than what good is it to the investor?”  Well if a company is growing quickly, or if they are a commodity producer in a time of heavily depressed prices, then negative free cash flow is not necessarily any cause for concern.  On the other hand, if two companies have similar production growth profiles, but one is outspending their cashflow and the other is generating free cashflow, then this is certainly an important thing to understand.  Free cash flow can be calculated in several ways, but for oil companies I prefer to just take cash flow from operations and subtract cash flow from investing.  

This is a bit of a hard chart to look at because of the volatile nature of it.  Apache’s free cash flow has been volatile because of major acquisitions (in 2012) and big asset sales in other years.  APC’s free cash flow was impacted by the $4b payment to BP in 2011 to indemnify themselves from any liability in the Gulf Horizon spill, for which they were a non-operator/minority investor.    But other than that incident, they have maintained very healthy levels of free cash flow.

Conclusion:

The overall picture is that APA has outspent cashflow by $1.2b in the period, while both their production and reserves have been in decline, a very poor result for a period with historically high oil prices.  EOG on the other hand has generated a small amount of free cash flow ($91mm) as they have grown production, reserves, and quite dramatically increased their weighting to higher value oil from lower value gas.  Anadarko Petroleum also has an overall positive record.  They have generated a nice sum of total free cash flow over the four years ($666mm) while growing production, maintaining reserve life, and slightly increasing their oil weighting. 

But having made this determination, there is a subsequent step that is just as important, and that is valuation.  EOG and APC both deserve a higher valuation multiple than APA, because they are higher quality companies.  But indeed these companies already trade at a higher multiple.  EOG is now trading at about 12x consensus 2015 EBITDA.   Anadarko is at 11.5x.  Apache is at 6.7x.  How can we compare low quality APA trading at a cheap multiple to high quality EOG and APC trading at a high multiple?   I really don’t have any satisfactory methodology for making a selection between two companies that are so different.  It is much easier to pick between two companies valued at similar multiples.  For instance there is little question in my mind that EOG is a much higher quality company than Pioneer, and Pioneer trades at a higher multiple at 15x 2015 EV/EBITDA.  I have owned EOG, APA, and APC each at one time, and was fully aware of the quality gap between these companies.  APA turned out to be the best investment of the three, but this was largely because I owned during a period when pretty much all oil stocks were going up.

Will the US oil export ban be lifted?

The US crude export ban is one of the bizarre quirks of American politics.  American politicians have a long history of demagoguery and idiotic behavior in the sad history of our national energy policy.

At the time it was instituted in the 1970s the US was already a major importer of crude oil.  I'm not sure if the ban was designed to be ineffectual, but there was never any impetus to end it, even in the long era of deregulation.  The US was the thirstiest country in the world, why would anyone want to export from here anyway?

Although we are still a huge importer of crude, we are producing too much light oil, when our refineries are geared towards refining heavy oil oil.  Heavy oil is more technically challenging to refine efficiently and "high-complexity" US refineries on the Gulf Coast are needed to refine Mexican, Venezuelan, and Canadian heavy crudes.  The logical thing to do would be to export light oil and import heavy oil.  But the export ban prevents this.

Obviously the ban was ostensibly intended to keep US fuel prices down.  I say "ostensibly" because in order to have this policy be successful, you would clearly need to also ban the export of gasoline and other refined products.  But we have not done this.  So millions of barrels per day of diesel is exported from the USA.  US gasoline and diesel prices will never get far below world prices, because then people would just export more gasoline and diesel out of the US to take advantage of any price difference.  So now that there is a glut of US light crude, the price differential between US and world light crude oil grades is not accruing to the US consumer, it is accruing to the US refining industry.  In fact it is a massive subsidy to the US refining industry.  The refining industry and the refining unions have the gall to lobby against lifting this ban.  I can only imagine how they would cry if congress fixed the ban and ended exports of refined products too, so that the benefits would accrue to the consumer instead of the refining industry, as it ostensibly was originally intended.

The Republicans are pushing bills through to end the ban.  Its hard to see how this could get held up or vetoed, but in the world of US Energy policy I suppose anything can happen.  The Dems could bow to the environmental left(a la Keystone), or the Republicans could put a highly offensive and wholly unrelated rider in the bill (like the abortion language in the recent anti-human trafficking bill).  Ending the ban will hurt refiners and help domestic E&Ps.

Iran thoughts

Brent prices, and to a lesser extent WTI were hit with news that the a "framework" had been reached with Iran today, and a full deal and easing of the sanctions is expected to be reached by sometime in June.  Iran supposedly has tankers full of crude ready to go, and about 1 million barrels per day of unused capacity.  Since there is plenty of inventory on hand right now, I would think this should start hitting prices across the curve right away, even on oil for delivery before the sanctions are lifted.

The 10 year chart of Iranian production below gives you a sense for about how much supply they are going to be able to add.


From oilprice.com- Can you guess when they ramped up the sanctions?




























The chart above from Wikipedia only ends in 2006 but it does show the Iran production during the 1970s.

An Iran deal is also bearish for oil in the longer term.  Since there is very little prospect of cooperation between Iran and Saudi Arabia/OPEC, Iran is likely to try to increase capacity and gain market share where it can.  Presumably competent service companies and some investment could rapidly raise Iran's output.  Iran's conventional oil reserves are 2nd in the world, and total reserves are 4th.  There is certainly very significant scope to increase production if it becomes a normal country.  Iran produced over 6 million barrels per day before the disruptions of the '79 revolution.  This was immediately followed by the Iran-Iraq war of the 1980s, the very low prices of the late 1980s and the 1990s, and finally the international sanctions.  In the very long term Iran might also add to the LNG glut, since they have a ton of conventional gas and no pipeline exports.  The logical thing from a logistical standpoint would be an export pipeline to Pakistan and even India, though the geopolitics of all that make it seem a rather remote possibility.

Of course there are various parties who want to scuttle this thing on both sides, so it may not be a done deal yet.