EIA data release and some predictions for 2015

Data releases by EIA

Earlier this month the energy information agency released their year end 2013 reserve estimates for both liquids and natural gas.  I think that the past experience with gas reserves and production will be instructional for what is likely to happen in the world of crude oil.  When the price of US natural gas crashed in 2008, a number of interesting things happened: 

1. The number of rigs drilling for gas plummeted, and most of these were shifted over to oil drilling in the Permian, Bakken, and Eagleford.
2. Reserves in what turned out to be the higher cost shale basins (Barnett, Fayetteville, Haynesville, Woodford) continued to increase for another two or three years before leveling off, or even declining in the case of the Haynesville due to write-downs of uneconomic reserves.
3. Reserves and production continued to climb in the lowest cost basin, the Marcellus shale in Pennsylvania and West Virginia.
4. Despite the number of rigs going from 1500 to 350 or so, natural gas production has continued to increase due to continued improvements in performance and increasing infrastructure in the most cost-efficient area (Marcellus).

(I know I have said all this before on previous posts)

 The economics of the various shale oil plays remain something of an unknown in 2008, because the pell-mell pace of drilling, the lack of infrastructure, widely varying degrees of acreage quality and operator competence etc.  As of 2008 most of the drilling was for the purpose of holding acreage, and so was inherently inefficient.  It was also done in a boom atmosphere and a rush to claim huge tracts of acreage, and amidst very high prices.  At that time, there were plenty of analysts saying things like “you need $5.50 gas for shale drilling to make sense” and putting specific numbers for the so-called breakeven price in each of the shale areas.   Most of the drilling was not economic at the lower gas prices that we’ve had these past 5 years, but enough of it was to keep production growing.

How does this provide instruction for us on what is likely to happen with oil production in the USA?

Unless prices continue to decline, I think we are rather likely to see similar things happen: 

1. Number of oil rigs will decline dramatically.
2. Some areas, particularly newer-unproven oil regions such as the oil window of the Utica, Tuscaloosa Marine Shale, various of the smaller plays in the midcontinent region (Oklahoma, TX panhandle), and perhaps the DJ Basin/Niobrara area will see major declines in rig count, and perhaps also in production.
3. The big three regions will also see declines in rig-count, especially in exploratory peripheral regions, but production is likely to continue to grow, though perhaps more slowly.
4. The focus for the major operators will be how to streamline operations, cut costs, improve well economics, rather than finding new plays, adding acreage, or accelerating drilling schedules to bring forward returns.

but there may also be some big differences with 2008:  UNLIKE in the gas crash, operators will not have the ability to shift from one uneconomic resource (gas) to a profitable one (oil) as they had done in the years following the 2008 gas crash.  A number of smaller operators, and some larger ones, basically walked away from non-economic gas, bought some oil leases in Bakken/Permian/Eagleford, and were able to cover their interest payments and continue as a going concern.  Even the companies that carried on drilling gas tended to shift to "wet gas" since propane and butane prices are partly linked to oil prices.  Only a handful of companies including Southwestern and Cabot continued to drill almost exclusively dry gas (though both have more recently also shifted some capital to oil drilling).  The option of switching to a more profitable resource is not available at the moment because both oil and gas prices are low, so we are much more likely to see bankruptcies this time around should low prices in oil persist.   Unlike in the gas crash, the service companies will not be able to shift assets from the gas region to the oil region.  THIS MEANS THAT PRICES FOR SERVICES WILL PLUNGE.  Those declines in service costs will make break-even oil prices far lower than those often quoted today, and this will provide some relief for the E&Ps.

This last point is very important.  The companies most likely to go bankrupt are smaller E&Ps and smaller service companies with debt.  The smaller E&Ps that have no real economic drilling opportunities but don’t have a mountain of debt, may be able to sell-out to other operators.  If they have too much debt, they may be destined for bankruptcy.  Service companies may be even more vulnerable.  During the 1980s crash the number of rigs in use went from 4,500 in 1981 at the peak, down to 660 at the 1986 trough.  Rig rates went from $40k per day down to $7k per day.  Physical consumable items like drillbits declined in price by about 40% according to this very interesting article from the Economist from 1987.  http://www.economist.com/news/business-and-finance/21634592-looking-back-consolidation-swept-oilfield-services-industry-1980s-americas-oil

I think a similar spate of bankruptcies is highly likely, which is one reason why I chose to wait and not buy oil equities yet.  There is one important difference between then and now which should be highlighted.  Those 4500 rigs in 1981 were basically scraping the bottom of the barrel on US onshore conventional oil drilling opportunities.  They weren’t particularly spurred by any improvement in technology, only on a change in price.   This time around we are in the midst of a technological shift that makes drilling tight oil increasingly economic.  We are already hearing about acceptable rates of return in parts of the eagleford at sub-$40 oil from operators like EOG.  After massive service costs reductions combined with continued improvements in drilling practices, I wouldn’t be surprised if we see $20 breakeven prices in the Eagleford core when we look out two years from now (note that this prediction is totally predicated on continued low- say sub $60 prices). 

Besides waiting to see how the cost structure shakes out in the various plays, another reason to wait at the moment is to see which operators adopt a correctly conservative approach and cut costs aggressively.  E&P operators tend to be inherently optimistic people, and I want to see which companies scale back operations and go into survival mode, and which carry on spending recklessly.

price comps (first time in a while)

I realize that this is an incredibly tedious way to present data.  But it is useful to scan down and look at these numbers.  When I look back to the period prior to the OPEC meeting I do feel that I missed out on an opportunity to profit from put options.  I also regret not selling my shares of Whiting.

  The Permian Basin companies, which did poorly in September and October have held up reasonably well since the date of my last price check on November 12.  The Marcellus companies, which held up well early on have done poorly since.  They are reliant on both gas and NGLs, and the price of both have suffered partly due to the warm winter so far.   The Bakken companies have been terrible.  This is because they are perceived to be high cost producers, and also because there have recently been large discounts for bakken oil off of already low WTI prices.  Continental has trimmed spending in the Bakken while maintaining it in the midcontinent region, indicating that it has less favorable economics.

I have not started buying anything yet, and I believe that people are still perhaps being complacent about how far down oil can go.  

One curious thing to me is how Suncor, the canadian oil sands giant, is only off 7% from early november.  They are a high cost producer and it is interesting that their price is holding up so well.

current discounts vs 52 week high:

quick look at Bakken debt

The world of high yield debt has been shaky recently.  This is partly due to the prevalence of low credit quality energy issues, which I believe make up about 15% of the high yield market.  The other factor may be the anticipation of rising interest rates.    I decided to go through some of the Bakken names first, just to be aware of how their credit is trading.  The purpose of this is not a credit analysis, but just a check-up.  What is interesting is that in all cases, the sell-off really started in earnest with the OPEC decision to maintain output.  Most of these companies have some hedges in place, and generally they should be OK when it comes to servicing their debt unless the price of oil falls further, which is certainly a possibility.

Continental Resources-

Formerly the biggest Bakken player prior to the WLL/KOG deal, it is trading 50% lower than where it was this summer.  With about $6b of net debt they are a bit less leveraged, at 1.7x 2014 ebitda estimates, than some of the others like WLL.  They went from about $4.55 b of 2014 capex to 2.7b of projected 2015 capex.  They recently cut their capex outlook for 2015, and notably their Bakken capex went from 2.6b down to 874mm while their drilling in Oklahoma was only curtailed by 20% or so.  This  indicates that their best returns are not in the Bakken, although it might also have to do with holding onto acreage.

This is a benchmark bond for CLR 5% due 2022 callable 2017, with $2b outstanding.

Whiting Petroleum

After the Kodiak acquisition, which closed earlier this month, Whiting is now the largest Bakken company when measuring by production.  Whiting assumed $2.2b of Kodiak debt when they bought the company this December for about $2b.  The transaction was all stock, so the price was substantially lower than what had been initially announced because the shares of WLL were worth far less than when the acquisition was announced earlier this year.  Whiting had about $2.75b of gross long term debt prior to the acquisition, and $4.95b after.  Net debt to ebitda is about 2.5x. The stock is 60% off its summer highs.  WLL has not announced 2015 capex, but certainly we would expect big cuts when they do.

2019 5% notes.

Oasis Petroleum

These guys are now trading at $16 per share, up off the lows of $11, and down from $55 this summer.   With about $2.7b in net debt they are leveraged to about 3x 2014 EBITDA.  Their B+ rating from S&P is vulnerable to put it mildly.   Their 2019 notes have recently traded at 85, for a nominal yield of 11.7%.  They have $400mm due 2019, $400mm due 2021, $1,000mm due 2022, and 400mm due 2023.  I would expect them to get picked up by someone if oil prices stay weak, though I can hardly see CLR or WLL stretching their balance sheets further.  They had been running 16 rigs, but have already started to drop them down to 6 by the end of March and they say they can do 5-10% production growth.

6.875% 2022 notes.

Northern Oil and Gas-

This is a rather shaky company that does not operate any drill rigs, but takes a non-operating stake in other companies drilling.  It was originally the subject of some controversy in the 2009-2010 timeframe because some of the founders had a history of fraud.  Today it has $500mm of bonds due in 2020, with a YTM of 12.5% or so.  Their S&P rating is B-, but given where there bonds are trading you would think further downgrades are in the cards.  The equity is trading at about $6 compared to a 2014 peak of $16.  Net debt of $900mm is about 3x 2014 ebitda.

checking in

I'm going to do a post that looks at the sell off in energy debt over the past several months, but before beginning I should also note that I’ve now sold my small position in EOG at 96.58 per share on 12/23/14, having bought it for 101.32 per share in early September.  I still think this is the best quality US E&P, but its modest decline in share price does not fully reflect the very bad situation in world oil markets, so I’ve elected to sell it.  I now only hold WLL, and I wish I had sold that months ago.  Oil may have found a bottom here with WTI at $55 and Brent at $59, but I don’t think we can be at all certain of that.  Natural gas, though not as much discussed, has been rocked by a warm winter in the north east and some of the gas producers have seen huge declines.  

My sense when I was reading various articles today is that people are being complacent about how low oil can go.  So far we have seen serious curtailments to E&P capex, but almost all still claim they can grow production even with capex cuts of up to 50% compared to 2014 levels.  The price of oil must go low enough to spur more demand, or to limit supply.  Without a functioning cartel, it may take truly drastic price movements to get supply and demand inline with each other.  I believe that people have been buying E&P companies because they believe the price of oil will soon go back up, which I think is dangerous.  The inflows into the oil ETFs has been huge apparently.  Someday the price of oil will certainly be higher than it is now, but it may go down more first, and it may take a long while to rise again.

I also think that if oil were to stay at current levels, US E&Ps will do better than some might expect.  With both oil and gas prices low, we should see a major drop in rig count next year.  This may cause very large declines in service costs, rig lease rates, completions services, etc, which will cause a big increase in capital efficiency.  Also, it will be the least efficient rigs in the least efficient plays that will be laid down.  A 30% drop in oil rigs might have a surprisingly small effect on production.  This is similar to the effect we saw after the price of gas crashed in 2008.  Gas rig count plummeted from a peak of over 1500 down to about 340 currently, while gas production continued to increase the whole time.  You constantly see estimates of the "breakeven" oil price in various regions.  Those breakeven numbers will continue to decline as service costs go down and operator efficiency continues to increase.

A few links for the week

 An article posted on the Andrew Sullivan blog profiles a well timed book called The Peak Oil Scare and the Coming Oil Flood.

Rigzone has an interesting Reuters article about potential capes cuts in the industry for next year.   There were  $500b of major projects scheduled for final investment decision next year and the article says that Canadian oil sands, Venezuela heavy oil, and some deepwater projects were most likely to be cancelled.

EIA.gov has come out with their annual US petroleum reserves report for calendar year 2013.  The main take away is 10% increase in proved reserves for both oil and gas in the USA during the period. This corresponds to about a 2-1 reserve replacement ratio, which is incredibly high.  Most crude reserve increases were in Texas on-shore and North Dakota.  The biggest natural gas increase was in Pennsylvania.

Bloomberg has an interesting article about how energy insiders are buying big right now.  I must say that I don't find this to be a compelling reason to buy E&Ps yet.  In 2010 I went to a meeting of IPAA (Independent Oil and Gas Association of America) in NYC.  There were lots of E&P execs saying things like, "We're going to cut back on gas drilling until gas is back in that 5-6 dollar range."  This struck me as wishful thinking.  Why would should gas go back to that when there is an ocean of the stuff under PA, WV, OH, that can be produced at a profit for $2-3?  I am not sure that oil needs to be at $100 to incentivize sufficient supply over the short, medium or long term.

A look at costs for a few of the larger US-focused E&P companies

What are really the costs in the Eagleford, Bakken, and Permian basins?  There is a notion that the oil majors are well insulated from a decline in oil prices, mainly because of their diversification.  There is some truth to this, but the oil major’s business model is in some risk as well.  The tight oil players (“shale”) do have high costs compared to projects in the past. 

What we see here is that costs are apparently in the range of $33 to $48 per bbl among the mid-size to larger domestic-only E&P companies.  If we assume that oil cost substantially more to produce than gas, lets say that costs are about $40-$50 including DD&A.  If we look at the highest cost producer according to this chart, Whiting Petroleum, we can chart costs over the past few years.

I apologize for this eye chart here, but the key thing to see that the component of the costs that has increased is mostly the DD&A item.  This is depreciation, a non-cash cost.  It is curious that by many measures capital efficiency has been increasing dramatically in the Bakken during this period.  In terms of both EIA's metrics like "new production per active rig" and in terms of the companies' own claims about higher estimated ultimate recoveries based on improved hydraulic fracturing technology, it is likely that actual capital efficiency, in terms of oil that will ultimately be produced per $ of capital expense, is increasing.  But while capital efficiency is actually increasing (or so I believe), it looks like it is decreasing based on the metric DD&A per barrel of production (in the case of Whiting anyway).  I think the reason for this is that annual capex has more than doubled between 2010 and 2014, and has increased at a faster rate than production.  Due to their aggressive depreciation policies, the increased capex leads to higher depreciation per barrel produced.  If they were to pull back on their capex (which might be prudent in the current environment) costs on a per-barrel basis should decline significantly.  Also, as cost become more of a focus, instead of production growth, I anticipate greater capital efficiency from all of these companies.  Production taxes, which are proportional to oil prices, should decline as well.  In a lower price environment, I think you could see per bbl cost decline significantly in the major plays.  

It is also worthwhile to take a cursory look at the offshore "mega" projects, and DD&A per BOE rates already comparable to the E&P companies.

Here's a look at a few:

Stampede: US Gulf of Mexico.  Hess, Chevron, Statoil, Nexen.  $6b capex for 300mm bbl recoverable is $18/bbl.  That is before the inevitable cost overruns.

Hebron: Offshore Canada.  Exxon and Chevron’s Hebron project off shore Canada is now expected to cost $14b for 700mm bbl of recoverable resource.  This equates to about $20 capex per estimated recoverable bbl.

Kashagan: Eni, Royal Dutch Shell, Total- Kazakhstan Caspian Sea.  This project has already cost an astounding $50b, and has been 14 years in the making.  Phase 1 was originally intended to cost $10b when it was approved in 2005.  It started production early this year, only to be shut in after a leak.  It is now expected to produce 100,000 bbl/d after phase 1, instead of the original estimate of 180,000 bbl/d.  There are two more expansions which were originally set to increase production to over 1mm b/d, but that is in some question at the moment.

Then there are the LNG projects like Gorgon and Wheatstone.  These have also had notorious delays and cost overruns.

These are just a few, but the point is that the offshore projects dominated by the oil majors don't appear to have particularly better economics than the onshore tight oil plays.  Just as for the onshore projects, some of the cost growth in the offshore projects is due to very tight market conditions for both labor and equipment.  As industry capex declines, costs should also decline for the mega projects. 

What price is the "right" price?

To the left is a list of how far each of the stocks we've been following is below its 52 week high.  Note that the S&P is basically at its 52 week high.  It is hard to say if the declines are justified, but so far I'm not tempted to step in and buy.  One thing that I would point out is that the 11.8% decline for Exxon off its high seems far too modest given the carnage among the E&Ps.  The majors are somewhat insulated from oil price moves because of the structure of production sharing contracts in foreign countries, and also because they derive earnings from petrochemicals, refining, and retail operations.  But it is hard to reconcile the drama in crude prices with how well the two american majors have held up.

One thing that is scary about the current situation is that there is really no way of knowing what the price of crude will end up at because crude prices are all about perception in the short term.  Below is the 2004 copper "cost curve".  This chart has an incredible amount of information about what the price of copper "should" be.  Each of the bars on that chart represent a mine or a group of mines.  The height of that bar is the estimated operating cost net of production credits to produce 1 lb of copper from each of those sources.  A production credit is the value of other recources from the same mine.  For copper it might be gold or molybdenum or some other desirable metal.  The reason that the mines furthest on the left of the chart are in negative teritory is that you could still economically run the mine even if you threw all the copper away, because the bi-product credits alone would make the mine economic to run.  The width of each bar on the chart represents the amount of copper production available from that source annually.  Now imagine a scenario where copper demand declined to 14,000 kt/year.  The price could theoretically decline to about $1.25 per lb.  This is the price at which all production above 14,000 kt/year should theoretically shut down (in 2008 according to the mining company BHP). It would be totally impossible for prices to fall to $.50 per lb for any length of time, because nearly all mines would have to cease operation.  Because of this it is possible to determine approximately where the price of the commodity "should" be.

Oil does not have a meaningful short-term supply cost curve.  If you google search "oil supply cost curve" you will get many results, but none of them will come anywhere near the precision of the chart above, because such precision is totally impossible for oil.  The reason for this is that for a copper mine, while there is significant upfront capital cost, the bulk of cost is in operating cost.  The majority of the dollars spent to getting copper out of the ground in 2014 was spent that same year operating the mine and refining the copper.  For a barrel of oil pulled out of the ground this year, the bulk of the spending happened in prior years in the form of capital expense.  There is no way to know what profit or loss may come from a dollar of capex spent today.  Operating costs are typically far below the revenue derived from production.  So unlike for the copper mines, there is little chance that someone will shut off supply to balance the market for reasons of economic self-interest.  Over the longer run, lower prices will halt new investment, which will gradually cause a decline in supply to balance the market, or new demand may be stimulated by lower prices, but this may take a long time indeed.  The highest operating cost producers are assumed to be the Canadian oil sands operators, but the largest of those, Suncor, recently reported cash operating costs of $34 per barrel for their oil sands operations.  Western Canada Select has traded at up to $40 discounts to WTI in recent years, and the oil sands kept producing.  All this suggests that for serious supply to come off the market in the short term the price may have to fall far lower.  Few believe the price could stay in the 30s for long, since much higher prices are needed to justify the capital investments needed to replace the production declines from existing wells, but if OPEC is not going to take the reigns and balance the market, there is really nothing to prevent further declines in the short term.

Freeport McMorran nears settlement with shareholders

WSJ reports they are settling with shareholders for $100mm with allegations over insider dealing on the Plains Exploration and McMorran deal.  I only mention this since I had posted about it in may.

The management of FCX was also on the McMorran Exploration board, and the allegation is that the buyout was really a bailout for struggling McMorran Exploration.  Cross-holdings meant that PXP had the ability to block the deal, and so it was necessary to buy them out too.  The market reacted terribly when this deal was announced at the end of 2012.  I bought some shares in the high 20s when they sold off, and sold them at just above $30 a few months ago.

This is an example of how the management and board members tend to collude for their own benefit at the expense of shareholders.  This management had generally been considered "shareholder friendly" because of their policies.  That changed suddenly with the announcement of this acquisition.

Black friday for oil stocks

Everything's on sale!  But they will get cheaper yet.

I'm really regretting not getting those PXD options on friday, which would are up about 500% + (hard to tell because they're thinly traded.  But I'm glad I have a position in American Airlines (up 8% right now).  I'm looking to unload EOG, because I think it has much lower to go.  Its too painful to try to sell WLL today.  Some of the companies, even large caps E&Ps, are down 20% right now.

Oil can go MUCH lower than this.  Why shouldn't it go to $50?  If OPEC is not balancing the market, the market will have to balance the market.  We should see some major capex cuts, but what can stabilize the market in the short term?


The fact that the S&P is up right now seems strange to me.  There could be huge consequences to what happened yesterday.  Countries like Venezuela or Iran or even Russia could be in serious trouble.  Default rates on sub-investment grade corporate debt could start to spike, because energy is a big chunk of this market.  US Petrochemical industry (DOW, LYB, WLK) could be hurt because they rely on an advantage of US natural gas liquids vs global oil prices.  Within the transport sector we're seeing rails get hammered today because they transport so much crude by rail today.  It's going to be an interesting couple of months.

thoughts on the OPEC meeting

The meeting is on the 27th.  I had incorrectly written the 22nd earlier.

I did put out a bid for some January out of the money puts on PXD as a bearish bet going into the OPEC meeting.  I have shares of EOG and WLL on the other side of the ledger.  My limit order did not hit though, so I'm still marginally long oil going into the OPEC meeting.

I'm not sure if it is unprecedented, but it was very interesting to read about the Russians and Saudis giving joint statements on oil production levels.   The Russians may be signalling that they will cut output if OPEC does.  Between them they are 45% or so of world production, vs 33% for OPEC alone.  If I were the Saudi's I'd only be willing to cut if I knew that everyone was cutting their fair share.  Russian cooperation would go a long way toward that.  The funny thing is that people are speculating that the sanctions against Russia may cause production declines next year either way.  Maybe they can pretend to cooperate without really having to do anything.

It is worth mentioning that much of Russian oil production is not in the hands of state owned companies like Rosneft and Gazprom.  But no one should doubt that Putin could order the private companies to cut output if he felt like it.

Next week will be interesting.

A second historic example: the gas crash of 2008

A second example which may also be instructive to the current situation in the oil markets is the 2008 crash of NYMEX natural gas.  The gas price crash of 2008 pertains only to a local market (USA) since US gas is isolated from the international market.  But it may be instructive to look at because the production curves are similar to  unconventional oil wells, and the companies doing the producing are those same companies adding all the excess supply currently.

The US gas market is different than the world oil market in a number of key ways.  Besides being a much smaller than oil, there is also very limited storage availability and strong seasonal use in winter.  This can lead to price spikes during the “draw season” (when storage facilities are drawn down).  Both of these things increase price volatility.  There is also another factor which reduces price volatility.  Because much of the gas produced is used for electrical generation, it is substitutable, to some extent, with coal.  Natural gas turbines are relatively cheap to install, so utilities don’t mind leaving them idle if the price is high, as long as they have other options for generating power.

During the first half of the last decade gas production was in decline in the USA and there was a worry about a shortage.  This spurred investments in expensive LNG import terminals (terrible investments as it turned out).  Then came the shale gas boom.

A Brief history of the US Shale gas boom

(This is not researched and mostly from memory so let me know if there are any inaccuracies)

The Barnet Shale in the Fort Worth area was the first shale region that was actively produced.  It turned out that gas could economically be produced from a huge area if hydraulic fracturing and horizontal drilling were combined.  Companies like Devon Energy, EOG, Chesapeake Energy, and Encana were all early producers.  Shortly after, three other plays were discovered.  There was the Fayetteville Shale, in northern Arkansaws, The Haynesville in East Texas, and the Huge Marcellus Shale in West Virginia, Pennsylvania, and South-Central NY state.  Companies rushed to stake their claim to these huge geographic regions.  The rig count went sky high.  Production started to outpace demand, and the price crashed (after a speculative bubble in 2007 and 2008, but that’s a different story).

 Something interesting happened when the price crashed and the rig count along with it.  The production continued to increase!   How did this happen?  It is instructive to look at the individual regions.

First there is the Barnett, where the whole shale gas boom was kicked off.  Production stayed largely flat after the price drop, despite a huge drop in the rig count.

One reason that the regions tend to level out rather than declined is that in many cases there are firm take-away agreements between the gas producers and the pipeline companies, so they get penalized for producing below a certain level.  We are seeing this currently with Chesapeake in the Haynesville region.  Other reasons are that the pipelines were built, well pads and roads built, seismic studies conducted.  The land was leased and much of the land was also held by production.  All of this decreases the incremental cost of drilling additional wells.

The production increases since the crash have been driven almost totally by the Marcellus (South Texas Eagleford can take a bit of credit too).  Marcellus production was slow to take off because there was much less infrastructure in this region compared to Texas and Louisiana.  But the geology is much better than the other shale regions.  In fact, production now is mostly constrained by the ability to move the gas and NGLs to market, rather than by price even though pricing is terrible in the region, with realized prices far below the NYMEX price.

How does this relate to the current situation in oil?

The current world oil production growth is driven almost totally by unconventional oil production in the USA.  This production growth is exceeding world demand growth causing an oversupply situation.  We will not see prices stabilize until production and demand are matched.    Will the lower prices spur higher demand?  Will OPEC try to balance the market with cuts?  Will high priced production turn off to balance the market?  It is impossible to say for sure.

One thing is sure though.  We have not seen the cuts in investment so far that would indicate that the current price decline is adequate to balance the market.  It may be that it will just take more time at these prices for an effect to be seen, just as it took several years for the gas rig count to decline fully.  But the lack of a producer response does suggest that further price declines will be necessary.

If prices stabilize or go down another $10 or so from here, I wouldn't be surprised if we see a substantial decline in the US rig count and capex, but continued production growth from the most efficient producers in the most efficient regions.

There is an OPEC meeting on the 27th and I we may get a substantial price move in either direction on next Monday.  Buying either calls or puts on E&P companies this week might be a good idea.

(All charts are from Baker Hughs rig-count or EIA.gov for production)

Historical comparison: The oil crash of the 1980s

For those hoping for a bail out from OPEC, it is interesting to consider the crash of the 1980s:

Setting the scene:
As background, oil exporting countries initially had a pretty poor deal from the western companies that came and extracted their oil.  The Anglo Persian Oil Company (later BP), Standard Oil of California (later Chevron), Standard Oil of NJ (Exxon), Standard Oil of NY (Mobil), Texaco (later bought by Chevron), Royal Dutch Shell, Gulf Oil (later bought by Chevron in 1984) would produce oil in the Middle East and bring that same oil back and refine it in their refineries, and then sell the gasoline in their own filling stations.  There was no standard exchange traded price for oil, so it was very difficult for the producing countries to know what was a fair price for their oil.  At one point there was a study that suggested that Saudi Arabia received less from their oil than the US government received from corporate income taxes on the profits that the oil companies derived from producing the Saudi oil.

The balance of power started to shift in the 1960s as new western companies like Armand Hammer's Occidental Petroleum, Mattei's Eni, Getty Oil tried to fight their way in by offering better contract terms to the producing countries.  Occidental Petroleum in Libya gave 55% of the profits in 1970.  The Tehran Agreement of 1971 established 55% profit share with a 35 cent price increase for Iran.  Libya, Algeria, Saudi Arabia, and Iraq subsequently push through a $.90 price increase per barrel.

Then it's off to the races...

In the early 1970s the prices were renegotiated again and again in favor of the producing countries.  Demand was increasing, and the Arab countries were voluntarily cutting output to gain negotiating leverage.  In the negotiations at the 1973 Vienna OPEC meeting the oil companies offered a 15% increase in price.  OPEC wanted a 100% increase to about $6 per barrel.  Remember that since there was no exchange traded oil at that time the price was wholly negotiable.  In the midst of this negotiation came the 1973 Yom Kippur war between the Arab states and Israel, in which the US sent supplies to the Israelis.  This was very unfortunate timing for Big Oil.

OPEC then unilaterally announced that they would be taking 66% of the retail price of gasoline at the pump as taxes.  They had been receiving the equivalent of about 9%.  They later also started refusing to ship oil to the countries that supported Israel, including the USA.  At this time all oil in Saudi Arabia was produced by US companies.  But in the next few years, many of the OPEC countries nationalized production, including Kuwait and Saudi Arabia.  Oil price went up and up.

OPEC official selling prices went from $1.80 per barrel in 1970 to $11.65 per barrel in late 1973.  The following decade was one of turbulence and high prices in oil, culminating in the second oil shock following the fall of the Shah of Iran.

But the time when OPEC could simply dictate the price was short lived.  In March of 1983 West Texas Intermediate, started to trade on the NY Mercentile Exchange, the first exchange traded crude (heating oil had been traded previously).  Producers initially switched to exchange linked pricing because the price was going up so fast.


The crash:
There is an old adage in the world of commodities: "High prices are the cure for high prices".  Demand was eroded by increases in fuel efficiency, and new supply was brought online, especially from non OPEC countries like Russia, the UK and Norway's North Sea.  The US land rig count topped out at 4,530 (Baker Hughes) in 1981.  This is compared to about 1,928 currently.  Most importantly, there were big investments and technical advancements that led to the opening of the north sea and deepwater production more generally.  There was also the North Slope of Alaska.  All these things were spurred by the high oil price.

Oil is a strange commodity because there is such a long gap between the time when an investment is made and when it pays out.  When you are producing copper or iron ore most of the costs are in operating expense rather than capex.  So a mine can be mothballed if prices drop, quickly balancing supply and demand.  With oil, the majority of the cost is in up-front capex.  Those wells drilled in the North Sea produced for years after prices dropped.  While it may be valid to point out that many of these wells presumably lost money, the fact was that this was a sunk cost, and they went on producing with the low price environment after 1985.  And the incremental cost of drilling additional wells after the production platforms were in place, seismic studies completed, pipelines built etc, was quite a bit lower per barrel produced than when the first wells were drilled.  So even further development was practical at the low prices.

As demand waned and world production increased the Saudi's tried to balance the market by cutting output.  Others were supposed to be cutting to, but in many cases they cheated on their opec quotas.  This chart is fascinating:

As the Saudis cut and cut most of the other countries both in OPEC and especially non- OPEC took advantage of them.  Keep in mind that the world oil production was only about 55 million barrels per day in 1985, so Saudi Arabia had capacity equal to nearly 20% of world supply.  When Saudi production dropped all the way to 3 mm per day, they decided to give in and turn the taps back on to hold onto market share.  This coincided with the plunge in prices in 1985.

Prices probably would have stayed even lower through the 1990s if the USSR production hadn't collapsed with their government.

The Aftermath:

The 1983-1985 price of oil (around $80 per barrel in today's money) was never again hit in nominal terms until after 2000.  In inflation adjusted terms it was not hit until late in the last decade.   Production in higher cost areas like the North Sea and Alaska, stayed strong even through the low price period.

Alaska North Slope production http://planetforlife.com/anwr/



How does this relate to today's situation?

You might make an analogy to 1985 for today's situation.  High prices spurred new technology and large-scale investment.  That investment has been in relatively expensive supply like deepwater, oil sands, tight oil ("shale").  It also spurred conservation in the form of higher CAFE standards, consumers preferring higher millage cars, switching from fuel-oil heating, more efficient jets etc.   In some cases it can be difficult to determine whether the motivation is cost or due to environmental factors.

On advantage compared to the prior situation is that much of the new source of supply has a relatively short production life, or at least the production of a new well declines quite rapidly from the first few months.  Therefore if the price plunged and companies pulled back on capex then the decline in production (or at the very least production growth) should be extremely rapid.

One thing is sure: it is hard to believe that the Saudi's would be willing to balance the market alone, as they more or less tried to do in the 1980s.  They would only agree to a cut if their was substantial cooperation from other OPEC producers.

There is another example that I want to look at as well, and hope to get a chance to post on shortly.

Breakeven Price

Just finished a work project and am going to get back into this a bit.  I haven’t really taken any actions since bailing out of Apache, Chevron, and FCX a while back, and buying a small amount of EOG.   The EOG purchase has only  gone down about 4% or so, quite remarkably.  I’m going to do a post on two historical comparisons that are interesting to think about and may be instructive to our current situation.  But first here’s an interesting chart from a Bloomberg article.  Its from Goldman, trying to identify the areas where drilling will slow and stop.  “Break-even” price is something that the sell-side E&P love to do, but it is sometimes quite hard to get a handle on for a number of reasons.  Here are a few I can think of off hand.

1)     A major part of the break-even price is services cost, which will decline as the price of oil goes lower, lowering the break even.

2)      Take away costs may decline as production stops growing, so the producers get a price closer to benchmark pricing.

3)      Learning is always increasing, and efficiency in terms of oil production per active rig or dollar spent has been on an uptrend in the shale plays for years.

4)      There is a wide range of economics within each play.  Companies that have pads set up and gathering networks in place have a much lower cost.  There are also differences in acreage quality and technical ability that will have an impact.  So if 50% of the rigs leave a play, it doesn’t mean it will produce 50% less oil over the long term.  The inefficient rigs will leave first.

5)      Exploratory drilling may be the first to shut down, and the development pad drilling may continue.  Thus the rig count may decline with little actual effect on production.

One broad take-away from this map is that the mid-continent regions are in bad shape.  Of the three major resource play areas, Bakken, Eagleford, and Permian, it is the Permian basin that is most at risk.  Ironically this is also the area that has seen a parabolic increase in production recently.  But within the Permian there are a wide variety of different sub-plays, with varying economics.

oil reserves 101

When a company reports it’s reserves, unless otherwise noted, it is talking about something called proved reserves.  This is the quantity of oil that has been identified in the ground, which they have the legal ownership off, that are deemed to have at least a 90% chance of being extracted with current prices and technology.  In order to report something as proved reserves their data must be audited by an independent reservoir engineering firm, just as the financial reports of a company must be audited by an accounting firm.  Typically most proved reserves will already have the producing infrastructure in place, but sometimes the infrastructure is not fully in place.  Because of this, proved reserves may be divided into proved-developed (PD) and proved-undeveloped (PUD).   In the event of a sudden decline in prices PUD reserves are much more at risk of being written off by the company.  This happened several years ago for PUD gas reserves in the Haynesville shale when the price of gas plummeted.  Proved-developed reserves are rarely written off because the money has already been spent to get the wells to production, and the operating cost of maintaining production is usually very low.  Proved undeveloped reserves can only be counted as reserves if the company has a reasonable expectation that they will be developed within 5 years (sometimes called the 5 year rule).  Because of the amount of work involved in doing  a survey of reserves, in companies make an annual “reserve report”, which states reserves typically as of calendar year end.

Other types of reserves:

Historically, the SEC only allowed oil companies to report proved reserves to investors.  This may have been to prevent companies from confusing investors and exaggerating their prospects to them.  But at the end of 2008 a rule change was proposed and later adopted, allowing companies to report “probable” and “possible” reserves.

Probable Reserves- These have been shown to have at least a 50% chance of being produced with current technology and at current prices.

Possible Reserves- These have at least a 10% chance of being produced with current technology and at current prices.

Sometimes reserves are also discussed in terms of 1P, 2P, 3P reserves.  1P is proved only.  2P is proved + Possible.  3P is proved + possible + probable.

Another change that the SEC has made recently was that certain catagories of oil were prohibited as being reported as reserves, including oil sands and shale oils.  This change was also proposed in 2008.

One area of confusion among people not familiar with the industry, is that sometimes they hear the term reserves, and think that this is a best guess for how much more oil can be produced.  This is not the case at all.  Reserves are oil that has been proven to be extractable.  Even if a quantity of oil is known to exist, it cannot be considered a reserve unless a company owns the right to extract it, and has demonstrated the technical and financial feasibility of extraction. 

OPEC stated reserves: Countries like Saudi Arabia have long reported the same exact proved reserve figure (260 billion barrels in that case).  This has led some to accuse them of just cooking their books.  They produce 3.5 billion a year and yet the number never goes down!  While they may indeed be adjusting the number for political reasons, they could possibly be adding reserves through engineering work to compensate for the produced barrels.  It is difficult to say, but if we look at OPEC proved  reserve charts, the chart for many countries look very suspicious.  Starting in 1986 OPEC began trying to use a formula system to set production quotas for each member country.  Reserves were a factor, and if a country had large reserves, it would help get it a higher quota.  For this reason many countries increased their stated reserves massively, as shown in the chart below.  Their reserves are not independently audited, like they are for a private-sector company.  It is not possible that these revisions were all the result of some overnight engineering.  Either the reserves were deliberately understated prior to 1986 or they were deliberately overstated after that point.  Also note the huge increase for Canada- this is when they started counting the oil sands as reserves.

Article is from http://www.theoildrum.com/node/7363

after the brutal sell-off, are E&P stocks a buy?

The 10% selloff in energy in the past three weeks doesn't seem so bad in comparison to the 7.5% decline in oil prices, but of course the equities had been declining faster than oil in the last weeks of September.  The Marcellus gas producers have held up particularly well, but that may be partly because of the Chesapeake sale to Southwestern of their southern Marcellus assets, which went for a nice price.  Oil producers in the unconventional plays need a relatively high price to make money.  Marcellus gas producers don't, or they'd be out of business.

If the oil price was going to stay where it is there are a number of decent buys out there, but why can't it fall further?  Supply has to come off the market or demand has to increase.  The market must be balanced.  The US seems to be doing its part on the demand side if booming SUV and pickup truck sales are any indication, but the auto industry on the whole is moving towards more and more efficient vehicles, and that doesn't seem to be changing.  China, the source of the biggest demand growth, appears to be slowing. Demand in oil tends to be very inelastic in the short term, so it is hard to see demand increasing and balancing the market in the short term.

On the supply side, we are now getting into earnings seasons, and it will be interesting if we hear about capex cuts in North America.  Due to the fast decline rates in unconventional, the production would certainly fall fast if they pulled back on capex in a significant way, but recently production has been growing with flat capex spending due to increasing efficiency by the drillers.  Many of these companies are hitting on all cylinders now, and I doubt we see them pull back unless the price goes down further.  They might talk up their willingness to cut capex in the event of a big price drop, but I bet most are taking a wait-and-see attitude for the moment.

We also have the November 27 Opec meeting.  Opec has a lot of competing interests now.  Nearly all the Opec countries are heavily reliant on oil revenues for their budgets.  But a few countries, like Venezuela, Iran, Libya, and Iraq, may be at risk of political collapse with prolonged oil price declines.  The situation in Algeria, Nigeria, Angola or Ecuador I don't even know enough to casually speculate about.  Russia (they are not an OPEC member) might be vulnerable to a severe economic collapse in a very big price drop scenario as well, especially given the western sanctions.  But many of the gulf states, like the Saudis, Kuwait, Qatar, UAE might be able to weather a rather long period of low prices, and if it derails US unconventional, Canadian oil sands, and deepwater to any extent, then that will put them in a stronger position for the long term.  If it causes a political crisis in Iran, then so much the better for the Gulf Arabs.  If I was in their position I might want to give the non-opec oil producers a good sweat, just like any prudent would-be monopolist, before balancing the market.  It will be interesting to see how they act.

weekly prices and other stuff

After a series of horrendous weeks in energy, last week was the worst yet.  The S&P was only down .75% for the week after Friday’s rally, but E&P stocks were down 5-6% on average.  Bakken companies were nearly totally correlated: down between 7, and 8.1%.  Whiting Petroleum now trades at 11x next years estimates and a 3.7x EV/EBITDA, and this for a company growing at a steady 30% CAGR for many years.  These estimates will likely come down with the retreating oil price, but the current $90 trading level for WTI certainly does not justify the fall in price over the past few weeks.  The declines are only rational if we believe the price will continue to fall, which unfortunately I do.

I find myself conflicted.  

The E&P companies I now own shares of, EOG and WLL, have both had phenomenal execution, and now trade at very low multiples.  On the other hand I have no confidence at all in the oil price.    But for now I am still resolved to hold these through earnings season. 

As a bit of an aside- on Thursday I also bought American Airlines stock amid panic selling that some attributed to the Ebola case in Texas.  In general, airlines have an inverse correlation with oil because fuel cost is over 30% of operating costs in a very thin margin business.  But this is only part of the reason I’ve bought AAL.  Along with E&P stocks, airlines are also extremely high beta, so they can become correlated with energy in the context of a general risk-off situation.  Airlines have also been selling off since July, and they tend to be extremely seasonal.  You never want to own shares in July and August, and they usually do very well in October through December.  Part of this may be because wall street tends to go on vacation in August, and it is hard to enjoy a vacation when you are holding airline shares.  The other reason to own them is that they are trading at 5.5x next year’s earnings estimates.  They might get to put a huge tax asset back on the balance sheet later this year.  I just mention this in passing, as I mentioned my CF fertilizer position earlier (which has not changed), because it is a trade that is energy related.

Saudi price cuts- the sell off continues

Saudi's sent a strong signal to the market by cutting their prices today.  An OPEC supply cut could make prices rebound strongly, but their meeting isn't until November 15.

Both US Crude and Gasoline inventories declined in the EIA report from yesterday but this has failed to slow the collapse in prices.  This is being compounded by the general market selloff and the failure of ECB to come to the rescue with QE.


Besides the shocking declines in the E&P stocks I would also call attention to the drill ships.  Both low and high quality drill ship companies are selling off as badly as the E&Ps or worse.  Transocean is down by over a third since its July peak.
 

Always volatile low-quality drill ship company Transocean (of BP-Horizon fame) is now selling at 1/2 book value.

 Higher quality Ensco is also dropping like a rock.

Schlumberger, the premium oil-service name has held up quite well, off only about 10% so far.

The oil majors have also pulled back by 10-20% off the highs.

I'm considering selling EOG, which is off by about 7% since I bought it only in August.  This would leave me with only WLL left.

With an OPEC rescue off the table for a little while at least, and inventory declines doing nothing to arrest the strong downward trend in prices, one last hope could be a short term rebound in the dollar, which has been strengthening for months now.  Lack of QE in europe might lead to mean-reversion for the dollar, and a weakening dollar is always supportive of oil prices.  The dollar has strengthened from about $1.39 to the Euro in May to about $1.26 today, an incredibly big move.

Trading positions review

I wanted to go over all my positions today.  I decided to sell out of APA today, with the continued deterioration in oil prices.  I am now only holding WLL and EOG, of which WLL is by far the larger position.  On the one hand I hate to be selling during such a strong pull back, but on the other hand it just feels to me like there could be quite some ways to go on the down side.

Chesapeake Energy (closed out):

I really should never have touched Chesapeake.  This is a company that is still recovering from the overly adventurous management of CEO Aubrey McClendon.  I still intend to do a post on CHK at some point, since it is a fascinating company.  Overall the trade wasn’t as disastrous as it might have been, since they did spin out seventy seven energy, which is worth about $1.58 per share at current trading prices.  Including the spin-out I netted 5.5% on CHK.  Had I held it I would now be badly underwater, with shares currently trading at $22.99 as of today’s close.  So on the one hand, I never should have bought this, but on the other, at least I ended up in the black by a bit.

Apache (closed out):

Overall this was a decent trade, with a 22% return not including dividends.  I bought it fairly well, and time will tell whether it was sold well.  I would certainly look at buying it back if we get a pullback or I regain some confidence in oil prices.

EOG (open):

I should have held off for longer, but this is a stock that I have wanted to own for a long time.  I may reassess after earnings.  The current position is relatively small.  I consider EOG to be the best managed oil large-cap E&P.  The chart does look ugly though.

 Whiting (open):

Whiting is by far the bigger position of the two remaining, at about 3x the EOG position.  I should have taken some off the table, as it has now pulled back off the highs by about 15%.  I intend to hold this through earnings on October 22 and then reassess.   Overall I'm still pretty deep in the black with a 38% net gain compared to the average acquisition price.

A few comments on oil prices going forward

I think there are two separate reasons for domestic oil producers to be nervous about the price of oil going forward.  There are two commonly traded oil price benchmarks that are the most heavily traded on the futures exchages.  West Texas Intermediate (WTI) is priced in Cushing Oklahoma and traded on the NY Mercentile Exchange.  This was historically the most important benchmark, but due to wild fluctuations in WTI most of the major producers have switched to Brent, a North Sea grade which is traded on the ICE exchange in Europe.

The WTI-Brent spread (the price difference between the two grades) had usually been +/- $3/bbl or so until 2010.  Please ignore the "QE2" marker on here which really has little to do with the spread.  I just used this chart because it is otherwise very nice.  In 2010 it grew due to production growth in the Bakken and Permian Basin regions, both of which had pipelines that fed Cushing Oklahoma, where there were several refineries.  So much crude was going into Cushing, but there was no effective way to get it all out and down to the mega refineries on the Gulf Coast of Texas and Louisiana.  This oversupply caused depressed prices relative to seaborn grades like Brent.

So recently two things have been happening.  The spread  has been collapsing, and is now only $4, down from highs of as much as $25.  I think a big reason for this is that the logistical constraints that created the spread have been largely alleviated by new rail capacity, and to a lesser extent new pipelines.  The collapse of this spread has been good for producers and bad for refiners.

The second thing that has been happening is the collapse in the Brent price.  Brent has been in freefall over the past few months, despite major turmoil in the Mid-East, which has historically been good for a supply scare.  Demand has been surprising to the downside and supply, mostly from North America, has been surprising to the upside.  US crude production was 8.6mm bbl/d in August, and EIA is now projecting 9.5mm boed average for 2015.  The US really does have a shot at becoming the number one crude producer in the world in 2016 or 2017.  Meanwhile EIA and other forecasters have been downgrading world crude consumption growth to about 1% per year, which works out to about 1mm bbl/d.  So US projected supply growth will fulfill total projected world demand growth if non-US production stays flat.  Meanwhile there is a whole lot of oil out there that is very economic to produce at prices far lower than the current price.  Libya, Iran, and Iraq all have tremendous capacity to grow output if they were not constrained by political turmoil.   It never pays to underestimate the odds of political chaos disrupting production in ME or Africa, but production capacity does certainly have the potential to grow in that region, even in a period of falling prices.  On the opposite side of the ledger there is Russia, which is currently the largest producer.  Their production has been growing since bottoming in the mid 1990s but is now showing signs of flattening out due to underinvestment.  It could fall further if sanctions are widely expanded.  This is not a very likely scenario, but it remains a possibility.  Even the possibility of sanctions is a disincentive to investment.  The current, relatively mild sanction regime is also keeping the most competent service firms out of the area.

In order to slow production growth the market needs to send a signal to the fast growing American producers to slow down.  Price trends can last for very long periods, because capex cycles are so long.  Breakeven price with a 10% cost of capital is probably around $40-80/bbl depending on the region.  If we do get a fall in price, supply may be somewhat more elastic than in the past because tight-oil capex can be turned on and off remarkably quickly, as was demonstrated in shale gas in 2009.  Tight oil wells also decline more quickly, so declines in capex may be followed by production declines relatively quickly.

And that chart is ugly, ugly, ugly.

Then there is the other potential piece of bad news for US producers.  Although the brent/WTI spread has tightened recently, to their benefit, it is in some danger of blowing out again.  Supply constraints have been effectively alleviated by rail capacity.  But there is a major potential constraint ahead.  The US has now displaced substantially all light oil imports, and it is illegal to export crude oil from the USA.  Now there is still the possibility of "lightly refining" oil and exporting it, as they are currently doing with some condensate (extremely light oil that is in gaseous form in the reservoir).  But this issue may well cause a blow out of the Brent/WTI spread again.  Congress may come to the rescue by passing a waiver to this very outdated law, but one should never count on congress to do anything.

This chart shows how small US imports of light oil are.  For domestic production to displace more imports, it would have to be displacing heavy crudes.  This would require substantial discounting because the US refining system is set up to take large amounts of heavy crude from Canada, Mexico, and Venezuela.   Note that the above chart can give a misleading impression that the US depends on imports more heavily than it actually does.  We are now a net exporter of about 4 million barrels per day of refined products and other non-crude petroleum liquids like propane, so net imports of petroleum products are only about 4.6mm bbl/d (as of June according to EIA).  This is down from a peak of 13mm bbl/d in 2007.

Might OPEC come to the rescue and cut supply?  OPEC supply has been flat, and the Saudi's have been dutifully balancing the market, so a production cut in the short term may well happen.  OPEC really hasn't ever had terrific supply discipline.  The Saudis will balance the market by taking off or adding 1 or 2 million barrels a day, but I'm not sure OPEC can support the price of oil over a long period.  It is always risky to be too short oil during a decline, because it only takes an announcement by the Saudi's to send it back up.  Right now it is also important to note that about 3 mm bbl/d of OPEC capacity is "disrupted" by political turmoil.  If that were to come back online (a big if), it is hard to see Saudis cutting by that much to balance the market.

So far US land Rig Count is Stable - Prices only really started to drop three months ago.  But spot prices have plummeted for drill ships, particularly for deepwater.  Look at the prices of Transocean or Ensco over the past few months.  According to some reports the breakeven cost for deepwater oil is now higher than US shale, although this breakeven price might come in if we have a collapse for day-rates on the rigs, a major factor in deepwater drilling costs.  The sharpest capex cutbacks may come in Canadian oil sands, North Sea, US Gulf deepwater, deepwater Brazil, and deepwater West Africa.  These regions may already be higher cost than tight oil.

So overall, as you can probably tell, I'm a bit nervous on oil prices, and the E&P stocks tracked on this blog all have tremendous correlation with oil.  But I also hate to sell WLL and APA badly.  EIA US production numbers have been great, so I think earnings season could be a positive catalyst for some of these stocks.