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.