Atticvs Research

Long only, deep value, medium-term horizon, oil & gas
Atticvs Research
Long only, deep value, medium-term horizon, oil & gas
Contributor since: 2007
You say that the global oil glut should be about 300 million barrels in mid 2017. Currently the global oil glut is 1 billion barrels and it is growing at about 1 million b/day. In the second half of 2016 it should reach about 1.2 billion barrels and then it should start to decline. That said, I don't think people should be overly concerned about the glut.
First, oil pricing is driven in the main by the marginal production and once we get into late 2016, when demand begins to overtake supply, the oil price should drift upwards, I'd guess to around $50 or possible higher.
Second, China has a program to increase their SPR over the next few years from the current 200 million barrels to 500 million. This will mop up 300 million barrels from current surplus inventories, leaving the net surplus at about 900 million barrels.
Third, 900 billion barrels is not a crazy-high figure. With global demand running at 95 million b/day, it represents about 9.5 days of demand. In a world where spare global production capability is tight and when a game-changing blow-up can easily occur in one or more middle-east oil producing countries, the pendulum can easily switch from worries about too much oil to worries about too little oil.
Watch in particular for developments in Saudi Arabia in the next year or so; its budgetary figures, notwithstanding some austerity measures, coupled with its mix of disaffected sects and more aggressive policies by King Salman and his sons, make alarming reading. The situation is untenable, something will give.
In my opinion, we are likely to see significantly higher oil prices over the next 2-3 years and with valuations so low in the oil sector, we now have an excellent investment backdrop.
Richard, are you able to explain with reasonable clarity how the "non- controlling interest" is calculated in the P&L? I assume it's due to the company not owning all the rights to certain production etc... but in this case it begs the question as to why the non-controlling interest is not already excluded from the production and revenue numbers to begin with. Inherent within my question is the implication that the EBITDA multiples that are used are even more stretched from a valuation perspective if one backs out the non-controlling interest from the production and revenue and the EBITDA data at the outset.
In Parsley's most recent quarter the non-controlling interest group took a full 65% of the combined after-tax profit leaving Parsley shareholders with just 35%. Hence, unlike most companies, this non-controlling interest subject is a very substantial item for Parsley shareholders.
At a minimum I'd like to see some transparency regarding the non-controlling interest calculations and in particular I'd like to know if there are any family ties between this non-controlling interest group and management and/or the major family shareholders. Too many times I've seen opaque arrangements ultimately hurt common shareholders.
Thanks for whatever you can provide.
A problem with Parsley Energy (PE) is that shareholders don't actually know what they really own or what they are likely to earn in the future because the "non-controlling interest parties" take such a large piece of the pie.
For example, during Q3 2015, the company reported that - inclusive of non-controlling interest parties - they made $2.643 billion profit after tax. However, of this a full 65% or $1.734 billion is backed out of the P&L because it goes to the non-controlling interest people. This leaves $909 million, or just 35% of the total after-tax profit, for PE shareholders.
I have examined the SEC filings but alas they contain no explanation as to how the non-controlling interest is calculated. Furthermore, I have written to the company but they have declined to provide any related information.
I think it safe to assume that what is going on with the Parsley reports and filings, including quarterly earnings reports etc, is that PE is including in their production and sales date numbers relating to production that does not rightfully and wholly belong to PE shareholders.
Normally, when a company such as PE has a partial interest in a particular oil well they only include in their P&L that portion of the production which is rightfully theirs. But PE is, for reasons only they know, apparently opting to publish accounts that suggest they have much greater production and revenues and profits than actually belongs to Parsley shareholders.
This would not usually be an issue for shareholder if the portion of after-tax profits attributable to non-controlling interest parties was negligible. Unfortunately this is far from the case. As highlighted above, during the most recent quarter the non-controlling interest group took a full 65% of the after-tax profits leaving only a 35% minority share for PE shareholders. Note that whilst the allocation to the non-controlling interest group changes from quarter to quarter it is always a large number.
I wouldn't get too excited about the upside potential for PE shareholders. The problem is that, as a PE shareholder, you won't know how much of the supposed upside goes to you and how much ends up going to the non-controlling interest group.
No discussing whether $60 won't be a ceiling for now, surely we all agree. The title of the article is that oil is setting up for another leg down, that's the discussion. WTI was just over $52 when the call was made.
Oil prices are largely determined by global supply/demand metrics. As well as Iran coming back, and demand growth of 1 million b/day for 2016 on top of 1.5 million b/day in 2015, you've also got diminishing production in many areas that already underway (i.e. not just a prediction) such as in Mexico, the North Sea etc. Global picture is definitely tightening in late 2015 and into 2016.
Shale producers are unlikely to show production increase of any significance next year because of worsening financials due to a lack of hedges compared to 2015 i.e. look for more cautious management of balance sheets next year. Besides, shale production is only around 4.5 million b/day. That's less than 5% of global supply. A 100k or 200k b/day delta won't make a difference one way or another, that's just 0.1% or 0.2% globally. The delta really is insignificant.
Other than a temporary spike - like the Greek/China/Iran triple headline combo - no further leg down below current levels of any significance. Instead buy the dips from here on.
Ok, but WTI on Monday was near $52, similar to the Tuesday. Whether you choose Monday or Tuesday price, which were largely the same, I still don't see the down leg you are calling for from these levels. It just doesn't make sense to me.
This article is dated July 8. WTI closed yesterday July 7 at $52.33. Aside from a temporary small spike lower driven by an event such as the repeal of the Iranian sanctions, WTI is very unlikely to experience another leg lower from these levels.
In early 2015 WTI dipped to the $45 region. At that time there was a global surplus supply/demand of 2 million barrels per day. Since then global demand has picked up by 1.5 million barrel per day. Iranian production will come in at 600k b/day and in 2016 we're looking at demand increasing by 1.0 million barrels a day. Essentially, in early 2016 the global supply/demand picture will begin to move towards balance.
Against such a prospect the idea of WTI taking another leg down from the July 8 level, the date of this article, with WTI now trading around $52.50, is highly unlikely.
I think we all agree that $60 should be a cap for now.
However, with regard to any softness into or below the low $50s these are likely to be very short term and great buying opportunities and from here on I'd recommend buying the dips.
Most of the fracklog is a natural phenomenon due to the migration towards multi-well pad drilling away from single well drilling. As of September 2014 - i.e. before the oil price downturn - the entire backlog was approx. 3,000 wells. That would suggest that a maximum of about 1,700 of the 4,700 wells may come back into the market if producers choose to bring 100% of the true underlying fracklog into production. That potential 1,700 wells does not translate into a big Boe/d production boost.
As usual, the media is making a mountain out of a molehill.
The major problem with Parsley is that, as a shareholder, you don't actually know what you're getting. That's because of the existence of various unexplained deals with outside parties, possibly relating to the Sheffield family. These outside deals hit the P&L in the form of the "Non Controlled Interest". Nobody would bat an eyelid if these hits to the P&L amounted to say 3, 4 or 5% of the Net Income but, unfortunately, they typically represent a huge proportion of the Net Income. Example, for the year to December 2014 the Net Income before Non Controlling Interest was $56.7 million. From this, the Non Controlling Interest people took a whopping $33.3 million leaving just $23.4 million Net Income for Parsley Shareholders. Every quarter it's the same story, the 'take' by the Non Controlling people varies but always it is a very material figure and it is never explained.
It's fine and dandy speaking of such and such acreage, or hedges, or % oil or whatever various assets. However, Parsley shareholders do not get the profits on these various assets, they only get a significantly reduced portion of the profit and essentially - unlike other companies where the shareholders effectively own 100% of the assets - Parsley shareholders only partially own the assets.
At a bare minimum, I would expect for transparency purposes that Parsley would explain in reasonable detail how the Non Controlling hit to the P&L is calculated each quarter, but they don't, they never do.
Ultimately, Parsley shareholders do not know what they own and they cannot form any reasonable view as to what the future profitability might be because of the sheer size of the take by the Non Controlling group.
Overall good work Joseph. I found his assumption that capex would increase year after year from recent high levels to be a glaring blunder.
However, I do agree with Einhorn that PXD is richly valued. The rich valuation relates in good part to the ~10 billion potentially recoverable resource the company has. That 10 billion potentially recoverable resource does require higher oil prices than we have today before it all becomes economic. How much of this resource is economic at $70 is questionable.
The product mix at PXD is only 51% oil. Sales during Q1 2015 before taking account of hedges amounted to $29.28 per Boe. Mid point guidance for Q2 2015 is LOE $14, DDA $17, G&A $5, Interest $2 and Ad Valorem taxes about 8%. All told this amounts to over $40 per Boe. Against sales revenue per Boe of only about $30, PXD is a long way from break-even without the benefit of the hedging program and the company says that they don't expect further big cost reductions from those already achieved by Q1 2015. The problem is that hedging programs are temporary and, with a product mix of only 51% oil, it is questionable if PXD can get to break-even within the next couple of years without substantially higher oil and NGL and nat gas prices.
Another mistake in Einhorn's analysis was in citing Whiting as a possible short.
1. Unlike PXD, Whiting will be cash flow neutral (including capex) and profitable in Q3 this year without any hedging benefit. This is based on Whiting's current guidance which is consistent with its Q1 2015 results. It helps that Whiting is 81% oil. In the next couple of years, as Whiting replaces old production with more recent highly efficient wells thus skewing the costs per barrel much lower, it is inevitable that Whiting will be highly profitable with oil at Einhorn's strip pricing and without any hedging benefit.
2. From Einhorn's beloved "proved reserves Vs market cap" perspective: PXD has proved reserves of 745 MMboe (oil 318 MMbo) against a total market cap of $24 billion. WLL has proved reserves of 780 MMboe (oil 644 MMbo) against a market cap of $7.5 billion.
Einhorn is making a fairly easy call on Pioneer but his inclusion of some of the other companies as possible shorts, especially Whiting, shows a significant lapse of judgment, or knowledge or just plain hard work, on his part.
"Warren Buffett is famous for saying "Rule No.1 is never lose money. Rule No.2 is never forget rule number one.""
Rule number 3: There are no rules.
For clarity and transparency I prefer to use a certain assumed WTI pricing, multiply the production by it to arrive at a product sales number and then add in the hedge gains/losses as a separate line item to arrive at total sales. It's how I've seen other do it too. See summary P&L above.
Yes, agree about the reserves calculation i.e. simple average of 1st day price for prior 12 month. I had based on a Bloomberg article which I've now corrected.
Banks: A credit facility review is done for the bank by their account relationship manager. To retain the confidence of the bank, and keep the relationship solid, it is critical for the CFO to make sure that the a/c relationship manager is aware of what is likely to occur in the next 6-12 months, both good and not so good. This means that whilst the reserve valuations would be done using the industry standard PV-10 calcs both the CFO and the a/c relationship manager would also know what those reserves would look like using lower oil price assumptions. Together they would try and manage the situation pro-actively. That's why recently you may have seen some companies restructure their credit facilities even though the facility wasn't formally due to be reviewed. A bank will always want to know that it has protection and security for its loans in the real world. So, they will have their numbers, and modified numbers, and they will also take on board a view on the outlook for the industry. It's not a precise science but it should all be ok so long as the bank doesn't feel uncomfortably exposed.
Yes the unrealized gains/losses from open hedge contracts are booked each specific period to the P&L and B/Sheet in the SEC filings.
However, the cash benefit or cost on settlement of each of the hedge contracts is a different thing. That cash benefit or cost only comes into the cash flow when the individual hedge contracts are realized on maturity. That's why I calculated that OAS will have a cash benefit of $320 million in 2015 relating to the hedges that mature in 2015, and $63 million in 2016 relating to the hedges that mature in 2016.
Additionally, because these 'open' hedge contracts at December 2014 relate specifically to 2015 and 2016 they will be excluded by analysts from the normalized earnings as recorded in the 2014 SEC filed results and will be worked into the 2015 and 2016 earnings as part of the earnings normalization process for those two years.
As to the calculations, you have to calculate each hedge contract separately and compare to the assumed WTI oil price at settlement. As stated in the article, the assumed WTI price for 2015 is $54 and for 2016 is $63. So, by way off example the 5,263,500 barrel $90.81 swap hedge maturing in 2015 will have a cash profit in 2015 of $36.81 per barrel = $179,749, 435 whereas the 263,500 barrels 3-way swap contract will only have a profit of $20 per barrel (the diff between the $90.59 floor and the $70.59 sub-floor) = $5,270,000 and so on for each of the hedges. Working off $54/bbl WTI gives you a total cash profit of $320 million in 2015 and using $63/bbl WTI in 2016 gives a total cash profit in 2016 of, coincidentally, $63 million.
All, thank you for your comments. I agree with many sentiments expressed although, from my many years of working experience in this arena, I am confident that Whiting's tight liquidity situation is both temporary and entirely solvable.
Gordon Haave; refer to SEC filings, the 10ks and Qs. Point taken about the concerns about liquidity, I've requested Seeking Alpha to amend the bullet point. Be aware that covenants with relationship banks are usually waived when the company demonstrates solid operational and profitability progress. Whiting is doing this, a waiver can be expected. Besides, the long term notes market is still available at reasonable prices.
rgtichy; From what I've read it seems the CEO, who is already into his late 60s, doesn't have the stomach for a fight that may last a couple of years. Additionally, whilst Whiting does have very good properties and an excellent team in place, I suspect the CEO doesn't have full faith in the VP Finance - he obviously should have done much better with both the hedges and with the funding going into the Dec'14 Kodiak acquisition. I agree (and mentioned) that reserves will be lower after Q1 but even for a severe cut of say 50%, that still leaves Whiting with a highly respectable ~400 million barrels of proved reserves and, once that Q1 cut is out of the way, the horizon will be clearer for buyers to enter the sector; both acquisition buyers and retail investors in the shale sector.
cirriusgator; Me an oil perma bull, I think not. I warned of impending lower oil prices in Nov '13;
and again in late April 2014 when I sold 100% of my oil holdings;
Q: If April 2014 was a good time to sell, what will be a good time to buy?
A: I think the Q1 results, with the combination of reserves write-offs and oil inventory concerns, may lead to April being the low point for oil stocks and I think that should be a good time to buy for the long term.

In anticipation of this, I've been doing some diligence work on the sector. I only bought into Whiting on Friday March 6 because the market was off heavily that day and it seemed from Whiting's stock performance that something was up, hence I bought, and ok got lucky in a sense. Longer term I strongly prefer that Whiting not get acquired because the upside for the stock over the next year or two is much greater than any acquisition premium in this market.
Other people's comments about increased borrowings going forward;
Over time borrowings go up in absolute terms, that's why I refer to the relative borrowings being stable to turning down for Whiting over time via the Debt/Equity ratio etc. To stress test Whiting's balance sheet I already used bigger capex figures for 2016 and 2017 than is likely to occur. There are swings and roundabouts, overall Whiting's liquidity is fixable and manageable. As usual, the scare talk is overdone.
Again, thanks all for your comments. Appreciated.
Michael, as you point out, there is more available storage than some commentators would lead us to believe. However, we still have a problem.
1. Physically and practically we cannot use all the boilerplate capacity. The absolute crunch, if there is such a thing, may arrive in about 12-15 weeks.
2. However, the situation isn't actually binary i.e. it won't be a case of "we're ok until we hit the max storage point". Not all storage is equally priced and pricing matters.
Reuters reported a few days ago that Gulf Coast lease rates are now rising to $1.20 to $1.25 per barrel per month. For the storage play to work properly the current contango would need to grow deeper. Recently, the contango between front month and 1-year has been running at about $10. It needs to grow wider either by the spot price falling or by the forward price rising.
As more storage is taken up week after week Gulf Coast lease rates will continue to rise and put more pressure on contango. Unless the forward oil prices rise then the spot rates will face pressure to the downside. The size of the oversupply (too much for slightly higher demand to mop up) plus the fact that no domestic producers are doing or even talking about cutbacks implies the risk is to the downside.
A change of the export laws would help but political solutions don't typically arrive until we reach or pass an emergency point. We're not there yet.
Whichever way you slice it, we face a difficult period ahead.
BCEI says it has hedged 60% of 2015 oil production equating to a hedged average of 10,000 B/day. This implies 16,667 bpd production - for oil only - for the full year.
Some of the hedges are straight swaps, which is good, but the greater part of their hedging is via 3-way collars. The problem with 3-way collars is that the "short floor" segment causes the company to be unhedged below that short floor. For example, in Q1 2015 BCEI hedged 6,500 b/day with a 3-way collar incorporating a floor of $84.32 and a sub-floor of $68.08 (refer to the hedging schedule in the article above). Assuming an average WTI price during Q1 of $50, this means that under this specific 3-way contract BCEI would receive $50 WTI pricing (less say $12 differential) plus $16.24 from the 3-way swap ($84.32 less $68.08) i.e. $66.24 less say $12 differential, or about $54/bbl net.
I've run some quick calcs, incorporating all of BCEI's swaps as well as all the 3-way collars so as to get an idea of BCEI's oil pricing for the full year 2015. If you assume, for simplicity, that production will be flat at 16,667 b/day and that WTI will average $50/bbl for the year and that differentials will average $12/bbl, then, on a full year 2015 basis, BCEI will receive approximately $56.60 per barrel.
Under similar $50 WTI pricing for 2016 the picture would be worse because, whilst BCEI does have some fixed price swap hedges for 2015 (with pricing in $93 to $95 range), it has none for 2016.
I'd guess that under flat $50 WTI pricing for 2016 that may equate to net pricing in the low $40s for BCEI.
However, in reality I think it fair to expect WTI pricing to be higher than $50 in 2016 even if not by much.
In the present weak oil pricing environment, the (startling) $13 Wattenberg differential will hurt players such as SYRG, PDCE and BCEI. All told, reserves will be written down, drilling inventory will surely be reduced, liquidity will dry up and so on. The upcoming earnings season will be very interesting with particular interest in Q&As on conference calls.
Whilst acceptable funding criteria has dramatically tightened in recent weeks, and banks are stress-testing client borrowing proposals using their own, very conservative, oil pricing assumptions, I still think that most drillers including SYRG should be ok in 2015 from an overall liquidity perspective. But the picture for 2016 looks a lot more daunting because drillers are overly reliant upon a decent rebound in oil pricing by 2016 and, in a continuing weak price environment, banks will never give you the desired umbrella when it's still raining.
Whilst I wouldn't short SYRG because there's always acquisition risk for small companies, I'd certainly agree it should be given a wide berth for now.
Most of us here are supporters of US shale and we get the upside potential. In fact I sense that many are a little biased towards the upside. So that ultimately we may make better investment decisions, it's very important that we do look at the bear case.
However, if this is "the main bearish thesis on crude", where is the narrative on the several new supply projects coming online in the GOM this summer, where is the narrative on the strong growth in low-cost Iraqi production some of which we've already seen recently with more happening during 2015 and thereafter, where is the narrative on low-cost Iran coming back into the fold, where is the narrative on middle-east countries cutting budgets as indeed many will thus negating some of their needs for higher oil revenue, and where is the narrative on many other multi-year long-term projects which were costly but have low cash costs at the operation level and so on.
Would appreciate some or more big picture arguments to support the titled article "the main bearish thesis on crude", thanks.
I don't wish to be their defender, but why blame the Saudis, they've actually done nothing at all. Zero. Nada. It's the shale drillers and other high cost producers that should be slapped around - they pumped more and more and more and more oil out in a completely mindless fashion as if $100 oil was going to last forever. Supply and demand always matters.
A very important sub-topic not addressed here is the impact that negative reserve revisions will have on drillers borrowing bases with their banks. Granted bank borrowing are mainly related to PDs. However, considering the dramatic slowdown in capex and thereby in new wells being drilled in 2015, plus the fact that 2015 production from existing wells will reduce PD reserves, it stands to reason that PDs going forward during 2015 will fall significantly. This has huge importance for drillers who are, or will soon be, heavily reliant on bank revolvers for liquidity. Clearly, diminishing PDs lead to reduced borrowing ability. In an ongoing low oil price environment I really cannot underestimate the importance of this last point especially for companies with already high borrowings and weak balance sheets. For sure some drillers will suffer enormously as 2015 unfolds and as hedges are burned off. Many investors seems to think that this harsh reality may not apply to their company, time will tell, there is real pain ahead.
Separately, could I ask you to please insert a visual color code (not words as all the colors seems pastel to me) to the first 2 schematics as it isn't clear to me what it what.
"The good news is that Sanchez has hedged about 65% of 2015 revenue at $90 oil..."
This is incorrect.
The hedge program incorporates a large amount of contracts that Sanchez calls 'enhanced swaps'. Under these hedges, Sanchez is hedged at about $91-$93 at the upper side but with a floor of $75. This means that these contracts do not provide protection below $75. As with most companies, beware of taking all their presentations at face value, some creative wording is included.
I would argue that the oil super-cycle is over, at least for now. I cannot see the oil price going back towards $100 any time soon (except for the briefest of spikes) and I'd say about $70 will be the ceiling for the next few years.
A major issue is that shale oil has become a victim of its own success.
Because of advances in the fracking drilling and production process, the shale drillers are in a position to produce, annually, an extra 1 million barrels per day with oil at $80/bbl. Also consider improvements in deep sea drilling processes and with oil sands, production ramp-ups in the GOM and from Middle-East countries that have been off-line, it's hard to justify higher prices in a continuing low growth global environment with cheaper oil coming from multiple sources.
Looking purely at the Saudis, the traditional Opec balancer: If Saudi Arabia cuts its oil production in order to temporarily shore up oil prices what it is effectively doing is giving away production of that same 1 million barrels/day to other producers such as shale etc. That's all very well for one year. But after 2-3 years this process of attempting to maintain high prices becomes insane for Saudi Arabia, especially when you consider that it now exports a significantly smaller percentage of their production than they did in the 1980's when production volumes were similar but when internal oil consumption was much smaller (population growth etc). All they'd effectively be doing is, year after year, creating a price platform for other producers such as shale to take away another 1 million bpd of market share. It just doesn't make sense, they've got to fight for market share.
There is an oft cited argument that says the Saudis need to boost revenues in order to fund their social budget. This argument is invalid. Their social budget is awash with subsidies and appeasement payments aimed at keeping segments of the population in check. Essentially, that's what always occurs when a country's budget revenues are aplenty. However, significantly lower oil prices give the Saudi government ample excuse for dramatically cutting back on overly generous subsidies and thereby then can re-set their budgets to a lower level that can then be managed prudently for several years thus maintaining social and fiscal harmony. It's what they did in the 1980's and there's every reason to anticipate it to occur again now.
In essence the Saudis have no option but to fight for their market share by maintaining production for the next few years. The natural supply-demand outcome is the end of the super-cycle with oil prices capping out at a lower price ceiling that we're all become used to in recent years.
Besides, if you look at the longer-term history of oil prices they have always been followed by periods of lower oil prices and I don't think this time should be materially different.
Hi Michael, good article and agree WLL stock should have long-term potential when the dust settles. I had hoped WLL would have pulled the KOG acquisition deal because ultimately they could acquire far better assets at significantly lower prices after the oil price plunge, but we are where we are.
Personally, having cashed out all my shale oil stocks in April/May 2014, I think it is still too soon to buy WLL for the long term and I prefer to wait until WTI breaks below $50 before looking to buy any shale stocks again except for the occasional quick trades. Most probably there will be a typical stock market pull-back in H1 2015 that coincides with WTI being well under $50 that will throw up a really good buying opportunity.
On my back of envelope calcs, I come up with different market cap and EV numbers for WLL than you are using in this article. Unless I'm mistaken, the market cap should be 119m shares plus 48m shares to KOG shareholders (not yet shown on sites such as Yahoo because the acquisition closed after the qtr 3 10Q report date) x $34 per share = about $5.7 billion.
And add the WLL debt of about $2.76bn and the KOG debt of about $2.25 billion, total $5 billion to the $5.7 billion market cap (above) to get a total EV of about $10.7 billion.
We have an interesting year ahead for the stock market with interest rate hikes and for shale and oil stocks in general. A lot of money can be made, and lost. Good luck.
The picture is actually significantly worse than implied in this article. For example, you say that in the Bakken Continental would achieve IRRs of 30% when "oil" is $70/bbl but then you correctly lament that WTI pricing is currently below $70.
However, Continental does not receive WTI pricing for its oil sales, it receives WTI less the regional differentials. In the case of the Bakken, the differentials are currently $16/bbl. That means that, based on a WTI price of $56, Continental now only receives $40 a barrel. This is miles away from the $70/bbl 30% IRR price cited by Continental.
Pouring cash into drilling new wells in the current pricing environment Continental is questionable. It is understandable that they are now cutting back their 2015 capex programs. I believe we will see a lot more capex cutbacks across the industry during the months ahead.
Continental's decision to liquidate their entire hedge program was clearly a very poor decision. It's actually hard to understand why any shale company, not just Continental, would run such a reckless risk given leveraged balance sheets and exposure to lower-cost producers in the Middle East.
The oil price weakness is primarily caused by the US shale producers dumping 5 million B/day onto the market. For the first few years, shale production had no material impact on price because of large Opec outages. But this year this equation changed when Libya and Iraq came back.
Oil demand is highly inelastic and the current oversupply is having a disproportionate downward impact on the oil price.
This downward spiral is set to continue into 2015 because shale wells and other production projects already funded and near completion will, when complete, pump more oil onto the fire.
Look for oil to bottom in H1 2015 at prices much lower than today, probably below $40. Think 'cash costs' of production.
A great investment opportunity will be available but only for those who wait. In the meantime a lot more hurt will occur. Play with caution.
A base case of $85 for 2015 seems awfully high. It would be interesting to see the NOG estimates for 2016 using $60 WTI. By then, with less obfuscation by temporary hedge programs, we will get a better view of the underlying business. I'm not saying that WTI will be $60 in 2016, but I'd sure like to test the model before committing precious capital. In my view the high oil prices of the past couple of years were an aberration supported by high Opec outages and we won't see those prices again for quite some time now that shale production volumes swamp the Opec outages.
Given the ongoing negative Bakken differentials of about $10/bbl doesn't this mean that WTI would need to average $75/bbl for CLR to hit the $65/bbl oil price mentioned. I suspect we'll not see WTI averaging $75 for some time because that price would be an open invitation to the shale drillers to take market share away from producers such as Saudi Arabia and, considering the lines being drawn, I don't see that happening anytime soon.
Hamm's move to cash out the hedges around $80/bbl doesn't look like one of his best decisions.
APC is a fine company but, with WTI likely to break below $60 in the next few months and possibly spike much lower, the risk-reward says it's wiser to wait until early 2015 before considering buying.
US shale has added ~4.5 Mbo/d to the global picture during a very short time frame. Against this backdrop, the fact that global oil prices didn't soften during 2012 and 2013 was an aberration. During this time frame, significant price support occurred because of the amount of outages by large global suppliers such as Libya, Iraq, Iran and Nigeria. With production by Libya and Iraq having been reinstated in 2014 it became inevitable - and entirely logical in my view - that we would get some significant downward pressure on oil prices during 2014. I wrote about this in April:
Unfortunately, the situation is exacerbated by slowing economies, by even further efficiently improvements achieved by the shale drillers, by continuing plans by the shale drillers to increase production during 2015 (E.g. Whiting guides 20% production increase in 2015 even with flat Capex) and the picture is also worsened by some speculative flows out of the space.
I have no doubt that things will improve.
However, first I feel it necessary for the shale drillers to collectively show negligible production growth for 2015 or, better, to show flat production.
Alas, much as I like all things shale, we're not there yet in my opinion.
- When QE1 ended in 2010 the Federal Deficit was running at $1,290 billion.
- When QE2 ended in 2011 the Federal Deficit was running at $1,300 billion.
- Currently the Federal Deficit is running at $483 billion.
- That's a Federal Deficit funding improvement of over $800 billion.
- Meanwhile QE Infinity added (only) $25 billion monthly towards the end of the program.
Some people are over-reading the effect of the Federal Reserve bringing QE Infinity to an end because of how markets reacted after QE1 and QE 2 were concluded. Against a Federal Deficit funding improvement of over $800 billion, the end of QE is largely a non-event.
People are over-reading the effect of the Federal Reserve bringing QE to an end. The QE program is now adding only $25 billion of liquidity to the system.
- When QE1 ended in 2010 the Federal Deficit was running at $1,290 billion.
- When QE2 ended in 2011 the Federal Deficit was running at $1,300 billion.
- Currently the Federal Deficit is running at $483 billion.
We now have a Federal Deficit funding improvement of over $800 billion compared to 2010 and 2011.
Given this $800 billion improvement in Federal funding needs, it's silly to expect the removal of a comparatively miniscule $25 billion of QE liquidity to cause markets to tank.
The end of QE isn't a good thing or a bad thing, it's just a non-event.
Without doubt the long-term picture for oil is positive. The problem lies in the short-term.
If Saudi Arabia and Kuwait wish to push back against the fracking train in order to maintain their overall market share, then, in the short term, there is nothing stopping them doing so. They can drive down the oil price to the point where they force a cut-back in shale drilling, they have the low-cost oil and the financial flexibility to do so.
Given the efficiency improvements that are taking place in shale drilling, it will surely take a further significant fall in the oil price for drilling cut-backs to occur. And just as oil spikes overshoot on the upside we should certainly expect oil to overshoot on the downside i.e. don't expect the price slide to conveniently end at the first stop where rational logic would suggest. Markets, including the oil market, are irrational. When you put everything together there is potential for oil to down to levels that most of us here would consider alarming. Alas, I think this will occur.
The good news is that when (not if, when) oil spikes a lot lower, and when the drillers consequently make substantial cuts to their 2015 capex programs, the oil price will stabilize and that should represent a tremendous buying opportunity. In the meantime we have to see more pain, unfortunately a lot more pain.
Pay no attention to current broker estimates. Throw them out. They will be revised substantially to the downside over the next few months.
My guess, and it is a guess, is that we will see the oil price hit bottom and turn north within a few months. But if the shale drillers ramp up production again later in 2015, as well as Iran coming in from the cold, don't be surprised to see another oil price wobble in late 2015.
I expect we'll see many oil pricing peaks and troughs over the coming years.
Hard to see Petrobras gaining 50% when most pundits are forecasting lower oil prices ahead. Normally lower oil prices equate to lower stock prices for drillers, not higher.