Saudi Arabia, Russia agree oil output cuts until March 2018

MGL Comment
Oil's near 2% rally on this news is mainly relief that the two largest producers could agree the obvious. Rosneft, crucially, said the other day they would abide by any instructions they were given. The 'do whatever it takes' line from Falih is a tough ominous, it is suggestive that Russia and Saudi also quietly agree the need for a $40 handle.  It will be interesting to see whether the rally runs into a shale wall of hungry US E&P's whose hedge books are looking a little short dated, and on the light side. 

Russia sees oil market balance in winter if cuts deal extended: agencies

MGL Comment
So this time the bulls will say:
~We depleted all the 'black inventory', (OPEC floating, Caribbean tanks, tertiary product inventory etc)
~Demand is ok, and the shale has depleted the 'good stuff' i.e high graded.
~Therefore service pricing will rocket, and the the shale wall will move to $60 odd.

We're not so sure.
~The main shortage in the shale space is not equipment or labour, but equipment and labour in the right place.
~We've been picking up all year the surge in hotel activity around Midland Tx, and on craigslist Odessa, this is mobilisation of the workforce.
~Evidence of service 'inflation' remains thin, but hope reigns eternal, and I am sure the OIH will give you a good bounce. 

Floating oil storage has dropped by one-third in 2017: OPEC source

MGL Comment
Off hand, I would be inclined to suggest that this is disappointing. Floating storage is expensive, and should have borne the brunt in any contraction in inventory. 

Caspian oil pipeline eyes massive expansion thanks to new oilfields

MGL Comment
400kbpd gross Boee from Kashagan, which has finally sorted out its plumbing issues. 

Nigeria's Forcados oil pipeline said fully fixed, ready to ship

MGL Comment
200kbpd returns. 

Tidewater in bankruptcy deal to eliminate $1.6B in debt

MGL Comment
Creditors end up with 95% of the equity. New pro-forma market cap is $800m. Tidewater's  marine supply business has fallen 70% in revenue terms since 2014, and this figure includes long term contract roll off. We're cannibalising the Oil service industry now, and I seriously doubt the Oil Service index, the OIH, can endure the pain. 

We would still want to trading the OIH on the short side. 

Japan’s spot LNG prices continue to drop

MGL Comment
For your average LNG producer that's likely a P&L loss, and a 70c 'cash' margin. It is 35% better than last year, but in that 12 months period, another 5% of the market has likely dropped from contract to spot (2% decay/3% volume growth HH related prices for the most part.)

Gazprom hopes to agree in 2017 main terms of gas exports to China from Russian Far East

MGL Comment
Now the original contract was around the $12 level, which at the time, rocked the LNG industry badly, because they were licking their chops at selling LNG to the Chinese for $15. Today, and three-four years on, and LNG into China is $5-6, which means citygate at $8. So once again, Petrochina is licking its wounds on a massive implied contractual loss. 

We simply do not believe the extension is at $12. Note over the weekend US representatives accepted an invitation to turn up at the 'belt and road' initiative, and Alaska, once again moves into focus. 

Qatar cargoes could weigh on Australian NWS condensate premiums

MGL Comment
Condensate is often produced as a sideline from big LNG projects. 'Wet' gas processing yields condensate, lpg, and natural gas. About five years back we were noting that LNG developers were picking off high condensate deposits as primary development sites. That leads us to wonder whether Qatar is bringing onstream a particularly 'wet' part of the North Field to support it's LNG expansion plans. 

If true, and it seems likely, then we could be seeing yet another straw in the wind that the combination of shale, and LNG is leading to a steady surge in liquids volumes. Not only are these barrels poorly recorded in supply data, but they are also outside the classic remit of OPEC/nOPEC agreements. That we're being shown these barrels because Qatar's dedicate Laffan refinery has some teething issues is not helpful, Qatar recently completed a double in the size of this refinery:

Qatar Petroleum (QP) subsidiary Qatargas Operating Co. Ltd. has formally commissioned the 146,000-b/d condensate splitter of its Laffan Refinery 2 (LR 2) at the Laffan refining complex in Ras Laffan Industrial City, Doha, Qatar (OGJ Online, Aug. 19, 2011).

The LR 2 project doubles condensate refining capacity of the Laffan complex to 292,000 b/d in line with principles of Qatar Vision 2030, which aims to create a sustainable economy and advance the standard of living in Qatar, Qatargas said.

This one project is approximately 10% of net Oil demand this year on the most optimistic numbers. Add in Yamal, Gorgon and Wheatstone and its plausible we have 500kbpd+ of condensate in markets by year end. 

Egypt to cut down on LNG imports

MGL Comment
Egypt's gas start-ups appear to be eating into demand earlier than expected. 

Permian Dominates Again: Rig Count Rises 17th Week

MGL Comment
8 rigs a week right now.

H&P made this comment in their quarterly:

 22 AC drive FlexRigs with 1,500 hp drawworks and 750,000 lbs. hookload ratings were upgraded to include a 7,500 psi mud circulating system and/or multiple-well pad capability, resulting in 122 rigs in our fleet today with rig specifications in highest demand⁽⁴⁾.

This cost them $18m in writeoff of old cannibalised equipment. They increased their 'superspec' rig fleet by 22% in the quarter, and claim they have a further 50 rigs capable of this transition.

Now if we infer that the market is doing the same trick, that would imply 7 rigs per week are being made 'shale ready', and by that we mean walkers, electric direct drive, and all the gadgetry required to use a rig on a pad. 

So of the 8 rigs being added weekly, we have 7 upgrades entering the market, and plausibly 1 redeployment. 

Further, we can do this trick for another 2 quarters before we run out of 'easy' upgrades. 

If we further suggest that 662 rigs are actually producing the near 900kbpd run rate of adds to US shale production, then we can guess that at peak current annual adds we can make 1.3mbpd net adds.

We need to tweak this math some:
1> ~400 rigs were required to keep US shale production flat, ie 262 rigs are the growth driver. That would imply 1.8mbpd adds at existing rig count plus super spec rig conversion, which is actually 'midrange' on US shale surges.
2> If we assume that last year was mainly old vintage wells at 30% decline, then the first 1.8mbpd in year one is 'surge' capacity.
3> Year 2, the 1.8 declines to 600kbpd, so year 2 sustain requires 300 odd rigs add to the original 400, ie 700 rigs post q3 is 'steady state', and we need to find another 250 rigs to upgrade next year to continue growing production.

Caveat emptor: more and more Oil professionals are cautioning that the rig count itself is no longer the US shale 'driver'. Some argue it is now sand and completions.

On sand for example, 25000 wells per annum at one unit train of sand per well is 25000 unit trains of sand moved. (Peak Oil by rail was 17000 unit trains?)
Last cycle it was Canada/Bakken to the coasts with Oil. This cycle it is midwest to Permian with sand. 

U.S. Shale's Favorite Financial Trick Is Getting Less Attractive

MGL Comment
So what we are seeing in the quarterlies looks like this:

$60= 150%+ returns.
$50=70-100% returns.
$40=0-30% returns.

The shale is super sensitive to price, and the fall from $55 t0 under $50, took the fizz out of the system.

Unfortunately for the bulls, this 'slow burn' market in Oil allows people and capacity into the system at some sort of rate, and doesn't allow the 'blow off' that would tighten the Oil service market into exciting pricing power. We're still visibly adding productivity at the well head. Companies are building out logistics, teams and inventory at a steady pace. The phrase of the quarter in the Permian was 'bulking up' as the industry engages in swaps, acreage moves and rock evaluation to put some decent numbers together on padd deployment. Each padd, recall costs roughly $50m, and whereas when we first described Permian well pads we were looking at triples, now we've seen a distinct movement towards quadruple wells per padd, and Encana disclosed one mammoth Canadian style 12 well padd. 

Crucially capex intensity is clearly falling, with EOG head turning $7.6k spend per 1000 bpd gross add. Out of the corner of our eye we're watching well duration increase by a factor of 3-4 times. Typically the 'turnover' point of a well has been around 30 days. Now it's moving towards the 100-120 days. (Turnover point is when the well moves from rapid depletion of the fracked volumes, to slower depletion of the higher surface area now facing the low porosity shale. ) Again, worst yet for the bulls, is the increasing mobilisation of companies on 'refracs', old wells drilled with primitive fracks, that typically left 50-80% of the recoverable Oil behind pipe on cluster length that was too high, or sand volumes that were too low. 

I keep looking at Union Pacific's 32% rise in Sand volumes, their dominance of the Permian, and that '1unit train per well number' and thinking that this is one of the few stocks that rallied on the q1 number. 

EOG in a nutshell.

MGL Comment
EOG has this concept of drilling only premium wells. A premium well uses high end data management techniques to accurately drill the most prolific hydrocarbon lenses in the shale. There is a perception out there that the shale is uniform, EOG, (and Oxy), are championing a methodology that directs the well bit into the best rock in the area. Most tier 1 companies in the E&P space have a manufacturing methodology that simply drills fast, and effectively through all the rock. My hesitation on EOG this last year has been largely due to the fact that in the last cycle the 'manufacturers' (eg CXO, CLR) massively outperformed the 'designer well' strategy stocks (Whiting being the obvious example). 

Note: EOG uses After Tax Rate of Return in its calculations, and not the slightly misleading IRR commonplace in the industry. ATROR is a much 'tougher' return hurdle. 



The question we faced was whether the 'data intensity' at EOG would create a situation where they were unable to create enough feedstock to propel the P&L account. In the first quarter EOG claims to have created enough premium locations (1.4bn boee in 1200 drill locations) to more than replace reserves this year. These premium wells shatter two distinct barriers to the conversion of the shale from 'massive experiment', or bubble as the doomsayers would have you believe, to business, where EOG can both grow volume AND drive positive cash flow. That is nearly but not quite unique. Oxy nearly has the trick, but they MIGHT be able to grow volume 5% with positive cashflow. EOG is saying 18-19%, and these guys are conservative. The metric that matters here is EOG saying 7.6k capex per annual flowing barrel of growth. The industry is at $50k, and even Oxy is at $30k.  
This combination of high end data science, and the use of every 'knack' EOG has learn't is demonstrably producing better wells. We would simply point out that on EV/EBITDA EOG is no different from its peers, despite producing measurably better numbers. Unfortunately its not all sweetness and light. 

EOG gross drilling adds estimate= 130k
Capex in last 12m= $2.9bn.
Implied capex per flowing boee=$22k. (50% premium)

So we must assume non premium at $36.4, which is still credible by industry standards, just not as 'wow!' inspiring.

This year EOG say 80% at premium, which implies total company $15k per flowing boee  capex cost , we achieve 265k gross adds, minus decline of around 110, leaves 150kbpd new vintage boee kpbd, which declines something like 60% in year one, leaving net adds of some 60kbd. That figure is inline with most analyst expectations. 

Oil companies drill down on industrial cyber security

MGL Comment
Is there an NVDA in cybersecurity? Not our field, but you feel the demand. 

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