Sunday, January 18, 2015

The Oil Majors

Since I'm looking for a way to place bets on a rising oil price sometime in the future, take a look at the large Integrated Oil Companies.

There have been many articles over the past few years saying that the IOCs are losing out to the National Oil Companies, as cheaply accessible oil is getting harder to find.  To check this, look at these these numbers over the past 10+ years:
  • Volume of oil produced.  Don't look at revenue, which depends on a fluctuating oil prices.  And don't use BOE, which mixes oil and gas but disregards their differing values (similar to comparing a kilo of gold with a kilo of silver).
  • Proven reserves.  Again look for barrels of oil, not BOE.
  • Cash Flow from Investment (CFI).  Capex (cash spent to find/produce future oil), plus anything gained/lost from buying/selling their reserves.
One company at a time.

Exxon Mobil

Hard to tell if its an oil or gas company?  In 2013, 34% of production was oil and liquids, as measured by BOE, and 66% gas.

Oil and Gas production as (measured as BOE) has remained steady:
But after removing gas, liquids production (mostly oil) has fallen in the past 5 years:

Proven oil reserves (again, excluding gas) have fallen.

But CFI has risen steadily.

The end result is steadily increasing capex, for decreasing oil production and reserves.  Jim Chanos gave an interview last month (second video) stating that he is short XOM/long oil, as they cannot keep their dividend up if the price of oil remains low, and their BOE reserves may be overstated by the XTO acquisition (p12).  Chanos has previously been right about China, IBM and Petrobas, I'm not going to bet against him.


They are primarily an oil company - in 2013, 88% of their production (measured by BOE) was oil.

Oil and NGL production is trending down:

Shell restarted their reserves in 2014, so numbers before 2002 are meaningless.  Proven Oil and NGL reserves fell from 2012 to 2007, but have stopped falling since then:

CFI seems to be rising (though not as clearly as XOM):


1/3rd of their 2013 production (measured by BOE) was gas - so its still mostly an oil company.

Oil production may or may not be declining:

Proven Oil reserves are clearly trending down, being replaced by gas.  Could not find figures for developed/undeveloped oil reserves:

Gas is generally cheaper than oil, though it depends on location since transportation is difficult.  For example, it costs around $3 per BTU in the Marcellus, but may be over $10 in Tokyo - after expensive liquefaction, transport and gasification.  So its a lot harder to determine profitability for a gas company than an oil company.

Again, CFI trending up:


39% of their 2013 production was gas, 61% liquids, as measured by BOE.

Oil production has dropped off slightly in the past 5 years:

But Oil reserves are not going down!

CFI may be trending up, but not so clearly:

BP looks the best out of the majors.  Most of this is due to its investment in Russia: originally the joint venture TNK-BP, now converted to a 20% stake in Rosneft.   If we exclude Russia, the numbers look similar to the other companies:

So a bet on BP is a bet on Rosneft.

In terms of long-term value creation, BP is probably the best (or least worst) of the major oil companies.

Saturday, January 10, 2015

Gran Tierra Energy (Nasdaq:GTE)

Gran Tierra Energy is a conventional oil producer, primarily in Columbia.  97% of their 2013 was liquids, very little gas.  In Columbia, they have interests in 22 blocks, 5 of which are producing.  75% of their 2013 production came from the single Chaza block, in which they have 100% interest.  Their production contracts for Chaza expire after 2034.


GTE pays royalties, as a percentage of oil produced on a sliding scale according to production volume. The royalty levels are a bit complex (p12), and are different for different fields on each block.  Roughly 25% in 213.  Revenue stated is NAR (Net After Royalties).  Since there's no complex PSC, it is easier to estimate their sensitivity to oil prices - production retained (after royalties) will be the same each year assuming constant production levels.

On average, their oil is sold at a discount to WTI, due to transport costs.


Have risen steadily over the years:

Production Costs

Depreciation, Depletion & Armortisation (DDA) forms a high proportion of their costs.  Probably because they use the full cost method to account for exploration costs, where failed exploration efforts are capitalized, then later amortized during production.

In 2013, 49% of oil was sold to a customer requiring trucking 15,000 km away.  The trucking costs were deducted from revenue in 2013, but in previous years were recorded as revenue and expenses (increasing revenue but decreasing margin).

For the spike in 2012 operating expense: $29.3m of it was due to to new pipeline transportation costs of $3.77/BOE and the above mentioned trucking costs.

Other Financials

At the end of 3Q2014, they had $360m cash with no debt.

Planned capex for Q42014 is $220m, and 2015 is $315m.

Management stated they have not taken out any credit lines for contingencies.

Could they survive if oil fell to $40?
  • Its reasonable to remove Depreciation, Depletion & Armortisation from the costs to get 'cash costs':  "The cost of repairs and maintenance is charged to expense as incurred.".  So most capex in CFI should be for new exploration or production, not maintenance.  
  • They sell at a discount to WTI.  Due to a regional differential, and trucking.  In 2013 the average price received was $90.61 versus $97.97 WTI.  In the first 9 months of 2014, the average price received was $89.41 vs $99.61 WTI.  Lets say an discount to WTI of $7-10.
  • So with cash costs between $20 and $26 in the past 5 years, they would generate $4 to $10 cash per barrel for WTI $40.  While making losses on the income statement.
What would its PE be at $60-70 WTI?
  • Extrapolating production for the first 9 months of 2014, with WTI $70, and selling oil at a discount of $9, I get EPS of 12c. 
  • We should probably factor in some growth, as production has risen 30% in the 4 years from 2010 to 2014 (CAGR of 7%), and reserves have risen  steadily over the past 6 years.


Low cost of production and excellent financials make this a good play for an oil price turnaround.  But the nature of their industry and where they operate makes this a speculative stock.  No more than 2% of my portfolio if I buy.  Still too expensive right now.

Wednesday, January 7, 2015

Genel Energy (LSE:GENL)

Genel is a low cost oil producer in Kurdistan, one of the last places in the world with cheaply accessible oil.  They have minority stakes in 2 producing oilfields:
  • Taq Taq (44% interest), produced 42680 bopd for Genel in the 9 months to Sept.
  • Tawke (25% interest), produced 21000 bopd for Genel in the 9 months to Sept.
The Kurdish Regional Government (KRG) has completed a pipeline (in green) through their territory, linking to Turkey's pipes through to the port of Ceyhan, allowing exports.  Genel expects all their oil to be sold at higher export prices in 2015 (p29).

Genel has recently signed a deal to develop 2 gas fields, Miram and Bina Bawi, for export to Turkey.  Production is expected to start in 2016.
They are also exploring in Morocoo, Ethopia, Côte d'Ivoire  and Malta.  Exploration is a hit-or-miss affair, mostly the latter.

I'm looking at the 2 producing oilfields only.

Production Costs

Extremely low costs.  I use net production, divided by all costs on the income statement:


Offsetting its low production costs, Genel sells its oil at far below market rate as agreed in the Production Service Contract (PSC) with the KRG.

Generally, a PSC breaks down the revenue received into 3 parts: the contractors costs, government royalty, and the profit.  The first is given to the contractor, the second to the government, and the third is split:
(Source - p26)

For Genel, to calculate their share of oil produced:
  • Subtract royalties of 10%
  • Genel gets to keep costs.  Specifically: production costs, exploration costs, gas marketing, development and decommissioning.  Up to 40% of the oil (excl. royalties).
  • The remainder is profit oil, to be shared between Genel and KRG.  Generally, 15-16% of this goes to Genel.  The amount depends on the projects profitability, or R-Factor (accumulated revenue over accumulated costs throughout project lifetime).
  • However, we have to halve Genel's share of the Profit Oil, due to KRG's 20% carried interest, as well as a 30% 'infrastructure/capacity fee'.
A summary of the PSC is on p30.  PSC details are here, with the 2010 amendment for the 30% capacity fee here.  Genel provided an example, assuming $90/barrel:

(Source - 2011 Company Presentation - p19)

I was not able to reconcile the formula with the prices and volumes given in their results.  Without knowing which costs were claimable and what the R-factor is.  The best I can say is that this is a 'cost plus' model, which gives Genel some protection from falling oil prices.  They mentioned in November that a 10% fall in oil prices would lead to a 6% fall in revenue (p12).

Averaging out over their net oil production, they were getting around $20/bbl.  For the actual barrels sold in 1H14 (before the cost of the PSC is accounted for): they said they sold most of it in Kurdistan for $60-70, and trucked the remainder to export markets for $80.

Other Financials

After the first line on the income statement, the other numbers in the financial statements are simple.

Cash at hand was 973m at 1H14, after issuing US 500m bonds, which pay 7.5% and are due in 2019. 

Capex is estimated at 300-250m in 2015.  None given afterwards.

Could they survive if oil fell to $40?  I'm estimating yes, conservatively using 1H14 figures, whey would still roughly break even on the income statement.  They still would be generating cashflow from operations, and it would cover their capex in 2015, leaving zero cash on hand.  They'd still survive, but would have to cut capex afterwards.  This does not account for increases in production, or for the PSC decreasing sensitivity to oil prices.  Check again when we get the 2014 results.


Reserves for their 2 producing oilfields are slowly decreasing:

See if they are increased in future Annual Reports.  Look at oil only, as gas confuses things.


I would value an oil company on a sustainable oil price.  Probably $60-70.  Can't estimate their revenue/earnings at this price because I don't understand their PSC.  Theres also too many other moving parts: production increases, reduced transportation costs due to the pipeline, and the two new gas fields.

So a rough guess first.  Since they say they sold their oil for in 1H2014 mostly at $60-70, based on the earnings in that period, their PE at a share price of 700p is around 21.  Too expensive.  


I think Kurdistan is not as dangerous as most people think; the main risks for this company are political:
  • Dependent on the Iraqi Government to recognize the oil exports (recently done), and the Turkish Government to continue to accept gas imports and transport oil over their pipelines.  Although the current Turkish government seems to be friendly to the Kurds, they have a long history of conflict.
  • The KRG may renegotiate the PSC, as in 2010.  Genel gained from being one of the first to move into the region, but now that larger companies are moving in, it may be more competitive.


I don't fully understand the company, especially its revenue.  It seems OK, with a good chance of surviving low oil prices.

Oil is a risky business.  All the E&P companies I've looked at from the majors down to the independents have a lot of risk.  None have sustainable competitive advantages.  I'll aim to buy 'a basket' of oil stocks - allocate 2% each - to try to spread the risk.  Pick ones with good finances and low production costs, that give them a reasonable chance of surviving. These aren't stocks to hold forever, just buy to take advantage of the low oil price till it recovers to a sustainable $60-70 level.

Later on, I'll check Genel's 2014 results, for their cashflows, ability-to-survive, and see if we get a better revenue estimate based on lower oil price.  Also valuations.

Tuesday, December 30, 2014

Oil - part 1

Oil has dropped nearly 50% in the past 6 months, due to an estimated  1m bpd excess, over 92m bpd usage.  Oil prices swing wildly with small changes in supply or demand, as it can't be stored cheaply or safely.

In theory, a commodity glut ends when the price falls below the cash cost of marginal producers, eventually pushing them out:

(Source - Business Insider)

I believe US tight oil (shale) producers are the marginal producers. They are high on the cost curve.  And individual shale oil wells have a very rapid decline in production:

This means they need to constantly drill new wells every year to maintain current production levels.  For the successful ones, their business model is to have the initial production spurt in the first few years pay off the well (usually at hedged prices), after which the the remaining tail end of production (even if only hundreds or tens of barrels per day) is mostly profit.  For the weaker ones, with bad acreage or too much debt, the constant need for capex to re-drill will kill them.

No one knows what the real tight oil production costs are:

  • Costs are always falling, due to new techniques such as horizontal drilling, multi-well pads, and  wide short fracks.
  • There is no single cost number we can use: every single well must be evaluated individually, due to differing location, technology and fracking techniques used.
  • I could not approximate EOG's past few year's production volumes with the above decline curve, they're far higher than it suggests they should be.
For now, lower prices mean that everybody drills more.  Individual US companies drill to pay off debt and keep their leases.  The poor shitty countries that depend on oil revenue will produce more of the stuff to try to pay their bills.  We won't know when it ends, or at what price US production numbers drop, until after it happens.

In the long term:
  • Supply is controlled by the Saudis. Even with the cheapest production costs, they have a large welfare payments to make. Their projected 2015 budget has a shortfall of nearly USD 40bn at an estimated oil price of $55-60 per barrel.  They have about $750bn reserves.  They can't do this forever - maybe 5 years at $40 oil.  They reportedly did want to initially cut production, but increased it instead after they could not agree with Russia.
  • I think the future oil price will be capped at $70-80.  Even after US tight oil companies go bust, production can start up again in a matter of weeks or months if prices rise.
  • This means fewer new deep water projects.  It makes no sense risking hundreds of millions upfront to explore and produce, when you know where the oil is in the continental US and land rigs can be deployed for less than 10m each.
So I believe that oil will recover to a sustainable cost ($60-$70) in 1-4 years.  Unless we get a US recession - the current upswing is now 5 years old - or a hard landing in China - about a 1/3rd chance - in which case prices remain low longer.

At some point, the price falls far enough to say an asset undervalued.  For a commodity its based on marginal production costs.  I'm going to pick WTI $40.  No guarantee it will reach there, but if it does, production costs mean it must increase eventually.  Around that point, I'd look to buy strong companies that can survive the downturn.

Sunday, November 30, 2014

Indonesian Thermal Coal (part 2) - the Asian coal market

The thermal coal market is harder to understand than I imagined.  Demand should be predictable - after you build a power station, you know how much coal you can shovel into it for the next 30 years. And if many coal miner's costs are above the market price, then production must contract, and there will be an eventual recovery when a new wave of demand picks up.  But its not that simple.

Seaborne trade is dependent a few big customers.  In 2013, China was responsible for about 30% of Asian coal imports, followed by Japan and India at around 15% each, and Korea at 12% (from BREE - p55).  But even though China is the worlds largest importer, only about 8% of its thermal coal is imported.   So graphs like this, showing China's coal imports steadily rising year after year are misleading,
when you consider that China's thermal coal production was off the chart at 3024 mt in 2013.   The imports are only at the margins.  A small change in demand or supply could reduce or stop imports. Or even lead to China exporting coal again.

The reason for that China imports is that bad railway infrastructure makes it expensive to carry the coal to the coastal cities.  This makes it the same to ship Indonesian coal to them:

 (Source: Adaro - p11)

So Indonesia's low cost advantage is also only at the margins.  They can only sell coal to the China's coastal cities, not to the western provinces.  And improvements in train size or railway infrastructure may make it possible for coastal cities to buy from local mines instead.  There are also plans to build power stations near the mines inland and transmit power to coastal cities.

The next largest buyer, Japan, is easier as they don't produce any coal themselves.  They are expected to reduce coal imports from 142mt to 127mt in 2019 as  they restart nuclear reactors and  (p51).  They have 4.8GW of coal fired stations scheduled to start next decade, which may add 10mt.  This report gives more optimistic estimates.

India is widely expected to replace China as a leading importer of coal.  But, like China, India has large reserves of coal.  Unlike China, they cannot mine them fast enough - their state owned coal company has missed targets for the past 6 years.  It is politics, not economics that will determine if their coal industry can be consolidated enough to improve efficiency, if foreigners can invest, and if required railways and power transmission can be built.

South Korea is next: additions of 12GW in 2015/16 expect to add 25-30mt coal per annum.

I expect ASEAN to grow coal consumption dramatically.  From around 70-90mt of imports now, to 210-279mt mt in 2035 in 2 scenarios (pp124-125).  Makes sense, as some of these countries do not have full electricity coverage yet, and coal is the cheapest and most reliable option.  Adaro expects ASEAN consumption (not just imports) to rise from 214mt in 2013 to 600m in 2035.

Worldwide, growth in coal use is undergoing structural slowdown:
  • Coal use has declined, due to cheap natural gas in the US
  • The US and China have agreed to reduce their greenhouse gas emissions.  China agreed to cap emissions by 2030.  They also released plans to cap coal consumption at 4.2bn tons by 2020.  I am surprised, I thought there was no way they would do it. They have also implemented local carbon trading schemes, mostly in coastal areas, in preparation for a nationwide scheme, possibly in 2016.


Thermal coal is trading below its marginal cash-cost in the cycle.  Credit Suisse says that "when there is oversupply of a commodity, typically 40% falls below the cash cost."  They say that 40-50% of thermal coal production is currently below cash cost.

Thermal coal is expensive to transport, thus seaborne coal is a small part of the thermal coal trade.  The cost curve shown in my first post is only for seaborne thermal coal only (graph B4).

I can't tell if long-term overall Asian thermal coal usage will rise or fall.  You can construct plausible scenarios either way.

Even though we are probably at the low point in the cycle, I won't look at Indonesian thermal coal because:
  • China and India may use their own coal
  • There is a structural decline in coal growth.  So the next up cycle may be smaller.
  • Potential changes in regulations make it risky for Indonesian coal companies.
  • Commodity down cycles are usually very long.   Newcastle coal fell from 1995 to 2003.  Due to the above risks, I would not be comfortable holding an Indonesian coal company for another 4 years while waiting for a payoff.
I could be wrong, and there are plausible scenarios where coal usage rises, especially in South East Asia, which would benefit Indonesia's exports.  If I was going to buy, my first picks would be Adaro and Bukit Asam.  But the long term picture is too hard to predict.

Wednesday, November 19, 2014


Baiju is the most popular drink in China, and Moutai is the highest premium brand of Baiju.  It has a long, storied history.  Each bottle takes 5 years to produce.  It is only produced at a specific location (p6).

In China there was a Baiju Bubble, which popped in 2012:

I don't know if Kweichow Moutai itself benefited from the previous high prices, or if their distributors did.

The bubble was pricked by Beijing's anti-corruption drive.  Moutai had previously focused on selling to government officials (or those who were hosting them).  They are now trying to switch to the consumer market, by:
There are many brands of baiju in China.  Diageo, LVMH and Pernod have acquired their own brands.

The risks are:
  • Young people in China may not take to baiju, being used to foreign brands of whiskey or vodka in nightspots instead.
  • This is purely a domestic China play.  Its unlikely that foreigners will take to it - "tastes like paint thinner and feels like a lobotomy".
  • As a China Company, its numbers may be fake.
  • China food quality: the company had a contamination scandal in 2012,over plasticizers in the bottles.  They did not handle it well.
  • How are they managing to lower prices, increase volume and move into the consumer market without affecting quality?
The numbers look excellent.  I didn't read the financial statements myself, but got the numbers from Morningstar, who, surprisingly, cover it (subscription needed).  Profit margins (after taxes) have been over 44% for the past 5 years.  Gross margins are over ninety percent.  Net cash has risen steadily over the past five years - I estimate it to be around 15% of the market cap, at 165yuan/share.  Perhaps they are also in the business of printing money.

The PE based on the last 4 quarters is just under 13 (@ 165 yuan/share).  Even though I prefer Diageo, which has a larger variety of products and is more international, Moutai looks better at this valuation.

Bought 900 shares at CNY 163.3 on 17th Nov 2014.  Total cost was SGD 31594.  Held in my DBS Vickers acct.

Sunday, November 16, 2014

Indonesian Thermal Coal

In one of his books, Aswath Damodaran mentioned a strategy for investing in cyclical commodity companies. When the commodity price is low, below the marginal cash cost of production, buy the lowest cost producer, who will survive and benefit once the commodity price recovers after the more expensive players are forced out of the market.

Newcastle (Australia) coal has dropped 50% since 2011:

(Source - indexmundi)

Futures have it between USD 63 now and USD 72 in 2020.

A google for thermal "coal cost curve" beings up this chart (from mid 2013), showing many players above the current price.

More googling shows Indonesia being the 2nd lowest cost producer, after South Africa (See here) (See p8).  A more recent chart (p24):

This is worth looking at further.

Quick Notes on the Thermal Coal Industry

Thermal coal pricing is regional, due to high transportation costs.  Coal often costs several times more to transport than it does to mine.  Cost to transport to port (for export) is the largest component of production costs.  Therefore, mines by the sea have much lower costs.

The simple 2011 map below gives rough costs for shipping coal.  Indonesia has the cheapest costs to China and India:

(Source: Nomura p11)

This one is more recent and detailed (source - Accenture p14):

We can see that Kalimantan has the lowest shipping costs to India, Japan and China.  The price differences between the importers (Qingdao, Japan) and exporters (Australia, Indonesia)  is maybe 10-15% once shipping costs are added.  A small change at the margins can have a large effect.

In the US, coal has been slowly replaced by Natural gas due to the fracking boom (p10) (more graphs here).  I don't think this will happen in South East Asia, as LNG is expensive to ship, and many regions here are so poor that they don't have reliable electricity.

Even though Australian producers are losing money, they are forced to continue production by long-term take-or-pay contracts.
It is expected that Chinese imports will decline over the next few years:
Mongolia is a producer of coking coal, but it is probably uneconomical to produce thermal coal there, with production costs estimated "in the order of $10-$30/tonne" with the same costs being incurred for freight into China.

Indonesia has a policy to replace diesel with coal for electricity generation.  They expect to double thermal coal consumption over the next 8 years.  This may not be good, as the government has tried to interfere with the coal industry:
The thermal coal market is quite fragmented.  Glencore is by far the largest player.  It probably controlled 50% of South African exports before its merger with Xstrata in 2013.  In 2010, it had 28% of the seaborne thermal coal market, plus Xtrata's 9%.  Glencore will be responsible for half the new coal coming onto the market in the next year.  They have been accused of trying to flood the market to remove competitors.

As with any market, no one can predict future coal prices.  Prices may be low until the 2020s, due to Glencore flooding the market and Australian mines being forced to produce.  I can't see a catalyst for coal prices to increase...but if I could, then so would everyone else.  Have to be willing to buy before everyone sees the light at the end of the tunnel.

The uncertainty introduced by the Indonesian government's ever changing rules may make me take a smaller position.

What to look for in a Coal Company

  • Low debt, to survive the cycle.
  • Low production costs:
    • Short distance to port (pit-to-port)
    • Low stripping ratio
  • Reserves: long mine life.
  • Are they selling coal on the open market, or at a hedged price?  Selling coal at a price higher price hedged years ago can make the company seem more profitable than it is.
  • Operating leverage: especially high fixed costs for transportation.