Saudi Arabia has announced that 5% of state owned Aramco is to be put up for sale perhaps as early as 2018. As part of the process, the country’s oil reserves will be subject to audit by western consultants, presumably to OECD standards. Given that Saudi Arabia has not adjusted oil reserves for production since 1980 there is a widely held view that the official figure of 267 billion barrels is a gross overstatement of reality. The audit will be interesting to say the least, especially since Iraq, Iran, Kuwait and UAE are all guilty of the same malpractice. Deducting the 156 billion barrels produced since 1936 leaves 110 billion bbls remaining. Only time will tell where reality lies.
There is a lot going on in the Kingdom of Saudi Arabia (KSA) right now. Regional competitor Iran has come in from the cold and boosted oil production by 760,000 bpd at a time when higher prices would have suited all OPEC. Wars rage in Iraq and Syria to the North, and Saudi Arabia is waging war in Yemen to the South. The Kingdom has had to venture onto capital markets to borrow money in order to fund welfare spending at home. Donald Trump has been elected US president and has restated goals of US energy independence whilst signalling an end to oil dependency on KSA. OPEC has announced that demand for oil may peak in 15 years if countries aggressively try to cut emissions. And Saudi Arabia has announced that 5% of Aramco is for sale, valuing the corporation at $2 trillion.
This post begins with a look into the black art of estimating reserves and concludes that none of the methods currently in use are satisfactory. They are in fact woefully inadequate. The Middle East OPEC countries are operating to a set of unwritten reserve reporting rules all of their own that have no semblance of similarity to the OECD standard that is also critically flawed. How then are potential OECD investors in Aramco going to value the investment?
Reserves Reporting Standards
There are two main reserves reporting institutions 1) The US Securities Exchange Commission (SEC) and 2) The Society of Petroleum Engineers (SPE) backed by The American Association of Petroleum Geologists and others. There has been a large degree of convergence in the methodologies in the past decade but one still needs to be cautious in the interpretation, especially between 1P (proven) and 2p (proven + probable) reserves and the broader term of resources.
The first stage in understanding petroleum (oil and gas) reserves is to understand the accounting methodology:
- Reserves at beginning of year
- Minus production
- ± Revisions
- + Additions (new discoveries)
- = Reserves at end of year
The SPE Methodology
The SPE methodology is based upon the Petroleum Resource Management System (PRMS) (Figure 1):
Figure 1 The petroleum resource management system of the SPE.
The SPE scheme arranges reserves and resources into a 9 box matrix where the x-axis is the range in physical estimates based on data, e.g. seismic, well logs, well tests and cores. The y-axis is a measure of commercial viability where the reserves are actually in production, in the process of being developed or where development is planned. The contingent resource category comprises reserves that have actually been discovered but for which no development plan exists. To be discovered means that at least one well has been drilled and discovered oil or gas. The prospective resource category is based on prospects identified on seismic where the possibility of a discovery is identified but has not yet been drilled.
The definitions of 1P, 2P and 3P are more woolly. Proved (1P):
Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.
2P is less certain than 1 P and 3P less certain than 2P. Commercially recoverable is in bold because unlike volumes in place, which should give or take revisions be constant, commercial viability varies with the oil price and with technological advances. The fall in the oil price has created severe problems for western oil companies since the fall in price has made swathes of production, current and planned, unprofitable, wiping out large portions of reserves and share price valuations.
The SEC Methodology
The SEC rules have changed significantly over the last decade and are now by and large aligned with the SPE methodology. The SEC was formerly ultra-conservative, allowing only 1P reserves to be reported. New rules are more relaxed where:
The new rules define proved developed oil and gas reserves as those that can be recovered through existing wells with existing equipment and operating methods or that can be recovered in other ways through extraction technology installed and operational at the time of the reserves estimate.
For undeveloped oil and gas reserves, the new rules will permit companies to claim proved reserves beyond spacing areas immediate adjacent to developed areas if the company establishes with reasonable certainty that these reserves are producible economically.
Formerly the SEC only permitted proved developed reserves to be reported but the definition has now been broadened so that the SEC definition of reserves is now broadly equivalent to the SPE definition.
OECD Reserves Reporting Standard
At this point it is worth pointing out that the BP Statistical Review reports 1P reserves which is a very conservative measure being the top left box of the matrix (Figure 1). Figures 2 and 3 show the reserves evolution for European countries – Norway, the UK and Denmark. What we see are year on year adjustments that simply reflect the accounting methodology. The reason for showing this is to compare and contrast with the picture from the Middle East OPEC countries, including Saudi Arabia.
Figure 2 The evolution of North Sea reserves as reported by BP.
Figure 3 Line chart showing the evolution of North Sea reserves.
Since 1980 Norway has produced 28 billion barrels of oil and the UK has produced 27 billion barrels of oil. And yet UK reserves were never above 9 billion and Norwegian reserves never above 12 billion. The main point I want to make, therefore, is the fact that the conservative definition of reserves used in the OECD is a useless measure of how much oil or gas may actually be produced. A better measure may be 2P reserves + contingent + prospective resources if one wants a measure of how much exploitable oil and gas is actually there.
Middle East OPEC Reserves Reporting Standard
Oil Drum readers from days of old will be familiar with the oddities of ME OPEC reserves reporting that are shown in Figures 4 and 5. There are two rather suspicious elements to this. The first is that all countries bar Qatar revised their reserves upwards by substantial amounts in the 1980s. Saudi Arabia, Kuwait and the UAE did this only once, but Iran and Iraq have both had two upwards revisions since (Figure 5). These upwards revisions have nothing to do with new discoveries being made but rather reflect a revised view of the oil that may be recovered from existing fields, mainly revising upwards the recovery factors. While in the good old days of The Oil Drum a decade ago this caused consternation among peak oilers, I conclude today that these upwards revisions are probably valid, though need to be subject to audit.
Figure 4 ME OPEC countries oil reserves according to BP.
Figure 5 ME OPEC countries oil reserves according to BP.
What is less easy to defend is the flat line reporting. For example, the UAE has reported a value of exactly 97.8 billion barrels since 1996. No effort has been made by any of these countries bar maybe Qatar, to carry out the basic accounting practice of deducting production from reserves. So what do these numbers mean if anything at all?
Saudi Arabia Reserves
A good starting point for the discussion of Saudi reserves is the table dating from 1975 published by the Rand Corporation (Figure 6). A little history is useful to know. Prior to 1974, Aramco was known as the Arabian American Oil Company and was owned by companies we now know as Exxon, Mobil, Chevron and Texaco. Following US assistance to Israel during the Yom Kippur war in 1973 the government took a 25% stake, increasing that to 60% in 1974. In 1980 the whole company was nationalised and the name changed to Aramco. The point is that the Rand table was compiled at a time western companies were active in Saudi Arabia and had access to the data. It lists all fields by order of size and shows 176 billion bbls of reserves, 24 billion barrels produced to date for an ultimate recovery of 200 billion barrels.
The reserves figure of 176 billion bbls for 1975 compares with the BP number of 168 billion bbls reported in 1980. If we adjust 176 billion for the 13 billion bbls produced in the four years 1975-1979 we arrive at 163 billion barrels, close to the BP figure. I am satisfied that the Rand Corporation and BP figures are closely aligned.
I am going to allow Saudi Arabia the large hike in reserves during the late 1980s since recovery factors may well have been understated. This could be why the Rand Corporation has low? set against most fields. But I am not going to allow them to not deduct production.
Figure 6 Table of Saudi oil fields from the Rand Corporation dated 1975.
Figure 7 Saudi Arabia oil production using the API Facts and Figures Centennial edition (1959) for 1936 to 1959 and BP from 1965. The large dip in production post-1980 was Saudi Arabia + OPEC cutting production in order to support price. Their current strategy to maintain market share is designed to avoid a repetition of such drastic restraint. The dark green line is a bottom up forecast I made for Saudi Arabia following several weeks of epic blogging on the Oil Drum (Figure 8). The forecast was looking good until three years ago. The decline shown in my forecast was based on the anticipated watering out of wells on Ghawar that appears NOT YET to have happened. I wonder if anticipated decline of Ghawar lies behind the plans for the IPO.
Figure 8 A bottom up forecast of Saudi oil production that I produced in 2006 as published on The Oil Drum. The post-peak decline was based on a model for wells watering out in core production areas of Ghawar that must happen one day.
Figure 9 Saudi Arabian production began in 1936. If we assume that the official reserves figure of 267 billion barrels is in fact an expression of URR, then the dark green line shows reserves depletion for production.
During discussions on The Oil Drum, the idea emerged that reported ME OPEC reserves were more a view of ultimate recovery (URR) rather than an expression of what may remain to be produced. We know with virtual 100% certainty that the flat line reserves reports are false. And so, in absence of any other information I am going to assume that the figure of 267 billion bbls reported by BP for 2015 is a measure of URR. If we deduct the 156 billion barrels produced since 1936 we get 110 billion barrels of remaining reserves as illustrated in Figure 9. This is just 41% of the figure claimed by Saudi Arabia. I am not claiming these numbers are correct but simply pointing out that the official figures cannot be correct either. Auditing the real data is going to be exciting to say the least.
Saudi Arabia is placing a value of £2 trillion on Aramco that is both a production and a refining company. 5% of that will cost $100 billion. Investors with deep pockets are sought. The Saudi annual budget is of the order $224 billion [note that I originally wrongly stated this number to be $98 billion], and so this sale, dressed up as building a sovereign wealth fund, will do no more than pay for 5 months of the Kingdom’s bills. Of course it’s not as simple and straightforward as that, but as writing this post has progressed, I’ve found it increasingly difficult to understand the underlying motive.
But where will investors be looking to value Aramco? Reserves are one metric very difficult to tie down. Production statistics are easier but I have found it strangely difficult to find summary production stats for peers like ExxonMobil and Shell. Here’s a very rough guide gleaned form various sources.
- ExxonMobil 4.3 Mbpd
- Shell 3.7 Mboe/day
- Chevron 2.7 Mbpd
- Total 2.1 Mbpd
- Total = 12.8 Mbpd
And market capitalisations:
- ExxonMobil $349 billion
- Shell $219 billion
- Chevron $207 billion
- Total $140 billion
- Total = $915 billion
And then if we look at Aramco we find:
- Production 12 Mbpd
- Anticipated capitalisation $2000 billion
Houston we have a problem!
Added to that markets tend to value minority stakes in State owned companies lower than OECD peers. According to Bloomberg:
Despite the prince’s bullishness, foreign investors rarely value state-owned oil companies as dispassionately as their crude-reserve numbers suggest — or as government officials might hope. State-controlled OAO Rosneft, for example, is the largest oil producer in Russia and one of the world’s largest. It pumps 5 million barrels a day — far more than Chevron — yet its market capitalization is just $50 billion, a fraction of Chevron’s $180 billion.
Much will depend on the structure of the deal. With lifting costs <$10 / bbl in Saudi Arabia, if investors are exposed to the full glare of profits then perhaps a $2 trillion price tag can be justified. It is not normal for States like Saudi Arabia or Russia to allow third parties full exposure to profits. Let’s get the back of the envelope out:
- Oil price = $50 / bbl
- Lifting cost = $10 / bbl
- Profit = $40 / bbl
- Production of 12 Mbpd * 365 = 4.4 billion bbls / year
- 4.4 billion * $40 = $176 billion in profit / annum
- On a PE ratio = 10 gives a market cap of $1.8 trillion
- And then there is the refining business on top
It looks like the Saudi princes are using the same envelope as me. In this calculation, reserves become important in determining how long Saudi Arabia can maintain 12 Mbpd production.
[Footnote: observing that the Saudi budget is $98 billion and Aramco profits would be $176 billion @ $50 / bbl, where to Hell does the rest of the money go?]