Opinion: CERA report on Cost of Oil

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The CERA report, “The Cost of Oil,” by Pritesh Patel, CERA Director, Capital Costs Analysis Forum, dated Oct. 2008, has been overtaken by the events that occurred towards the end of 2008 as this quote shows “If oil prices were to crash today to $60 per barrel, CERA expects the viability of projects in several regions—including the North Sea, deepwater Gulf of Mexico, Brazil, Angola, Nigeria, Canadian oil sands, and Venezuela heavy oil—to be either delayed or re-evaluated.” Prices in the last quarter of 2008 fell below $50, though they are slowly recovering. However, except for the Canadian oil sands, development in most other oil provinces continues as normal.

Much has been said about a minimum price of $70 being necessary if oil investment is to continue so there will be adequate supplies once the world comes out of the current recession. However, this assertion has been made by those who have a vested interest in high prices e.g. members of OPEC and oil companies. Once a country becomes accustomed to living with a price over $100, it comes as a shock when the price drops by half. Among oil companies supporting high prices is BP, but this is hardly surprising when the latter made a loss of $3.3 billion in the last quarter of 2008.

The author, Pritesh Patel, is to be commended for spelling out the methodology he used as it allows one to make comment. For instance, the risk premium covers 15 elements of which 14 affect the capital cost of development, but only one, “foreign political risk,” relates to the overall risk. I believe the latter far outweighs the possibility there will be cost overruns on projects, and that most investors will concentrate on three aspects:

•  Possibility that the ground rules will be changed

•  Possibility that the assets will be expropriated

•  Possibility that repatriation of profits will be delayed

As the 15 elements are very subjective, I prefer to use a simpler classification of low, medium and high risk, and I shall limit my comment to Venezuela ‘s situation which I know something about. Recent history is probably the most important guide for assessing all three.

As regards changing the ground rules, I believe the risk is now relatively low because PDVSA’S government take is already one of the world’s highest.

Venezuela was criticized for changing the ground rules when it increased royalties to 33% and income tax to 50% on the Orinoco Belt operations. However, this only put them on a par with the rules for operations outside the Orinoco Belt.

Contractual conditions were indeed unilaterally changed, but oil companies recognize agreements are no longer written in stone and may well be modified when conditions vary from those originally envisaged. The fact is the companies in the Orinoco Belt were making large profits with royalties of 16.7% and income tax of 34%. Where criticism may be justified is with the recent introduction of a charge on windfall profits which kicks in when prices exceed $70. This is certainly a disincentive for a potential investor.

Risk of expropriation exists and it has legal support under the “United Nations Resolution on Permanent Sovereignty over Natural Resources” (Resolution 1803). Last year, PDVSA expropriated shares of the four companies operating in the Orinoco Belt in order to nationalize them through a majority holding. By law, PDVSA must now hold a minimum of 60% of the equity in all oil companies operating in the country. The companies are no longer joint ventures since joint control does not exist, and the foreign companies are just minority shareholders.

The risk is that the country will not be content with a 60% shareholding and may, in future, decide to increase it. I put this in the low risk category while oil prices do not increase substantially because PDVSA needs the cash to fund the country’s social programmes. When prices exceed, say, $100 the risk moves to the medium category because it is mainly a lack of funds and know-how that prevent further nationalization.

The problem with any expropriation is that PDVSA will only agree to pay compensation based on the net book value and not a commercial value. This was confirmed in legislation just passed on 7 May 2009 which provides for the expropriation of contractors and service companies employed in the oil industry. Companies registered in a country that has a Bilateral Investment Treaty with Venezuela can go to arbitration, but that is a lengthy process they will want to avoid. It also means they will do no further business in Venezuela .

The third risk is not that profits cannot be repatriated, but that there may be delay of some considerable time. This is happening at the moment because PDVSA is strapped for cash and, as the majority shareholder, can decide when dividends will be paid. Dividends on the 2008 net profit should have been paid by 31 March, but I understand they are still unpaid. I put this risk of delay as high any time that PDVSA finds itself short of funds, though this should only happen when oil prices take a sudden dive as they did at the end of last year.

With reference to risk premiums, Mr Patel has added these to construction costs in order to permit comparison across the board. This may be a modern approach, but I still prefer the old system of allowing for different levels of risk by increasing the required rate of return e.g. 15% for low risk, 20% for medium risk and 25% or more for high risk. Where risk is deemed high, then the old-fashioned payback time is more useful than IRR or the PDV of future cash flows.

As regards CERA’S statement, “Under Global Fissures (one of three scenarios), lower oil prices threaten the viability of deepwater Gulf of Mexico, Angola, Nigeria, Canadian oil sands and Venezuelan heavy crude,” it was probably a lapsus that deepwater Brazil was not included to complete the offshore list. But let me comment on Venezuela ‘s extra-heavy crude oil where many analysts make the mistake of assuming production costs are very high. First, the area is on dry land and easily accessible, it has already been explored, 3D seismic surveys have identified the best prospects, and the oil in place has been determined. Secondly, production techniques–cluster wells, drilling in the form of an L so that it goes horizontal along the reservoir, and the creation of powerful electric pumps–are well developed.

The oil flows in the reservoir and only becomes a thick tar when it reaches the surface and cools down. But once again there is a tried technique of blending the oil with a diluent so it can be pumped to the upgrader on the coast. The diluent is recovered and pumped back to the production area for reuse. None of the production operations is particularly costly.

The higher cost is incurred in upgrading the crude from an 8.5º API to either 16º API or 32º API depending on the plant complexity. The upgraders are akin to refineries except that they specialize in a process of hydrogenation and are less complex than traditional refineries. Even so, the cost of an upgrader can be as high as $4 billion. But, like refineries, they have a long life so their cost is spread over many years of upgrading.

Though comparison is clouded by different risk premiums– Canada 19% and Venezuela 28%–I cannot believe that Venezuela ‘s extra-heavy oil has the highest capital cost of all onshore fields at $19 boe which makes it double that of the Canadian oil sands’ cost of $8 to $10 boe. If so, why has development of the oil sands suffered while that of Venezuela ‘s extra-heavy oil continues as normal? The two operations are quite different: the oil sands involve surface mining whereas the Orinoco Belt uses normal heavy oil production methods. For that reason alone, even allowing for Venezuela ‘s higher risk premium, I believe Canadian oil sands’ development is more costly than that of the Orinoco Belt.

Mr Patel has produced an excellent table which shows life-cycle (capital and operating) costs. However, again I find it hard to accept operating/capital costs per barrel for Venezuela’s extra-heavy crudes ($25) exceed those of Brazil ($20), UK North Sea ($23), US Gulf of Mexico ($24) and equal Angola’s ($25) which are all offshore and, with the exception of the North Sea, in very deep water. The higher risk element assumed for Venezuela does not, on its own, account for it.

I am surprised Brazil does not have the highest cost since the Tupi field is almost 200 miles offshore and reaching the reservoir means going through 7,000 feet of water and then drilling through 17,000 feet of sand, rock and a thick salt layer.

Another admirable table, which sums up the report, shows the “Minimum Equivalent WTI Price” that is required to obtain a 15% internal rate of return (IRR). By linking prices to WTI, crude quality differentials are taken into account. But, once more, I fail to see why the price of Venezuela ‘s extra-heavy crude ($114) exceeds those of UK North Sea ($60), Brazil ($61), US Gulf of Mexico ($65) and Angola ($71) which all have much higher costs because they are offshore. Even the Canadian oil sands ($87), a recognized costly operation, have a lower price than Venezuela ‘s extra-heavy crudes. The only explanation I can think of is that the price applies to the extra-heavy crude before upgrading, in which case there is indeed a huge quality differential. But upgrading to 16º API or 32º API is an integral part of the upstream operation–the upgraded oil still needs to be refined in a downstream operation.

One important aspect the author did not mention is that by far the largest share of Venezuelan production belongs to PDVSA where royalties and income tax are not costs but part of the government take. This means, even with low prices, production is profitable for PDVSA when it is much less so for the foreign investor for whom both royalties and income tax are costs. An accounting presentation, where capital costs are taken up as depreciation, makes this point clear. The figures are only indicative since PDVSA does not publish the Orinoco Belt costs.

 

Orinoco Oil Belt Costs Including Depreciation

Sales price

$50

$60

$70

Production cost

5

5

5

Upgrading cost

7

7

7

Royalty*

17

20

23

Total cost

29

32

35

Profit before tax

21

28

35

Less income tax*

11

14

18

Net profit per bbl*

10

14

17

Government take*

$38

$48

$58

 

The government take is comprised of royalty, income tax and net profit which all accrue to the government. Whether $10 per barrel is attractive enough to the foreign investor will be seen when bids for the Carabobo blocks are opened in July this year. The date keeps being put back which suggests bidders have doubts about both the profitability under Venezuela ‘s high government take and about the political risk which has been brought into focus by the last round of expropriation of contractors and service companies.

The statement that, “ If oil prices were to drop to $60 dollars per barrel, CERA would expect projects in several regions to be affected. Venezuela heavy oil, Canadian oil sands, and deepwater projects in West Africa carry the highest risk of being delayed or re-evaluated” is open to question. It is true oil sands’ development has been put on hold but generally, including Brazil ‘s offshore deepwater, project development continues. The reason is that the major oil companies are in for the long haul and projects have long lead times. They do not stop project development because prices are low at any given time.

Another statement that “The HIS/CERA Upstream Capital Costs Index shows that the construction costs of new oil fields are continuing to rise at unprecedented levels” may no longer be true. Since August 2008, steel prices have plummeted and this reduces construction costs. In addition, the daily rates for offshore drilling ships and semi-submersibles have gone down. However, drilling in very deep water is still a most expensive business.

The CERA report is well thought out and is a useful tool for the oil investor. However, its finding that in most countries the minimum price to achieve a 15% return will be in excess of $60 is questionable. It was only in 2002 that OPEC established a price band between $22 and $28. In 2003 the WTI price was around $30, and for much of 2004 it was below $40. The finding implies development and operational costs have rocketed since then. Though this is true in the case of deepwater operations, e.g. Angola , Brazil and Gulf of Mexico, it is not so of most other areas.

It is also debatable that Venezuela’s extra-heavy crudes have a life-cycle cost above those of Brazil, UK North Sea, Gulf of Mexico and Angola, and only below those of Canadian oil sands and Nigeria. It is equally doubtful if a minimum price of $114 is required to produce a return of 15% to the foreign investor.The reason adduced for both of these is “a fiscal regime (in Venezuela) that increasingly favours the state as oil prices increase despite that its lower quality crude sells at a heavy discount to WTI.” The fiscal regime is indeed a tough one, but present, foreign investors in the Orinoco Belt have lived with it and not walked away.

In brief, I believe the report has treated Venezuela ‘s extra-heavy crudes more harshly than they deserve. They are onshore, no exploration is required, the oil in place has been determined, and the production and upgrading cost is not unduly high. Compare this to offshore deepwater Angola , Brazil and the Gulf of Mexico and the cost differential must be considerable.

 

Oliver L Campbell , MBA, DipM, FCCA, ACMA, MCIM was born in El Callao in 1931 where his father worked in the gold mining industry. He spent the WWII years in  England, returning to Venezuela in 1953 to work with Shell de Venezuela (CSV), later as Finance Coordinator at Petroleos de Venezuela (PDVSA). In 1982 he returned to the UK with his family and retired early in 2002. cDiver.net does not necessarily share these views.

http://www.petroleumworld.com

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