Costs and the price of oil

CGES | MAY 2008 | SOURCE: Global Oil Insight

In a recent study, Goldman Sachs suggested thatthe oil market could experience a ‘super spike’ in the price of oil sometime during the next few years.

Although the oil price could obviously spike as a result of a severe disruption to oil supplies(consider the embargo of 1973-4, the Iranian Revolution of 1978-9, Iraq’s 1980 invasion of Iran and Iraq’s 1990 invasion of Kuwait), this was not the most interesting point raised by the study.

The study gave three reasons for the emergence of what it called a ‘multi-year trading band of high oil prices’ — namely:

1. Resilient oil demand growth

2. A growing premium for light-sweet crude oils

3. Further sharp increases to the industry cost structure

Of the three, the third has the greater longterm significance, because — if true — an increasing cost structure provides a rising ‘floor’ below which the oil price will not be able to fall.

In this particular market watch piece we try to ascertain whether or not the oil industry is indeed experiencing further sharp increases in its cost structure.

Our first port of call is to define what we mean by the industry’s cost structure. When the industry talks of oil’s ‘cost of supply’ it usually refers to a number of components in addition to the all-in cost of producing the crude oil itself. These include the cost of transporting crude to local refiners and other customers (for example, those who might be burning crude oil in electricity generation), or to export terminals for shipment to distant locations.

The all-in cost of producing crude oil covers the cost of exploration (including the expense of drilling unsuccessful wells), the cost of drilling the production wells, the cost of casings, pipes and the specialised down-hole instruments that have to be installed in the wells, as well as the multitude of surface equipment, facilities and pipelines that have to be put in place in the oil producing regions.

These costs are usually higher in the offshore areas and include the expense of the huge platforms that have to be constructed and then moved and installed in the offshore locations. One should also include royalties, excise taxes and financial costs, but for simplicity these costs are not considered in this discussion, because they differ considerably among countries and also vary over time.

The main constituents of cost that have been discussed thus far concern the heavy front-end investments required to get oil out of the ground (capital costs). When these expenditures are amortised and discounted over the total amount of oil expected to be produced in future years they comprise the capital component of the oilfield’s fully built up cost, which can be calculated on a per barrel basis.

Having drilled the necessary number of wells and built and installed the appropriate equipment, oil production commences, leading to a new set of costs that are strictly related to output (operating costs). Once production is under way, these latter costs are the only ones that really matter, the former being considered ‘sunk’ costs.

As long as the price of oil (minus excise taxes) exceeds the operating cost (per barrel), it makes economic sense for production to continue in the oilfield in question.

Do oil prices lead or follow oil production costs?

Although from a theoretical point of view fully built up upstream costs can drive oil prices higher, a quick consideration of the way in which the oil industry actually takes decisions suggests that oil prices lead costs and not vice versa.

The decision makers’ perception of future oil prices is the critical factor in undertaking the development of an oilfield: development of high-cost oilfields would get under way only if future oil prices are expected to be high enough.

With low oil prices in prospect, only low-cost fields would be considered suitable for development. Yet, in practice the future price of oil might turn out to be quite different from what was expected, especially when the life of a field might last a couple of decades.

If prices happen to be greater than anticipated, higher profits would obviously ensue, but trouble would arise if future oil prices were lower than expected.

It is important to note that in both cases, once the field has been developed, oil production continues at the maximum planned rate no matter what the actual price of oil might turn out to be in the future. Under most circumstances, the volume of supply would not be affected by conditions in the oil market.

Even if there were a collapse in the price of oil, production would not cease, because the investment would be treated as a ‘sunk’ cost. Indeed, in certain circumstances production might continue for a while even if operating costs exceeded the price of oil. This could happen if the cost of maintaining the shut-in oil wells and the dormant production facilities is greater than the financial loss incurred by continuing to produce oil.

However, production at a loss would not continue indefinitely: when the resource owners can no longer absorb the losses and there is little hope of a price recovery then output will cease. Costs are not that high.

As it happens, the likelihood of oil production having to cease as a result of the price of oil falling below operating costs is very low indeed, because operating costs are not as a rule high compared with the prevailing price of oil. The North Sea is an oil producing area of the world where costs are expected to be high because of the harsh climatic conditions, but this is not necessarily the case.

A detailed CGES study of production costs in the North Sea showed that in the late 1990s 68% of Norway’s oil production had operating costs below $2/bbl and 97% below $4/bbl. The operating costs for 69% of UK production were below $5/bbl and for 97% were below $8/bbl.

Operating costs are usually lower in other parts of the world. Quite a number of stripper wells in the US have higher operating costs, but only some of them were shut in when the oil price collapsed in 1998 and early 1999.

The fully built up costs of 167 fields in the North Sea (with oil reserves amounting to 15 billion barrels), which were studied by the CGES in the late 1990s, showed that the weighted average all-in cost was less than $10/bbl for the whole of the North Sea. More than 99% of the reserves in Norway and 82% of those in the UK were associated with all-in costs of development and extraction below $15/bbl. The cost of oil production is much less in the Middle East.

Another CGES study suggested that Saudi Arabia’s operating costs of oil production were less than $1/ bbl and its fully built up costs were below $3/bbl. For his part, Ali Naimi, the Saudi Oil Minister, stated some time ago at the 7th Arab Energy Conference in Cairo that Gulf production costs averaged $2/bbl, compared with $6/bbl in the rest of the world, and that the average cost of developing new oil in the Gulf was $3,500 per peak daily barrel versus an average elsewhere of $20,000 p.pk.d.bbl.

What do the operators think?

Despite the high prices that have prevailed in the world oil market over the last two years, the global oil industry’s perception is that oil prices will be lower in the coming years. The industry’s investment decisions and the choice of oilfield development projects are based currently on the assumption that oil prices cannot remain at these exorbitantly high levels. It is important to bear in mind the long lead-time for most oilfield operations.

First there are the years of exploration, during which a number of dry wells are drilled before the discovery of a commercially viable field; then there is the development phase of a fully appraised oilfield, which takes at least a few years to complete and sometimes quite a bit longer; finally, there is the production phase that typically lasts for a couple of decades — and often more.

The industry’s decision to undertake the development of an oilfield thus cannot be based simply on current or near-term oil market conditions. It depends instead on the investor’s outlook for oil prices over the lifetime of the field (usually more than 15 years into the future).

The price outlook thus becomes the key decision factor as to whether the development of an oilfield should proceed. These days, the cut-off oil price used by most oil companies to decide on the merits of oilfield development projects is not much above $20/bbl and until very recently this price was lower still. In other words, for a new oilfield to be developed and operated over its planned lifespan the fully built up cost should not exceed $20/bbl.

If oil prices happen to be higher than this threshold all is well and good, and the investment is considered highly profitable. However, the key consideration is whether the project is able to yield the desired financial return with the oil price at the benchmark level. The price of oil therefore influences the choice of oilfields to be developed and thereby the overall cost of the oil produced by the industry. It seems, from the behaviour of the oil industry’s key decision makers, that these days the all-in cost of producing the marginal barrel is not greater than $20/bbl.

Variations in production costs

A number of studies have demonstrated that oil production costs have been falling in the last few decades. For example, the CGES’ study of the North Sea showed that the average fully built up cost of the oilfields that were examined declined during the 1990s by 31% and 17% in the Norwegian and UK sectors respectively.

Improvements in technology lead to a reduction in costs and a concomitant increase in the volume of oil to be extracted from an oilfield. Thus, although costs are expected to rise in a maturing oil province, technological innovations and improved institutional arrangements resulted in a decline in costs. The same has been observed in other parts of the world, although costs might have increased for individual fields in some locations.

Because of the finiteness of oil resources one would expect to observe rising costs of extraction over the longer term. After all, logic dictates that the more oil that is discovered and produced, the more difficult and therefore costly it gets to find, develop and extract the remainder. However, although this concept is correct in principle, the time horizon to experience rising costs due to diminishing oil resources extends way beyond the next two or three years.

Oilfield costs do fluctuate temporarily due to global business cycles and sudden surges in the demand for and supply of particular tools or services. As one would expect, however, these cost fluctuations are for those goods and services required for oilfield development and production and the changes in such costs are thus usually transient. For example, the recent rise in the worldwide price of steel has resulted in an increase in the raw material costs for offshore platforms and production wells.

Similar increases could occur in the price of oilfield services if the global oil industry embarks on a massive expansion of exploration and production, but these increases would also be temporary. Their magnitude and duration should not cause any significant rise in the price of oil in the international market for the following reasons:

First of all, the oil industry itself will tend to scale downwards its expansion plans or delay the higher-cost projects in response to the higher prices for services.

Secondly, high prices in the service sector would also encourage new entrants into that part of the oil business and result in a lowering of prices for these services.

Lastly, it is good to remember that the international oil industry generally uses its own cash flow for its exploration and development expenditure. A reduction in the price of oil is commonly followed by a reduction in industry expenditure and, conversely, an increase in oil prices usually leads to rising expenditure.

Delays in expenditure could occur or the details might be different due to specific company policies, but the overall pattern is generally valid.

The pattern of spending can amplify fluctuations in the demand for and thus the price of oilfield-related materials and services, but not the price of oil.

Global oil industry E&P expenditure

The oil industry’s expenditure in the last few years has not grown in proportion to the rise in the price of oil. This could be explained in part by the industry’s apprehension about the durabilityof the recent high oil price regime.

Nevertheless, oil industry expenditure has actually increased and companies have been spending more on exploration and production. The annual surveys by City Group’s Smith Barney Division show that the companies responding to the survey increased their spending by 9.4% in 2003 and 10.3% in 2004.

The December 2004 plans suggested an increase of 5.5% for 2005, but the actual figure could be higher. It is interesting to note that the December 2003 plans for the 2004 spending round suggested an increase of 4.4% while actual growth in spending was 10.3%; thus, a similar rise in actual exploration and production expenditure is possible for 2005.

Total E&P expenditure commitments for the year 2005 by the companies responding to the survey in December 2004 amounted to $41.2 billion for the US ($14.2 bn by the majors and $27.0 bn by independents), $18.7 billion for Canada and $112.5 billion for the rest of the world — a grand total of $172.5 billion. As just noted, the actual may well be greater than this sum.

For their part, the national oil companies — the OPEC countries in particular — have also increased their oilfield development expenditure and expanded their oil production capacity. Again, one could argue that they should have undertaken such expansionist activities earlier.

Alternatively, one could accept their argument that, until very recently, conventional wisdom held that the future growth in demand for OPEC oil would be sluggish or would decline, thus leaving OPEC with rising unwanted production capacity. Whatever the arguments, some of these countries and their national oil companies are now vigorously expanding their oil production capacity, adding to the potential supply of lower cost oil.

Saudi Arabia’s last entirely new oilfield was Shaybah, inaugurated in March 1999 at a total cost of $2.5 billion for 0.5 mbpd of extra light oil (implying an investment intensity of $3,500 per peak daily barrel).

Just recently the Kingdom added 0.15 mbpd of capacity at the Abu Safah field (for $0.45 bn at an intensity of around $3,000 p.pk.d.bbl), 0.5 mbpd at the Qatif field (for $1.3 bn at $2,600 p.pk.d.bbl) and plans 0.3 mbpd by 2Q06 at the Haradh-3 zone of the supergiant Ghawar oilfield (for $0.3 bn). It intends to expand its capacity further by developing 0.5 mbpd of Arab Light at the Abu Hadriyah-Fadhili-Khursaniya complex ($1.5 bn) and 1.1 mbpd of Arab Medium at the Khurais oilfield (for $3.1 bn at $2,818 p.pk.d.bbl).

Algeria is another OPEC country that has expanded its capacity since 1999, principally at the northern sector of the Hassi Berkhine field with Anadarko (0.23 mbpd for $1.9 bn at $8,300 p.pk.d.bbl) and at the Ourhoud oilfield with Cepsa, Anadarko and Burlington (0.23 mbpd for $1.3 bn at $5,650 p.pk.d.bbl).

Nigeria too has boosted its capacity from 2.3 mbpd in 1999 to 2.65 mbpd at present (of which around 0.25 mbpd is shut in because of unrest in the Niger Delta), but the much-delayed deep-water Bonga field has still not come on stream (0.25 mbpd for $2.7 bn at $10,800 p.pk.d.bbl), although operator Shell is targeting August 2005.

To conclude, oil production costs are not high and cannot be blamed for soaring oil prices. The recent rise in the price of oil has been due to a number of other factors. Compared with previous years, world oil demand in 2003 and 2004 grew by a factor of three or more (1.8 and 2.7 mbpd versus 700 tbpd).

With annual growth in non- OPEC oil production of around 1 mbpd, OPEC’s spare oil production capacity has been eroded. Furthermore, political unrest, a turbulent Middle East, virulent terrorism, adverse weather conditions and various technical problems, have conspired at times to interrupt the supply of oil from some areas.

Meanwhile, in view of the ongoing uncertainty about oil supplies and whether the system can cope with continuing strong demand, large speculative funds have entered the futures markets to take advantage of rising oil prices. Thus, it is fair to say that market perceptions of whether or not the tight market will persist will play a much bigger role in determining the oil price in the next few years than the cost of producing it.