Oil supply is as much about money as it is about geology, technology, and politics.
The ongoing industry debate on the future of oil production, covered in a series of special reports in Oil & Gas Journal last year (OGJ, July 14-Aug. 18, 2003), largely ignores the single most powerful driver: investment incentive.
Oil companies are in business to deliver better value for their shareholders, not to provide the world with enough cheap oil to satisfy its appetites. In the current, confused consumer markets for oil products—where gasoline can sell anywhere from $1/gal to $5/gal—there is insufficient incentive to invest the new capital to meet the perceived demand growth over the medium and long term.
Business investment is largely governed by short-term performance and not by long-term social needs. Oil companies are not immune from these forces. Indeed, they are driven by financial performance obligations more than ever before. The likely consequence over the next 5 years or so is that old oil will decline faster than new oil can replace it.
An oil supply squeeze, if and when it comes, is not an Armageddon for the energy markets of the world. Modern markets are ingenious, responsive, and alert to every opportunity to make money. Governments and institutions are slow to see ahead, slow to react, and have their own electoral and political agendas. They have the power to solve most relatively simple issues, such as fuel supply, but they have not the imagination, courage, or will to initiate fiscal and legislative change to facilitate a seamless energy supply continuum or more-efficient energy demand practices. Crisis is an effective policymaker, but usually a technically unnecessary device.
As with almost all other markets, oil supply is governed by short-term financial and political interests that quite overwhelm any esoteric geological, technological, and long-term economic planning arguments from those outside the magic circle of political and industrial power. The world is a short-term place whose sequence of erratic events eventually produces the long-term outcome.
Oil field developments have planning horizons of not much less than 4-5 years, while corporate strategies are shackled by performance obligations measured in quarters or a year or two. Investors often have even shorter horizons. Company budget horizons run from quarter to quarter, and the stock market rewards companies mainly on current performance. In brief, the real world is short term. And the long run is merely a sequence of short-term behavior patterns.
Policy, fiscal disconnect
There is a disconnect between the need for long-term energy market and policy planning and short-term financial imperatives. The disconnect acts against optimization of oil supply.
As Merrill Lynch noted in a recent study, production growth outside the Organization of Petroleum Exporting Countries now is seriously hampered by the oil companies' obligatory focus on high returns. In oil field development terms, projects must be large and low-cost to achieve sufficient scale to make a difference to a large company's business. But there are only a few projects that meet those demanding criteria. For the non-OPEC world, outside the former Soviet Union, such projects can be found only in deep water. That is why large oil companies are betting heavily on developing their reserves in the US Gulf of Mexico and off West Africa to deliver the growth that the stock market now requires.
Even so, the highest net income performance in the history of an oil company clearly has no visible impact on the share price, as the first quarter results of 2003 have demonstrated.
Non-OPEC offshore oil
Evidence from the only "bottom-up" field-by-field model of non-OPEC offshore oil supply (the Petrologica NOPEX model,2 which currently comprises about 700 projects that have started production since 1997 and are to be on stream before yearend 2007), suggests that non-OPEC deepwater oil production may reach about 4.5 million b/d by 2006, with large increases off Brazil and West Africa.
These are not one-shot large field developments, however. High and ongoing drilling and development activity still will be needed to develop satellite fields to these larger, deepwater hub fields, because the peak comes fast, depletion is high, and decline even faster.
As a result, from the 3 million b/d or so average additional capacity likely to come on stream over the next several years, 800,000 b/d is estimated to be necessary to offset decline in older fields in the deep water itself.
This reality may be uncomfortable news. But the US Minerals Management Service found, in its most recent assessment of deepwater potential in the US Gulf of Mexico, that this growth-vs.-decline process is indeed the root cause of lower-than-expected aggregate medium-term production (see table). The agency now has a wide range for future production, because much hinges on the will of oil companies to develop their fields in time to offset falling production.3
The 2 million b/d net increase in deepwater oil output from 2002 to 2006 (Fig. 1) is partially offset for the whole non-OPEC offshore by more than 1 million b/d of decline in shallow and medium-water-depth fields. Older fields are losing a steady 300,000-400,000 b/d/year, while newer fields are moving into decline too, and at a fast rate as well. The reason that decline is fast in the newer fields is that the obligatory focus on returns and rapid cash payback means fast production, using as few wells as possible with high productivity. That sounds like an alluring proposition, but the reality is that the field development risk increases. There are several reasons. First, in deep water, betting on a few, very high-productivity wells early on and installing production capacity to process the expected amount of oil leaves the investment at risk to poor well performance. If an envisaged 35,000 b/d well does not perform for 6 months, then there is a significant delay in the payback. And marginal productivity dictates that the best wells are drilled first, as shown by the production profiles for wells in the deepwater Ursa development in the Gulf of Mexico (Fig. 2).4
In deep water, the fields may be sufficiently large to warrant another well, as the reserves may be there to justify the additional investment to extract the oil. However, in more-mature areas, this proposition becomes different. In the UK, where the NOPEX supply model suggested declining production before it happened in 1999, this factor is becoming very clear. Small satellite fields are being developed by a single or two high-productivity wells, which may cost $10-20 million each. A well such as this is expected to produce 10,000-15,000 b/d and extract 10-20 million bbl. Poor well performance, as in the UK North Sea's Leadon field, means that the investment is mostly written off. Drilling another well in a small field is simply not attractive offshore. The chart by Holtberg and Hirsch recently published in OGJ, showing well density in the US vs. the rest of the world, suggests that there is much scope for increasing drilling outside the US.5 This is the wrong conclusion. Intensive drilling does not happen when drilling cost and risk remain stubbornly high. Russian oil companies say they are increasing well spacing and putting emphasis on high-productivity horizontal wells to reduce costs.6 This trend is in exactly the opposite direction from the authors' conclusion.
In essence, places such as the UK and Australia are mainly adding small-scale satellite fields to their production capacity. These are short-lived additions and require sustained activity. If satellite drilling is not being undertaken, then decline will begin nationwide, however much oil is left. Oil companies are evaluating their portfolio on a global basis. Regions compete against each other. Staffs are relocated and downsized. Those are signs of a retreating industry, not of an aggressively expanding one.
If current behavior persists, then by late 2006, shallow and medium-water-depth offshore non-OPEC production may have fallen about 4 million b/d from late 2002 levels, only partly offset by an estimated 2.5 million b/d of new capacity in those water depths (Fig. 3).7
Poor well performance, slower production, and lower recovery rates than anticipated—be they in deep water or in mature areas—lead to more-conservative investment behavior. More-conservative strategy means lower production capacity, less investment, more careful planning of the wells, and probably fewer of them. If this experience is combined with the rigorous requirements on financial returns, it is clear that non-OPEC is being choked. Geology has a part in this all, since the smaller and more difficult the remaining fields get—and the farther away from existing infrastructure—the higher the risk. In other words, marginal profitability falls and thus projects are dismissed because they cannot make it up the portfolio list. This is not just an issue for the supermajors, but works for any oil company. The smaller ones may like smaller projects, but the risk for them is proportional.
The evidence from a regular basis of actual monitoring of offshore fields is that there is a preference for large, deepwater fields to be developed through a few hub systems, with a finely timed string of satellite fields to follow and small(er) satellites in other regions. The implications of the approach are that the deep water is not going to deliver at peak the optimum geological profile, but rather what is prudent to invest in. For shallow and medium-water-depth areas, the consequence is that decline is fast or slow, depending on the speed of development. But at oil price hurdles of $16-18/bbl, many fields do not stand the test and, at the $10/bbl that Total SA claims it uses, very few fields indeed are attractive. In this context, it is instructive to look at decline in the shallow US Gulf of Mexico. In 1997, the MMS expected that decline would be offset by new drilling in shallow waters to keep this part of production at 1 million b/d through the medium term. By 2002, it had dropped to about 600,000 b/d and keeps falling.
Thus, non-OPEC production from offshore fields still is growing, largely due to deepwater additions. But by late 2007, this may be over, and decline will start (Fig. 4). Decline will not start because there is no more oil to be produced. Decline will start because the return on investment is not good enough and the associated risk too high, given current requirements.
For as long as non-OPEC supply relies primarily on the private sector, there is a real threat to production growth. The counterbalancing factor in the global supply scenario for the next decade or so is that state companies have fundamentally different strategies and much longer-term perspectives. Where the private companies back off, state companies such as Pemex, Petroleos Brasileiro SA, the Chinese companies, and now the increasingly state-driven Russian companies may push forward in the best interests of their governments. While OPEC state companies invest slowly in new capacity to protect price, non-OPEC state companies have a different and often more urgent agenda where price and cost are not the primary drivers.
If global demand grows only slowly, as in recent years, and does not recover its earlier growth path, then indeed a surplus of oil may emerge and with it lower prices. The consequence will be a destabilizing impact on investment decisions.
These factors create a further problem in the service industries. Oil companies focus on reducing costs, and service companies will be required to bear a large part of that through competitive pricing. Thus they will be unable to replace their equipment since they cannot provide the returns required by their investors. This has been the lesson of the late 1990s boom. It means that prices for equipment will be volatile, and thus oil company costs hard to control.
Volatility and uncertainty form a deadly combination that works against stable growth, limits supply expansion, and threatens high prices as soon as demand expands again at the rate predicted by ExxonMobil Corp. and the main energy agencies.
The emerging risk of underinvestment in oil supply is that for the first time in the history of the oil industry, prices could rise because of a fundamental imbalance of demand and capacity and not because of political acts and threats, stock imbalances, or other temporary factors. In this sense, the recent US gasoline price sea change serves as a warning for a similar swing in global oil pries.
References
1. 2020Energy is a partnership based in Paris that seeks to address the issues of oil production, changes in market behavior, the evolution of liquid fuels of all types, and the implications for market participants in terms of investment opportunities across the energy spectrum.
2. Petrologica Ltd. owns and runs the NOPEX oil supply model and is contracted by OPEC to provide short and medium-term oil supply forecasting.
3. Gulf of Mexico Outer Continental Shelf daily oil and gas production rate projections from 2003 through 2007, US Minerals Management Service, MMS2003-028, May 2003.
4. Installed capacity is about 150,000 b/d on Ursa. MMS data show that the peak was close to 120,000 b/d and sustained for only a few months. Decline is steep in the deepwater wells. A 55,000 b/d redevelopment project is due to start early in 2004, only 5 years after start-up. First-Hand field development newswire, Strategic Offshore Research, various issues, Aberdeen 2003.
5. "Can we identify limits to worldwide energy resources," P. Holtberg, R. Hirsch, OGJ, June 30, 2003, p. 20. The well density in the US says more about the efficiency in the US than about the rest of the world.
6. See, for instance, OAO Sibneft's web site at www.sibneft.ru.
7. The offshore forecast allows for standard decline once a field goes off peak. The model has Mexican production declining from 2005 onwards as the standard production profile has the Cantarell redevelopment entering decline by then. These production expectations are in line with statements made by Mexican state oil company Petroleos Mexicanos during 2002 and early 2003. However, lately Pemex is stating that Cantarell is producing above expectations and that it will expand capacity both at Cantarell and develop and redevelop other fields to the extent that overall production will rise rather than fall. It may happen, and the impact will be material in overall non-OPEC output if it does happen. It goes to underline the point that state companies pursue different goals than do private enterprises.
The authors
Maarten van Mourik (mvm@ 2020energy.net) is an economist who has spent over 10 years focused on oil, offshore, and shipping markets. Previously with the Netherlands Economic Institute and Petrodata Ltd., he has developed a bottom-up non-OPEC offshore supply model, NOPEX, which is currently being extended to include onshore production. This NOPEX model is based on old field decline, visible new field additions, and a set of assumptions and observations with respect to likelihood of development. He also is working on a doctoral project investigating energy industry investment mechanisms and their effects on supply and markets.
Richard Shepherd (rks@2020 energy.net) is a journalist, editor, and publisher, with over 40 years' experience in the energy markets, including 10 years with McGraw Hill specializing in nuclear power, oil, and European energy policy. As founding editor of World Gas Report (now International Gas Report), he tracked the first big expansion of world gas trade as producers worked to peg gas export prices to crude oil values in the late 1970s and early 1980s. As founder and owner of Petrodata Ltd., he pioneered the application of real world oil field contracting data to oil service market forecasting and ultimately incremental oil production. He is now working on a forthcoming book, The New Energy Economy, with Maarten van Mourik to describe the economic and political changes that will govern energy markets in the next 20 years.
