Reposted from WorldOil.com.
Oil Outlook 2004
Matthew R. Simmons
The year 2003 was marked by a string of oil surprises. It is beginning to look as if “normal” is an oxymoron when used with the oil market. Perhaps 2004 will be the year when more answers than surprises occur.
Oil prices were the first surprise. For the fourth year in a row, West Texas Intermediate crude prices spent most of the year above $30/bbl, far higher than most “oil experts” had forecast, Fig. 1. The only time that oil prices took a sharp drop below this level was when the Iraq War broke out, spurred by the mistaken view that war in Iraq would soon be followed by a glut of Iraqi oil.
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Surprise number two was the growth in oil demand, despite weak economic conditions around most of the globe. For a decade or more, oil observers have fretted about how weak global oil demand would be. This thesis turned out to be wrong.
Demand Growth Sources
Global oil demand grew 1.4 million bpd in 2003, or 50% higher than the 15-year average growth of 900,000 bpd. Over the last 15 years, global oil demand increased every single year, growing 13.5 million bpd over the period, despite decreased demand from the Former Soviet Union (5.3 million bpd). Had FSU demand grown as fast as the OECD’s rate, global oil demand would now be somewhere between 85 million and 90 million bpd!
Fueling this growth was China, but demand was also strong in the Middle East, parts of Latin America and throughout most of the rest of Asia. Only a few years ago, conventional energy wisdom assumed that it would be almost impossible for Asian oil demand to see any robust growth until Japan’s economic miracle returned. Today, Japan’s economy is still weak; its oil demand has barely grown over the past decade. Nonetheless, this did not stop demand growth in the rest of Asia.
Perhaps the biggest surprise regarding oil demand was the growth that happened in the US. For two decades, most forecasts assumed that growth in US oil demand was slowing each year and would soon stop. In the early 1990s, a widely circulated National Petroleum Report on the future of the US refinery industry envisioned in its base case that US motor gasoline demand would stay flat at 7.2 million bpd for 1996 through 2010. It projected little growth for other oil products.
This gloomy view of US oil usage turned out to be wrong. By 2003, US oil demand was setting new records almost every month. Leading the way was the backbone of US oil usage, motor gasoline, where total demand came close to averaging 9 million bpd for the entire year. Peak summer usage exceeded 9.4 million bopd. There was virtually no evidence, either, that surprisingly high oil prices had any impact on any aspect of US oil demand.
The world still seems to have an insatiable appetite for oil. Almost five billion people have very limited use of cars and other energy-consuming luxuries, but their access to global media is creating pent-up demand that could expand this usage.
In the 60 years since World War II ended, the only time there was any meaningful downturn in oil demand, outside the one-time collapse in FSU oil demand, was when usage of oil in any great quantities to generate electricity stopped from 1979 to 1983. This one-time change was triggered more by the advent of nuclear power coming on-stream than the explosion oil prices.
There were a few one-time reasons fueling the strong, global oil demand in 2003. Japan’s nuclear plant shutdown, when some cracks appeared, created as much as 100,000 bopd to 200,000 bopd of extra oil demand. The extremely high natural gas prices in the US caused about the same level of added oil usage, due to fuel switching. But these impacts were tiny compared to overall growth in global oil demand.
Oil Supplies
The third 2003 surprise was what happened to oil supplies. A widely anticipated surge never happened. As far as any good data now show, oil supplies barely grew in most regions, except the one area where demand also failed to grow, the FSU. Despite exceptionally high oil prices for the fourth consecutive year, no serious surge in oil supplies resulted.
There was a genuine glut of published oil supply forecasts that continually predicted that massive amounts of new oil were about to appear. The common theory was that these new volumes would bring oil inventories back into balance or even build storage until it was too full, but the surge never came. The only part of the world with any sizeable supply gain was the FSU. Elsewhere, output increases were modest, keeping inventories tight all year.
Supply did grow in some areas. Mexico added another 200,000 bopd offshore, as all the benefits of the $10.5-billion, Cantarell tertiary nitrogen injection program bore their fullest fruit. Now Cantarell’s output seems likely to begin a steady decline. Canada enjoyed growth in its production of synthetic crude and bitumen, which offset supply declines from conventional crude supplies. Equatorial Guinea added close to 100,000 bopd, and Exxon’s major oil project in Chad finally came onstream. Algeria added some new productive capacity, and Brazil still hopes its oil production will grow by 100,000 bpd, although the last few months of 2003 saw unexpected production declines.
Positive production surprises, however, were few and far between. Meanwhile, significant output declines were reported in countries like Oman – where its giant Yimal oil field is now in serious decline – and Colombia, whose oil production peaked at almost 800,000 bpd in 2000 but now struggles to stay above 500,000 bpd. Egypt also came close to hitting a record 1 million bopd as recently as 1995, but now the country struggles to stay above 700,000 bopd. A country reporting oil supply growth is becoming the exception to the rule as declining output from almost all older fields is offsetting most new oil projects.
Future of the North Sea
The North Sea, the single greatest new source of global oil supply in the past 30 years, has peaked. There are still a handful of positive supply additions like the UK’s Buzzard field (scheduled to come onstream in 2006) or the two significant oil projects in Norway that should add a combined 300,000 bpd in 2004. But none are big enough to offset the steady declines in most North Sea fields. All of the first- and second-generation, giant North Sea oil fields are now in steep decline. Almost all new fields are small, peak fast and decline even faster.
The North Sea still has the potential to become another Gulf of Mexico (GOM), where scores of small fields can be developed rapidly by utilizing the massive production infrastructure that runs up and down the North Sea’s spine. Making this transition happen will not be easy. North Sea exploration is at record-low levels. The issues of “fallow fields” and relinquishment of licenses lacking plans for development have yet to be resolved in a manner that ensures a new generation of exploitation and, hopefully, an era of new exploration in the region north of the existing North Sea. How quickly the North Sea evolves into a new era will be one of the biggest issues during 2004.
Deepwater Outlook
This dismal picture for reliable growth in conventional crude supplies moves deepwater oil onto center stage in importance. It is hard to envision how tight global oil markets might be as 2004 begins, had the miracle of deepwater oil not occurred, Fig. 2. This last frontier of new oil would not have happened, if various technology miracles had not combined to finally allow oil to be produced at depths reaching nearly two miles under the sea.
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But even the deepwater oil miracle is showing some maturity. Most of the first-generation deepwater oil projects are in serious decline. The typical production profile for most new GOM deepwater projects is about 24 months to reach peak production, and then a steep decline occurs, unless new satellite fields can be found and tied back to buffer the declines.
Exploratory success rates for new deepwater fields also seem to be waning after a half-decade of robust successes. A few, new deepwater projects are running into tougher-than-expected reservoir conditions. Shell’s Brutus project in the GOM is a classic example. Brutus was designed for peak production of 110,000 bopd and another 150 MMcfgd. Actual peak rates were less than planned, and nine months later, production is around 35,000 bopd and about 44 MMcfgd.
Several exciting new deepwater projects are scheduled in Brazil for 2004, but maintenance and decline problems in the country’s current deepwater fields caused 2003′s oil output to miss planned targets. Angola’s deepwater story is similar. In second-half 2004, its massive Kizomba A project will finally come onstream, but 2003 production will be 15,000 bopd to 30,000 bopd less than planned. This will occur while Angola’s older fields experience normal production declines. Like the Gulf of Mexico, Angola has also seen a spate of disappointing dry holes instead of the promising new finds that were expected.
FSU Impact
The irony amid this litany of less-than-expected supply gains was how vital it was for FSU oil supply to suddenly grow once more. The FSU was once the world’s single, largest oil producer, Fig. 3. Soviet oil peaked at more than 12.5 million bpd in the mid-to-late 1980s. By 1996, FSU production had fallen to only 7.1 million bopd. It stayed at this low level through the end of 1998, and no one forecast any improvement. Suddenly, and to everyone’s complete surprise, production growth began. By 2001, FSU production had grown 1.5 million bopd. By the end of 2003, reported FSU oil production was up another 2.2 million bpd.
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Because FSU oil demand has remained very depressed, a large portion of FSU production gains is exported. This became the unexpected source of supply that so many oil pundits had assumed would come from everywhere but the FSU!
Three key issues keep this FSU supply surprise cloaked in uncertainty. First is the accuracy of reported supply gains. Most of the gains are probably real, but some might also be simply “optimistic reports.” Second is the degree to which these production gains are sustainable. Most current gains come from workovers and more infill wells in old fields. Other than a handful of massive projects like Sakhlin I and II or the Caspian’s Kashagan project, little exploratory drilling is taking place. Third is whether FSU oil demand stays low, and whether the ruble stays as undervalued to the dollar as it has been since 1998. At some point, improving economic conditions must jump-start FSU oil demand, assuming the economy continues to improve. FSU demand was once more than 9 million bopd. Today, it is still mired at around 3.8-to-4.0 million bopd. Even a partial return to old demand levels could bring much of the FSU’s surprising exports to a quick halt.
An improving economy should also strengthen the ruble. Over the last three years, the strong dollar denominating oil prices, combined with a very weak ruble, gave a typical Russian oil producer the benefits of experiencing the equivalent of $50-to-$100 oil, as long as production expenses were paid in depreciated rubles. Any meaningful strengthening of the ruble would immediately offset many of the FSU’s one-time ruble/dollar cost advantage.
If FSU oil gains cease, or the region’s ability to export most of these gains is not sustainable (and any prudent planner should at least create a scenario that this happens), then OPEC is propelled back into a powerful role not enjoyed since the 1970s.
OPEC’s Influence
It then becomes extremely important to properly understand the degree to which OPEC’s oil production capacity is sustainable, along with the group’s ability to grow its oil exports.
Conventional wisdom had assumed for decades that OPEC producers, in general, can bring on massive amounts of added oil whenever it is needed. There is mounting evidence, however, that most OPEC producers are reaching, or have now reached, their limits to increasing oil output from existing, older fields. Iran, Kuwait, the UAE, Algeria and Libya are all seeking foreign capital and expertise to develop new fields, or capital and new techniques to halt declines that are underway in so many of their key oil fields.
Venezuela faces political, financial and geological problems. In the wake of massive firings of half of PDVSA’s workforce, the country faces a genuine risk of overproducing its eastern oil reservoirs and suffering steep declines in its heavy Lake Marcaibo oil output. Nigeria struggles with continuing civil unrest and financial woes. Indonesia’s oil production has clearly peaked. Libya and Algeria could both be positive supply surprises, but their base production is too small, relative to the rest of OPEC, to make a difference.
Because some OPEC producers are out of spare capacity, or will soon reach their limits, the spotlight is put squarely on Saudi Arabia, the world’s most important oil producer. The kingdom has worked diligently to maintain the world’s only meaningful amount of spare production capacity.
While conventional wisdom has rarely questioned whether Saudi’s ability to easily grow its oil might end, it is becoming a genuine question whether the country’s spare capacity can be sustained. For the first time in memory, key oil officials in Saudi Arabia are acknowledging that even they have to bring a range of 500,000 bpd to 800,000 bpd of new oil production onstream each year, merely to replace normal declines in key, old fields.
For four decades, Saudi Arabia has been a true oil miracle, Fig. 4. But this miracle occurred through the discovery of five remarkable, super-giant oil fields found between 1940 and 1965. These five fields collectively produced 85% to 90% of all Saudi Arabian oil output. They all maintained high well-flow rates through an extremely efficient water injection program to maintain high reservoir pressure and sweep oil from the flank to the crest of each field. All five of these giant fields are nearing the end of their primary and secondary recovery, because both phases happened at the same time. Later this year, I hope to publish a manuscript detailing the challenges that Saudi Arabia now faces to keep its oil miracle alive. The data I have reviewed is alarming, as it would be such a jolt to the world’s oil supply if Saudi Arabia’s flow of crude also began to decline.
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Putting prices in perspective. In light of all these factors, high oil prices over the past several years should not have been such a surprise. The real surprise, when historians look back on this era, might be how long the price of oil was able to stay so low, Fig. 5.
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Few observers seem to have noticed that the cost to find and develop oil and gas production has essentially doubled over the past four to five years, despite most oil service prices being abysmally low.
Write-downs in proven reserves seem to be accelerating, even with prices remaining high. This, in turn, raises all costs per barrel even higher. Tanker rates recently increased to levels as high or higher than the early 1970s, and 2003 ended at rates almost five times what they averaged for most of the past decade. The cost of cheap energy might be nearing the end of a long run.
The 21st century oil markets, so far, have been very different than so many observers expected. These surprises might not be as random as many believe. A clear sea change may be underway.
Too often over the past several years, supply fell behind demand at various times. Each time that this occurred, oil inventories were used as a temporary method to bridge a supply/demand gap. With most OECD oil stocks now at unprecedented lows, this last, one-time supply bridge has almost run its course.
Thus, 2004 might well be the year when many of these key questions that made the oil markets so abnormal for so long finally get clear answers.
| THE AUTHOR | |
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Matthew R. Simmons, Chairman & CEO of Simmons & Company International graduated cum laude from the University of Utah and received an MBA with distinction from Harvard Business School in 1967. He served on the faculty of Harvard Business School as a research associate for two years and was a doctoral candidate. After five years of consulting, he founded Simmons & Company International in 1974. The firm has played a leading role in assisting energy client companies in executing a wide range of financial transactions. He is a trustee of The Museum of Fine Arts, Houston, and The Farnsworth Art Museum in Rockland, Maine. He serves on the boards of several industry and civic groups. He is past chairman of the National Ocean Industry Association, and he serves on the board of the Associates of Harvard Business School and is a past president of the Harvard Business School Alumni Association. Mr. Simmons’ papers and presentations are regularly published in a variety of publications and oil/gas industry journals, including World Oil. |
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