During the next few years, worldwide refiners will confront the challenges of mismatched regional supply and demand for refined products, tightening fuel specifications, less excess capacity, and changes in crude quality, according to speakers at a conference hosted by Cambridge Energy Research Associates in Houston Feb. 15.
Globally, the refining challenges fall into three categories, according to James Smith, director for CERA. The first challenge is supplying growing volumes of light products.
"Recent demand growth varied by region," Smith said. "But 2004's demand surprise is a global phenomenon and refiners in every region are facing the need to supply increasing volumes of product."
The second challenge is meeting the changing mix of refined products.
"We see refined product demand growth that has been biased towards middle distillates," he said. "This is driven by transportation demand and is occurring to varying extents globally."
The third challenge is that refined product quality is tightening in virtually all markets. He said that, "refiners in North America and Western Europe are facing mandatory reductions in gasoline and diesel sulfur, implemented on a timetable that extends from right now to the end of the decade. Even in emerging markets, sulfur levels are being reduced."
Other speakers noted that, although more refining capacity will be needed, the right type of production for a given region is also important.
"Refining capacity challenges are somewhat different depending on the region," according to William Veno, director, global downstream for CERA. "In Western Europe, for example, [there is] a growing imbalance between the productive capacity and demand. [There are] shortages of gas oil and surpluses of gasoline blending components.
"In the US, over the last several years, growth in oil demand outpaced increases in refining capacity, leading to the tightness in the market last year that led to record-high margins," Veno said. "In the emerging markets, Latin America and Asia-Pacific, the challenges facing the refining sector are a more fundamental need of refining capacity to meet rapid demand growth."
"Products are moving farther and farther all the time," according to Michael Hoffman, group vice-president of global refining, BP PLC. "And with clean fuels specifications, the chance of contamination is going up. It is very difficult to move zero-sulfur diesel anywhere without having it contaminated, and [refiners] will be required to move it farther and to more locations.
"The globe is much more dependent on regions to sort out the global issues," he said.
Refiner challenges
Refiners face these challenges while dealing with a changing crude supply environment. "The quality and availability of crude oil holds the potential to change the game for refiners, both at the regional level as well as the asset level," Smith said.
During the past 25 years, refiners have consolidated operations, experienced compressed margins, boosted efficiency, shut down refineries, increased the size of bigger refineries, and been more regulated, according to Hoffman.
"Part of the answer to what might happen in the future [lies in] the behaviors that we have learned over that 25-year period of consolidation—that it is very difficult to make money in refining," he said. "The returns over the past 25 years have been consistently low and so we have a fairly risk-averse industry. [Refiners have] succeeded in things like small debottlenecking, though we tend to not make money when we do big things.
"Assuming that demand patterns continue, it is very hard to see how investment will go in fast enough," Hoffman said. "There will be a big change in the way that governments and public policy happens becauseUrefining infrastructure is going to have to take a much bigger role in the public policy debate. Refining capacity is going to be a big deal.
"At BP, we are much more interested in investing in the downstream than we were a few years ago," he added.
Crude quality
In 2004 with the high refining margins, some refiners still suffered, according to Hoffman.
"The winners were [those] that could run heavy crudes, make finished products out of it consistent with the demand we saw," he said. "The losers were simple hydroskimming refineriesUif you can't run heavy crudes, if you can't make products, then your margin was zero or worse in 2004."
Many refiners feel that the overall crude slate is becoming steadily heavier and more sour. This may be a misperception, however, according to Edward Galante, senior vice-president, ExxonMobil Corp.
"If you look at the data, the world average crude gravity has actually been fairly constant for a long time," he said. "Uthe gravity of crude coming out of the ground, both for several decades in the past and for the near term, we find that the average crude mix is not getting heavier at all."
Galante said there were expected geographic variations, such as heavy crude from Western Canada, and short-term variations due to pricing.
"Clearly this past year the marginal crude production available to the market in the short-term was heavier than the average," he said. "But when we look at the mix of crude coming on production and that which is depleting, we believe average crude gravity will become a bit lighter between now and the end of the decade."
He said that crudes might appear to be getting heavier because product demand has gotten lighter.
"The marketplace wants more of the lighter, cleaner, higher-valued products; not the heavier fuel oil-type products," he said. "It is the transportation sector driving the growth. In fact, this past year, we saw an unusual jump in light product demand that we estimate at about 3.5%."
Because refining capacity is fixed in the short term, refiners can run lighter crudes to produce lighter products, which is why the prices were bid up. "But heavier crudes have not risen nearly as much, resulting in an increase in light-heavy crude spreads," Galante said.
"There wasn't enough refining capacity to deal with this heavier crude," Hoffman said. "We saw light-heavy differentials blow out in 2004. That hadn't happened for some time."
US refining
According to the US Department of Energy's Energy Information Administration, US oil consumption from transportation will experience a 1.8-2%/year growth rate to 2025. This equates to just less than 15 million b/d of refining capacity by 2025, according to Gary Heminger, president of Marathon Ashland Petroleum LLC (MAP).
"Energy demand will increase and capacity additions will be limited to existing refineriesUwith a bias toward [Petroleum Administration for Defense District] PADD 3," he said. "Operating utilization will remain very high, and we are very bullish on the crack spread trends." (For a diagram of PADDs, see OGJ, Aug. 2, 2004, p. 53.)
"We believe that [in] PADD 2Uthere will little capacity gain in comparison to the US Gulf Coast or PADD 3," he said. "PADD 3 is where you are going to see growth, but we don't believe it [will] keep up with the requirements of transportation fuels."
Heminger said that US refiners have been running at record utilization rates for the past 3 years, an average of 90-92%. And because demand keeps increasing, the US must import more products.
"More components have been coming into the US than finished gasoline because we have had to meet the clean gasoline specifications, started on Jan. 1, 2004, and we will have to meet the clean diesel specs on June 1, 2006," he said. "We have seen the imports go from 1.9 million b/d to about 2.5 million b/d in the mid-2000s."
He believes that imports will only increase in the future. But a greater concern is how the industry will deal with the ultralow-sulfur diesel regulations of 15 ppm.
"Every time you back up the chain—go through a manifold, a tank, a pipeline—you have the opportunity to pick up a contaminant, and that contaminant is another ppm of sulfur," Heminger said. "Our numbers are illustrating that you almost have to come out of the refinery at 5 ppm or less in order to have salable product at the retail level.
"We think that is going to be a real struggle for the industry," he said. "We think that this will offer a tremendous amount of dislocation to the marketplace."
In the US, a confluence of increased demand, a recovering economy, and a shortage of capacity led to increased crack spreads in recent years. In 2004, the large increases in crack spreads, however, were due in part by the sweet-sour crude differentials.
Heminger said that crude supplies from Western Canada would play an important role, especially for refiners in PADD 2.
"Today there [are] about 1 million b/d of production of a bitumen type of blend," he said. "As we go out to 2015, there areUforecasts that believe that number is going to increase another 1 to 1.5 million b/d."
How to process this crude is the real question, according to Heminger. The key is the light-heavy differentials that occurred in 2004.
There are, however, pipeline projects and other infrastructure already in place to bring additional supplies of heavy Canadian crude to the US, specifically to PADD 2. He said that much additional investment would be required to process heavy oils.
"If you look at all the production that supposedly, or possibly, can come on stream by 2015 for PADD 2, it has such a high vacuum gas oil content that it fills up all our cat crackers," he said. "Therefore, we [will need] tremendous investment on the cat cracking side, or some other solution, to run that product through our refineries" as they are configured today.
Possible investment strategies include either installing additional coking capacity or upgrading the crude in Canada and bringing down the synthetic crude as a blend.
"The typical coker project [for] a 100-200,000 b/d sour refinery is to put in a 25-30,000 b/d delayed coker," he said. "With that, we could run 100,000 b/d of [Western Canadian] crude.
"However, that costUis somewhere between $500 million and $1 billion, depending on how many other processing units you are going to have to [modify]. ... Most of our capital [since the 1990s] has been spent to meet the clean fuels specifications. So the investment [required in addition] to the investment cycle that we have seen recently, we believe could be severe in order to be able to run those types of crudes."
Galante said that perhaps another industry misconception is that there is a shortage of global refining capacity. And while true when measured as distillation capacity, a better measure of utilization is conversion capacity, especially in the US.
"Conversion capacityUhas been creeping up here in the US by about 2%/year," he said. "Last year, we saw a more dramatic spike in global demand for light products. As a result, conversion capacity utilization increased, and the market became tighter for light products. And in tighter markets, one can expect higher margins.
"Challenges and opportunities that we have are: crude prices [will] be very volatile, crude oil characteristics are going to change, requirements for finished products are changing, [and] a number of upgrade additions are going to be required to meet the increased demand," Heminger said. "With that comes significant investment."
Europe
The trend to use more diesel fuels in Europe is having profound effects on the worldwide refining industry.
In Western Europe, according to Smith, overall demand is not outpacing refining capacity. The ongoing dieselization of the region's vehicle fleet, however, is stretching the refiner's ability to produce middle distillates and dispose of surplus gasoline.
"Over the past 5 years, falling gasoline demand has increased surpluses, which are growing on the order of 50-60,000 b/d each year," Smith said. "This presents European refiners with a capacity challenge."
"In Europe, a lot of refineries reduced capacity," Hoffman added. the objective being "not to maintain capacity but to minimize investment to meet clean fuels.
"Northwest Europe has flat to declining demand for finished products," he said. "But underneath that, there is a massive structural shift from gasoline to diesel."
Hoffman said that Europe's refining system is old and was not built for an unbalanced product demand. Europe is now structurally short of diesel, middle distillates, and long and getting longer on gasoline and fuel oil.
"In 2004, this balance was met by exporting gasoline to the US, by importing low specification middle distillates from Russia as they dealt with their crude logistics issues, and by exporting fuel oil to Asia," Hoffman said. "It's a very tight and difficult balance."
From a configuration standpoint, Europe needs more bottoms upgrading, less FCCU capacity, more hydrocracking, and high-pressure hydrotreating, which will take significant amounts of investment to fix. This is a risky proposal considering that Europe has a "pretty flat demand market."
Crude logistics, on the other hand, are driving the refining industry in Russia.
Refineries there run to "process crude into something they can export," Hoffman said. "So there's been a lot of crude run in Russia that comes as intermediates into Northwest Europe. That has really helped the diesel situation in Northwest Europe but aggravated the fuel oil situation."
It's unclear, according to Hoffman, whether Russian refiners will continue to export the same products because those refineries are supplying more gasoline and octane to satisfy domestic demand.
"Octane requirements for Moscow and St. Petersburg are growing very rapidly and the refinery issue is to make high-octane gasoline for western vehicles," he said.
Overall, the future of Europe's refining sector is uncertain. "A demand structure that is completely out of whack with what refiners can produce is going to cause more and more dislocations in the market," Hoffman said. "Eventually either that will get sorted out or we have to change the way we [operate] there."
Asia-Pacific
In 2004, China's demand grew about 930,000 b/d in 2004, almost 17% year on year, accounting for about 35% of worldwide incremental demand, according to K.F. Yan, director for CERA.
"We do not think that growth rates this year will look like [those in] 2004," he said. "China's oil demand will continue to grow strongly, at a rate much faster than the world average, and will continue to push global demand growth."
He said the 17%/year demand growth experienced in 2004 is unsustainable. This is because the factors that led to this high demand growth in 2004 were either cyclical or temporary.
"An important factor was a very severe nationwide power shortage," he said. This power shortage created a large demand for coal, which led to increased utilization of rail and truck lines, and increased demand for oil.
"The power shortage won't be as bad in 2005—new generation capacity is coming online and the power shortage will be gone in 2-3 years," Yan said.
"Secondly, the mode of economic growth is beginning to change," he said. "The recent high level of investment in the Chinese economy is difficult to attain and is already moderating."
At a 4%/year average growth, China will represent "about 14% of world oil demand by 2030, twice its share today," Galante said. Downstream demand growth for oil will continue "at a steady pace globally, primarily driven by transportation and concentrated in Asia-Pacific."
"Asia-Pacific is fast utilizing capacity surpluses, which emerged during the 1990s," according to Smith. "The big question, especially in the high growth non-OECD [Organization for Econmic Co-operation and Development] markets such as China, is whether new additions can keep pace with surging demand."
"What China decides to do from a public policy perspective will be very profound for our industry," Hoffman said. The Chinese "have a lot of issues they need to sort out—one of their highest priorities is energy security. They also have local emissions issues, greenhouse gas issues, and if they choose a public policy perspective that favors diesel like Europe has, it is going to aggravate the global issue that we have with supplying distillate."
Yan predicts an oil demand growth of about 8.5% in 2005 for China.
"However, there are great uncertainties that [create] demand volatility or demand shifts," he said. "These include China's new strategic petroleum reserve and noncommercial product inventories, and more importantly, high levels of secondary and tertiary product inventories, which if triggered for release by a falling or flat oil price trend may mask the real demand growthUlower than current demand numbers."
Margin outlook
For refiners, 2004 was an unusual year, according to Hoffman, because margins expanded while crude prices increased dramatically.
"In 2004, you can say that refining margins led crude up at times," he said. "We had pretty dramatic and surprising demand increases in the world, especially considering the price of energy moving up. We saw way less economic impact in the world due to sensitivity to price."
Although unsure how long strong refining margins will last, Galante said that the industry should expect to see significant margin volatility.
"I also know that an underlying, long-term, downward trend in refining margins makes sense for two reasons," he said. "First, productivity gains—including advances in technology—continue to take costs out and improve yields in running the business.
"And second, long-term, incremental refining capacity growth has generally been sufficient to meet demand growth in the mature markets," Galante said. "The industry will continue to find ways to incrementally grow distillation—and more importantly, conversion capacity—through low-cost methods, primarily through the deployment of new technology."
According to Veno, CERA is expecting US Gulf Coast jet fuel margins to average near $5-5.50/bbl in 2005, significantly less than the $6.67/bbl average in 2004 but higher than the 5-year average.
CERA also predicts that diesel spreads vs. WTI will be strong at about $4-4.50/bbl in 2005. 3-2-1 crack spreads on the US Gulf Coast will run a strong $4-5/bbl in 2005.