Energy Infrastructure
Hurricanes Katrina and Rita were among the most destructive and expensive storms in US history for the oil and gas industry.
As of this writing, the US Energy Information Administration (EIA) reports that some 1.52 billion barrels of daily oil and 7.8 billion cubic feet of daily natural gas production are shut down in the Gulf of Mexico. That represents a whopping 98 percent of Gulf oil production capacity and three-quarters of gas production.
Perhaps even more damaging is the loss of refining capacity. A total of 13 refineries remain closed as a result of Rita, on top of four refineries still shut in due to Katrina’s passage a month ago. As many as a half-dozen of these facilities will re-open in the next week; others will take weeks or even months to repair and bring back online.
That damage assessment should come as little surprise given the tracks of these two storms.
Source: US Energy Information Administration
Source: US Energy Information Administration
As you can see from the maps above, Katrina followed a more easterly track than Rita. The storms’ paths crossed very different parts of oil country. The result was that Rita affected drilling and refining operations that weren’t damaged by Katrina. And the industry had not fully recovered from Katrina by the time Rita hit–drilling rigs and platforms were still being moved back into position and repaired. Bottom line:
This vicious one-two punch will continue to interrupt the energy business for at least the next three to six months.
While certainly not as devastating a storm for the industry, last year’s Hurricane Ivan offers a roadmap for how long it can take to restore production.
Source: US Energy Information Administration
According to the EIA, Ivan shut in significant Gulf oil and gas production up until March of this year, a full six months after the storm hit. On the bright side, the worst damage to the industry after Ivan was repaired within about a month and a half of landfall.
But the impact of these storms lays bare an even more long-lasting problem for the US: vast under-capacity to produce, transport and refine oil and natural gas.
Refining capacity in the US peaked in 1983 and has fallen dramatically since then. There is literally no spare refining capacity to offset supply shocks. On the production front, it’s next to impossible for the US to replace lost Gulf gas production because America has only limited facilities to import gas in the form of liquefied natural gas (LNG). And oil can take weeks or months to arrive from overseas by tanker ship.
Supply interruptions aren’t necessarily one-off or particularly extraordinary events. For example, if the meteorologists are correct, we could see unusually strong activity in the tropics for at least the next decade or so. Hurricane activity comes in cycles, and according to most experts the late 1990s were the starting point for another wave of heightened activity. There have been several such cycles in past decades.
Storms aren’t the only cause of supply disruptions–political instability in the Middle East has periodically disrupted crude supplies for decades. As I’ve explained in the past, I seriously doubt Saudi Arabia has the capacity to ramp up its supplies of crude fast enough to meet surging global demand over the next few years.
The culprit for this under-capacity goes far beyond two devastating hurricanes in the Gulf. Specifically, a prolonged period of low oil and gas prices in the ‘80s and ‘90s led to massive underinvestment in exploration, import infrastructure and refining capacity.
As I’ve outlined in the past, I believe that cycle is turning. Higher oil and gas prices have led to better profitability for energy companies. These companies see the lack of infrastructure and are starting to spend that cash on improvements. Undoubtedly, investment will target all aspects of the energy business from advanced deepwater projects and liquefied natural gas (LNG) facilities to refinery upgrades and, perhaps, the first new refinery in nearly 30 years on US soil.
In the short run Gulf coast energy infrastructure will need to be repaired. Damaged and flooded refineries will require new equipment. And rigs will need to replace lost pipes, bits and equipment.
There’s one company that’s uniquely leveraged to the new oilfield construction boom–I’m adding Dresser-Rand (NYSE: DRC) to the Wildcatters Portfolio.
Dresser-Rand makes advanced compressors that are used in refineries, LNG terminals and even offshore platforms. Dresser is an old name in the oil business and has developed some close and unique relationships with some of the largest integrated oil companies.
I’m also adding infrastructure and construction plays Tidewater (NYSE: TDW) and Cheniere Energy (AMEX: LNG) to How They Rate as buy recommendations. Tidewater will be tracked in future issues and periodic Flash Alerts as a trade recommendation. Finally, I’m raising contract driller Rowan Companies (NYSE: RDC) from a hold to a buy in How They Rate.
I’ll be sending out a Flash Alert next week providing a detailed review of all current trade recommendations and any updates to my advice. The next issue of The Energy Strategist (October 12, 2005) will include a quarterly review of the performance of and updated advice on all portfolio picks.
Before we delve into these recommendations in greater depth, let’s take a closer look at some of the major supply bottlenecks facing the oil and gas business.
Oilfield Bust To Boom
It makes little sense to invest money in energy projects when oil is averaging less than $20 per barrel and natural gas trades under $5 per thousand cubic feet. Those were exactly the conditions that persisted during the late 1980s and throughout the 1990s. Predictably, most energy companies weren’t undertaking major investments during this period.
Source: Chevron, Exxon Mobil
The above chart shows capital spending by two major oil companies, Chevron (NYSE: CVX) and Exxon Mobil (NYSE: XOM), over the past 20 years. The chart clearly shows that through most of the late ‘80s and throughout the ‘90s, both firms drastically scaled back their capital expenditure (capex) investments–they simply were unwilling to spend big when oil and gas prices were perennially depressed.
That’s begun to change over the past few years. As energy prices began rising, so did profits and cash flow. As the chart shows, budgets are now increasing, a trend evident across the industry.
Refining Shortage
Perhaps the most egregious lack of investment globally has been in refining capacity. As most TES subscribers are aware, refiners perform the vital step of converting crude oil into useful products like gasoline, diesel and jet fuel.
As all consumers are keenly aware, retail gasoline prices all across the US are hovering around $3 per gallon, up from a national average of $2.35 at the beginning of August, an increase of roughly 25 percent. Over the same period crude oil has risen by just a little over 5.5 percent. The reason for the disconnect: a shortage of refining capacity. This problem has been brewing for some time.
No new refineries have been built in the US since 1976. Even worse, increasingly stringent environmental regulations have rendered many older refineries unusable–the number of refineries operating in the US fell sharply after 1990 as the Clean Air Act came into effect.
In fact, according to the Oil & Gas Journal a total of 30 refineries representing almost 1 million barrels of daily capacity have closed since 1995 alone.
Source: Oil & Gas Journal
It’s clear that US refining capacity peaked in 1983 and fell off sharply after that. While it has recovered somewhat in recent years, that’s been due to expansion and upgrading of existing refineries rather than construction of new facilities. Many of these refineries are clustered along the
Gulf Coast. This year’s hurricane season shows just how many refineries can get knocked out by a single storm.
But while refining capacity peaked in the early ‘80s, US gasoline demand did not. Instead, the US has relied increasingly on imports of gasoline from abroad to meet ever-increasing demand; nearly 2.9 million barrels per day in gasoline imports were necessary to meet demand in 2004 alone. Imports accelerated rapidly even though US refineries operated at more than 93 percent of capacity, near the physical limits of safe operation.
Eventually, new refineries will have to be built in the US to alleviate this shortage. Traditionally, new refinery projects have encountered opposition from several quarters; some environmentalists have opposed these facilities and refineries are difficult to site due to local opposition. With oil and gas prices so depressed in the ‘90s, many companies were reluctant to shell out the cash necessary to build a new refinery.
Sentiment is shifting on both counts. High gasoline prices are turning the public’s attention to the refinery shortage and political opponents to refinery construction in Congress appear to be softening their stance. Meanwhile, the big refiners are in better shape to fund new refinery construction thanks to higher energy prices.
But even if no new refineries are ever constructed in America, the industry will still need to undertake infrastructure investment on a massive scale. The reason is two-fold. First, by installing more advanced equipment, refiners can squeeze more gasoline out of a barrel of oil; more importantly, refiners with the most advanced equipment can process cheaper heavy and sour grades of crude, crudes that are harder to refine and contain more pollutants. In an environment of strong demand, there is an obvious incentive to undertake such investment.
Second, the Clean Air Act and other environmental regulations require major spending on the part of the refiners. According to estimates from the American Petroleum Institute (API), the oil industry spent nearly $50 billion between 1994 and 2003 on bringing refineries into compliance with environmental regulations. Spending to reduce emissions is set to continue for some time.
Refining Defined
To understand why refineries require such major investment, consider the steps involved in turning crude oil into gasoline, diesel and other useful products. Crude oil itself is mainly a mix of hydrocarbon molecules, basically hydrogen and carbon atoms bonded together in chains of different lengths. In addition to hydrocarbons, most crudes contain pollutants such as sulphur and salts or sometimes metals like nickel. Most of these non-hydrocarbon molecules have to be removed during refining. And the hydrocarbon molecules must also be broken down into smaller chains of usable form.
The first step in most refineries is some form of distillation. Distillation is actually a relatively straightforward process that takes advantage of the fact that different hydrocarbon molecules have different boiling points. Refiners simply heat crude–the feedstock of the refining process–to extremely high temperatures and inject it into a tall cylindrical column called a distillation tower in gaseous form. Lighter components of crude (such as gasoline) rise to the top of the tower while heavier elements will stick near the bottom.
The lightest elements of crude oil will boil at just 60 degrees Fahrenheit, rising to the top of the distillation tower. The heaviest elements will remain in solid form up to approximately 1,200 F and will tend to collect near the bottom of the tower. Gasoline, diesel and jet fuel are all considered lighter components of crude–most boil at less than 650 F.
Different elements of crude will rise to different levels of the distillation tower and can be removed in separated form. Distillation essentially separates crude based on density. Depending on the crude type being refined, a single barrel of crude could yield as little as 5 percent to as much as 40 percent gasoline using that basic process.
To remove pollutants such as sulphur and nitrogen, refiners use a complex process called hydrotreating. This involves placing the products of the distillation process under extreme pressures of between 400 and 2,000 pounds per square inch (psi)–to put that in perspective, normal atmospheric pressure at sea level is about 14.7 psi. The feedstock for hydrotreating is also heated to as hot as 500 F to 800 F.
This heated and pressurized gas is then mixed with pure hydrogen and a variety of chemical catalysts. Under extreme heat, pressure and in the presence of catalysts, the sulphur will bind with hydrogen to form hydrogen sulphide, a gas that can be more easily removed. Nitrogen, another common impurity, also bonds with the hydrogen gas under these conditions to form ammonia, another relatively easy to remove impurity.
But simply distilling crude and removing impurities wouldn’t be enough to meet global demand for gasoline and diesel. Such components make up less than half of the crude oil stream in many cases. But heavier elements of crude–longer hydrocarbon molecules–can be broken apart to form lighter elements such as gasoline. This process is broadly known as upgrading.
Upgrading can involve different processing. Some of the more common are catalytic cracking (colloquially called “cat” cracking) and hydrocracking. The exact processes involved here are not important. What is important is that both processes involve heating heavier elements of crude oil to extreme temperatures and often under extreme pressures. Catalysts are added to the stream to literally break long stings of carbon molecules into shorter, lighter molecules.
As you might expect, upgrading and hydro treating require some fairly sophisticated equipment. This includes equipment to heat and compress the crude as well as manage temperatures and the addition of catalysts.
More to the point, most environmental regulation targets sulphur emissions. To meet ever more stringent sulphur regulations, refiners must install ever more complex hydro treating facilities. This means installing millions of dollars in additional equipment. Over the next few years, gasoline sulphur regulations will tighten even further in the US. The nation is also mandating a shift to ultra-low sulphur diesel fuel by June of 2006.
The US isn’t the only market undergoing such a shift. Europe is increasingly becoming a key market for diesel fuel; governments across the Continent are encouraging diesel fuel use over gasoline. With Europe shifting to some ultra-strict sulphur regulations for diesel, refineries there will need to spend big to upgrade their facilities. Europe is even considering a switch to diesel fuels with essentially zero sulphur content by the beginning of 2009.
And it’s not just the developed world that’s making the low-sulphur switch. India removed lead from gasoline in 2000 and is mandating a switch to diesel fuel with less than 500 parts per million (ppm) of sulphur this year; in 2000, the standard was 2,500. While this is still well above European and US norms, India has effected the change far more quickly. Estimates currently suggest it will cost more than $5.5 billion in refinery upgrades to meet these more stringent regulations.
Bottom line: refiners will be forced to spend big to meet environmental regulations in the coming years. What’s more, high profitability in the refining industry will mean there’s an incentive to keep improving refining efficiency and perform upgrades that allow facilities to accept cheaper but harder to refine feedstocks.
What About Gas?
Refining is only one of many bottlenecks exposed for the world to see by Katrina and Rita. While natural gas prices get less play in the press than gasoline, natural gas has shot up from under $10 per thousand cubic feet before Katrina to more than $13–an all-time record high–after Rita.
While rising gas prices may be less obvious to the average consumer than $3 per gallon gasoline, next winter’s heating bills are sure to change that. Just as the hurricanes interrupted refining operations, the storms caused massive disruptions to US natural gas infrastructure, including offshore gas production in the Gulf, gas processing and transport pipeline systems.
I won’t bore you by rehashing all the fundamentals of the natural gas market (covered in great depth in the The Energy Strategist, July 13, 2005, “Liquid Energy” ), but suffice it to say that natural gas will be the fastest growing fuel worldwide for at least the next 20 years.
Source: US Energy Information Administration
As the above chart indicates, the developed world will see solid growth in demand for gas. Most of that gas will be needed to power an increasingly large fleet of natural-gas-fired power plants.
Demand will grow even faster in the developing world. The fact is that as an economy develops, demand for electricity increases rapidly. An increasingly wealthy class of Asians is demanding the same sort of consumer goods and services as their counterparts in the US and Europe. That means more demand for electricity and, by extension, natural gas.
The problem is that for most of its history, gas has been a rather localized fuel. In the US, for example, domestic sources of natural gas have traditionally covered most of domestic demand. What couldn’t be covered by domestic production was simply imported by pipeline from neighboring Canada.
This is no longer the case. US gas production has probably peaked and Canada production is close to a peak. Unconventional and hard to reach sources of gas will help slow or prolong significant production declines, but domestic gas sources will not be sufficient to meet the nation’s demands.
To fill this breach, gas will become a globally traded fuel like oil. To accomplish this, natural gas must be converted to a liquid form–liquefied natural gas (LNG)–by cooling and compressing it under extreme pressure. Once liquefied, gas can be transported on specialized tanker ships from distant gas fields in gas-rich areas like Siberia and the Middle East to markets in North America, Europe and, increasingly Asia.
The global trade in LNG is set to explode in the next 25 years. The chart below offers a closer look at global gas trade.
Source: Oil & Gas Journal, Exxon Mobil
By 2030, Exxon projects that the US will import more than one-quarter of its daily gas demand, the vast majority of that in the form of LNG. That’s up from just 10 percent of demand in 2010 and close to zero a decade ago. Asia will also see strong growth–imports will account for 9 percent of demand in 2010 to about 24 percent in 2030.
And then there’s Europe, which will import more than 70 percent of its gas needs by 2030, up from about 50 percent today. Some of that will be in the form of LNG; the balance will likely come via pipeline from distant fields in eastern Russia (Siberia).
Gas trade of this magnitude will also require massive infrastructure investment. LNG requires the building of expensive and technically complex plants at both the producing and consumption end. Once gas in distant fields is produced it must be gasified at a plant that cools and compresses the gas for transport. Gas imported into a market like the US needs to be regasified and injected into the domestic pipeline system.
That infrastructure spending is already underway. Total spending on LNG infrastructure stood at nearly $97 billion in 2003 alone. Due to the rapid growth of this technology, that’s likely to increase to as much as $150 billion in 2010.
In addition, imported gas, like domestic gas, requires further processing before it’s ready for use. Gas processing involves the removal of natural gas liquids–products like propane and butane that occur naturally mixed with the gas. Just as with crude oil, sulphur and other chemical pollutants have to be removed from the gas stream before that gas is ready for use. Some of that processing work will likely be carried out near the source of gas production, while other steps will likely be carried out once the LNG hits its destination ports.
The pipelines that are used to move gas from ports and individual gas wells to the consumer are by no means simple networks of steel pipe. To keep gas moving and pressure high, compressors and turbines must also be installed along the route. The pipes themselves need periodic inspection for damage and maintenance; this includes subsea pipes that connect offshore production facilities with the onshore pipeline system.
Finally, most natural gas is stored prior to use. Contrary to popular belief storage facilities are not (in most cases) giant, above ground or underground tanks. Instead, natural gas is normally stored in older fully depleted gas reservoirs located close to ultimate sources of consumption. To get the gas into such underground storage facilities require intense pressurization–that, in turn, requires more equipment.
The Upstream Market
When it comes to production, energy companies are focusing their investment into two main areas: recovering more oil from mature, well-explored reserves and building giant deepwater projects. Traditional land-based oil and gas regions have been explored for over a century. The vast majority, if not all, of the giant onshore fields have already been discovered.
So too have shallow-water reserves. The shallow-water Gulf of Mexico is an important oil-producing area, but it’s not new. Much of the exploration activity in the region consists of exploiting smaller pockets of harder-to-drill hydrocarbons or using advanced technologies to boost production from mature fields.
The big new reserves to be found in the coming years will undoubtedly be in more hostile deepwater environments. The deepwater has not been as completely explored and until recently, energy prices were too low to make deepwater development economical.
Deepwater reserves require much more infrastructure investment than either shallow-water or onshore projects. Such reservoirs are rarely connected directly to the shore via pipeline; to do so would be enormously expensive or impractical. Instead, individual wells are produced using subsea equipment–valves, pipelines and electronic equipment located on the seafloor. Production from scores of subsea wells is then transported by subsea pipeline to floating (or permanent) production/storage platforms.
Those platforms perform some basic processing of hydrocarbons, such as separating them into oil and natural gas. Eventually, products can be offloaded by tanker ships for transport to onshore pipeline grids.
Production from mature or non-conventional reservoirs also requires special attention and investment. The problem with many mature fields is that the natural underground pressure in the reservoir drops as gas and oil are produced. This makes it more difficult to produce hydrocarbons the longer a well is operated.
Oil is not found in vast underground caverns but is instead trapped in tiny pores and crevices of rock. When a well is first spudded, oil will naturally flow through these pores to the wellpipe, and through that pipe to the surface due to the pressure of underground reservoirs. But this primary production leaves behind a lot of oil. Not all oil located underground will naturally flow to the wellhead for production–as much as 60 to 80 percent of oil in a reservoir can be left in that reservoir after primary production is complete.
Myriad technologies exist to produce more of this left-behind oil from mature fields, including gas reinjection. Gas and oil are often located together in a reservoir. Depending on the pressures in the reservoir in question, gas can exist in gaseous form; because it’s lighter than oil it tends to rise to the top of the formation in what’s known as a gas cap. If under higher pressure, natural gas can actually be dissolved in the crude itself.
No matter how the gas occurs, it helps to keep the crude oil under pressure–pressure is what keeps oil moving through the reservoir and to the wellhead. And as pressure drops, gas dissolved in crude can actually begin to bubble out of solution. This bubbling action actually helps lift oil from a reservoir, a phenomenon is known as dissolved gas drive.
During gas reinjection, natural gas produced with the oil can actually be reinjected into the formation to keep pressures high. In some cases it’s also injected into the well pipe itself. The gas them bubbles back to the surface, helping to lift the crude oil.
Still more complex is carbon dioxide injection, a common mature recovery technique in the US. Sometimes heated carbon dioxide can be injected into a reservoir to literally push oil through the pores of the reservoir. By flooding a field with carbon dioxide some Texas producers have been able to squeeze significantly more oil out of reservoirs that have been producing for decades.
Again, as you might imagine, all of these advanced recovery techniques require some complex infrastructure. Giant pumps and compressors are needed, for example, to inject gases into a reservoir. And offshore deepwater fields require highly complex subsea equipment that can be remotely controlled by computer and must be installed on the seafloor directly, often at depths of a mile and a half or more.
How To Play It
Dresser-Rand (NYSE: DRC) is almost uniquely positioned to benefit from the global bottlenecks in refining, LNG capacity and production growth. It’s one of the only companies touching just about every aspect of the energy infrastructure business, from the wellhead to the consumer.
Over the next five years, the energy infrastructure boom will really kick off as the big oils put their cash to work in reversing the underinvestment of the long oilfield depression of the 1980s and 1990s.
Dresser-Rand is a leading global producer of highly specialized compressors and turbines, nearly 95 percent of which are used in the energy business. In addition to manufacturing and selling such products, Dresser also offers after-market servicing and spare parts both for its own equipment and that of the competition.
As I outlined above, new gasoline and diesel sulphur regulations require extensive hydrotreating capacity additions at the world’s refineries. This is not just a US and European issue. Some of the most dramatic new environmental standards will be coming into effect in fast-growing markets like China and India. Hydrotreating crude and gasoline to remove sulphur requires pressurizing; Dresser’s compressors are used to create that necessary pressure.
The same is true of upgrading operations–the reactions used to crack crude oil into smaller molecules all require extreme pressure. Increasingly, the world’s marginal sources of crude supply are “heavier” oils. For example, Saudi Arabia’s giant offshore Safaniya field is that nation’s main source of spare oil producing capacity. Whenever the desert kingdom increases oil production, the marginal supplies tend to be from this field. And Safaniya is a heavy crude oil field–crude from the field, containing many heavy hydrocarbon molecules that need to be broken apart to form lighter products, is tough to refine.
The same is true of the vast Canadian oil sands. Bitumen, the near-solid crude oil produced from the sands, tends to be rather heavy and can be high in sulphur. It therefore requires significant upgrading. Heavy oils mean the globe needs more upgrading capacity–upgrading operations require pressure, and creating that pressure means using large compressors and turbines.
It should come as little surprise that refining is already Dresser’s largest end market, accounting for nearly one-third of total revenues. Growth in this end market should continue to accelerate. Most of the big US refining companies have stated they are now ready to meet sulphur regulations. This is not the case outside the US; refiners in Europe and Asia still have to carry out more investment in infrastructure to meet the new regs. And all refiners around the world will be keen to upgrade their systems to accept the more marginal grades of crude now in greatest supply worldwide.
Fortunately, Dresser has a superb position overseas. As the chart below illustrates, a little over a third of revenues come from the US. The balance is well distributed from around the rest of the world. Dresser maintains service and support centers in 106 countries to support its overseas aftermarket and servicing operations.
Source: Dresser-Rand
Refining is clearly only one piece of the puzzle. Dresser garnered an additional 30 percent of its 2004 revenues from sales into the upstream market, mainly oil and gas exploration and production.
As explained above, deepwater operations also require the use of compression equipment. Crude oil and gas can be produced together from a single subsea well. Pressure is used to separate these two commodities on board floating production vessels. Pressurized chambers are also used to as part of other gas processing operations such as de-sanding and removing water vapor in the natural gas stream.
Dresser has garnered several major contracts to supply compression equipment for floating production, storage and offloading platforms (FPSOs), ships that are used to produce hydrocarbons from offshore, subsea wells.
Onshore, compressors are used in what’s known as the gas gathering pipeline system. The gas gathering system is a network of small-diameter pipes used to transport gas from individual wells to gas processing plants. As wells mature and pressures drop, gas gathering systems must be enhanced with compressors to make sure gas moves through the system effectively. Closer still to the wellbore, Dresser supplies gas reinjection equipment.
Another 20 percent of revenues for Dresser come from the midstream gas business. Basically, that means pipeline infrastructure. When moving gas over long distances, compressors are required to boost speed. And as I outlined above, gas stored in underground reservoirs is pressurized using compressors.
More exciting from a growth standpoint is the LNG business. To date, Dresser has a roughly 25 percent global market share in LNG regasification compressors and more than a third of the global market for liquefication. Dresser missed out on a few large LNG orders in recent years to the likes of General Electric (NYSE: GE).
But more recently it’s focused attention on building out its LNG business. Dresser has the most advanced compression technology on the market. Because this equipment is more reliable, it has less downtime–downtime means lost revenues. There’s a growing sentiment that Dresser will grab a big LNG contract win within the next six months; such a win would be a strong near-term catalyst for the stock.
Other Competitive Advantages
I see several other key competitive advantages for Dresser. The first is the company’s gigantic existing installed base of equipment. The reason this is an advantage is that Dresser garners most of its revenues and earnings from aftermarket sales and services, not the original sale of equipment. Because compressors can last for several decades, the big business is the sale of spare parts and maintenance contracts. After-market work is about two-thirds of the company’s revenue mix.
Dresser equipment accounts for roughly half the current global installed base. As you might expect, Dresser does a good chunk of the maintenance and repair work on its own installed base.
Another big advantage is that Dresser focuses almost exclusively on the high end of the compressor market. That means that most of its units are custom made to handle a particular job or project. Companies like Hanover Compressor (NYSE: HC) tend to manufacture and lease out lower-end compressor units.
The advantage of the high-end market is two-fold. First, high-end compressors are the sort installed in big projects like new LNG terminals and deepwater developments. Such projects take years of planning and development to complete; Dresser normally has a very good idea of its likely revenues because its compressors are part of these longer-term projects. Second, the high-end compressor market is dependant on technology and reliability more than price; Dresser’s units are generally recognized as technologically superior to other units on the market so it doesn’t have to compete solely on costs.
A final advantage for Dresser is the value-pricing contract and the company’s strategic alliances. Instead of simply selling a compressor unit for a fixed price and then agreeing to separate service terms, such contracts actually bundle together service and manufacturing services. The company buys the unit and hires Dresser to service and maintain it. Dresser also receives added revenues for reliability–by maintaining the unit and limiting downtime, Dresser actually earns larger revenues. This type of contract reflects the reality that downtime for refiners and LNG terminals spells lost revenues.
The advantage to the customer is that a value-pricing contract provides the highest reliability and service and minimizes downtime. For Dresser, such contracts are a way of locking customers in–it would be very difficult for a competitor to take any of Dresser’s after-market business when the equipment is covered by such a contract.
Roughly half of Dresser’s new revenues are part of alliances with energy firms. These global alliance contracts normally entail Dresser forming a very tight relationship with a particular company to supply compressors. Most such contracts are value-based in some way.
Dresser Rand is now a component in the Wildcatters Portfolio.
Other Infrastructure Plays
My other favorite plays on global energy infrastructure are Cooper Cameron (NYSE: CAM) and FMC Technologies (NYSE: FTI), members of the Wildcatters Portfolio. Both are plays on subsea equipment, a key link in developing deepwater reserves as outlined above. (For more on that market, check out The Energy Strategist, April 13, 2005, “Going Deep”.)
I’m also adding Tidewater (NYSE: TDW) to How They Rate as a buy recommendation and will continue to track the stock as a trade recommendation. Tidewater is the leading supply ship operator globally with a fleet of more than 500. Supply ships are used to transport products used in the drilling process from the shore to offshore drilling rigs and production platforms. Items transported include workers and heavy equipment like drill pipe, cement and fuel. These ships are also used to aid offshore construction projects.
Some of Tidewater’s ships are also equipped to perform specialized functions. For example, some offshore platforms are moored or anchored–some of Tidewater’s ships are designed to help place those anchors effectively on the sea floor. Also, many drilling rigs aren’t designed to move great distances under their own power–Tidewater owns powerful tug-like boats for towing rigs into place.
Tidewater has a particularly strong presence in the Gulf of Mexico. Fortunately, the company has reported no major damage to ships as a result of the recent passage of the hurricanes. Though its headquarters has been temporarily moved from New Orleans to Houston, there’s been no disruption of operations.
Like the contract drillers and tanker ship companies, Tidewater charges a certain day-rate for leasing out its ships and crews. Due to the global pick-up in offshore projects and construction activity, those day-rates have been rising. The stock is a direct play on the growth in offshore investment activity.
In the short run, Tidewater will benefit from hurricane-related construction and clean-up efforts in the Gulf. Longer-term, higher spending on offshore infrastructure will power demand.
Finally, I’m adding Cheniere Energy (AMEX: LNG) to How They Rate as a buy. Cheniere constructs LNG terminals and facilities in the US, and has ownership interests in four proposed LNG terminals. Three of the terminals have already received government approval and construction has started on two. Both should be up-and-running within the next three years.
Cheniere has also lowered its risk by selling regasification capacity to the big energy companies in long-term contracts. This will ensure that the company is not particularly vulnerable to commodity price swings in the gas market.
Cheniere has an early lead in the LNG terminal business. That said, it’s still not a profitable company and likely won’t be until contract revenues start rolling in after 2008.
Does It Matter?
By Yiannis G. Mostrous
Not a single day goes by without someone saying that China and India are consuming the world’s oil. If the Asian giants would only slow down, we could all drive our SUVs to work and back without thinking of the monthly payment on the gas-only credit card.
Well, they might do just that.
Anecdotal evidence coming from China is showing that oil demand is gradually slowing down, not so much due to the per-barrel price (the Chinese government subsidizes oil prices), but because Chinese companies are having some difficulty making profits. A gradual slowdown in manufacturing has also lowered transportation intensity.
So we may see oil at $55 next year. But just two short years ago everyone was talking about $25 oil. Never happened, never will.
Oil is making a new base at around $40 and the world will have to accept it. Of course, when oil trades at $70 and gradually moves back to $55 everyone is pleased. Nevertheless, the new higher base will be a reality, and given the short supply of memory power, no one will dare mention $25.
The recent hurricanes proved how vulnerable the world’s energy infrastructure is. And do not be fooled: as easy as the per-barrel price of oil can go down to $55, it can also go up to triple digits. From terrorism to political instability to the weather, there are plenty of upward catalysts to worry about.
The world has only 1.4 million barrels per day of spare production capacity, or less than 2 percent of current global demand–not a safe buffer. Unless global demand collapses, the long-term case for energy stocks (with the obligatory ups and downs) remains intact.
Our favorite big energy stocks continue to be ExxonMobil (NYSE: XOM), Total (NYSE: TOT), Marathon Oil (NYSE: MRO), BP (NYSE: BP) and ConocoPhillips (NYSE: COP).
As of this writing, the US Energy Information Administration (EIA) reports that some 1.52 billion barrels of daily oil and 7.8 billion cubic feet of daily natural gas production are shut down in the Gulf of Mexico. That represents a whopping 98 percent of Gulf oil production capacity and three-quarters of gas production.
Perhaps even more damaging is the loss of refining capacity. A total of 13 refineries remain closed as a result of Rita, on top of four refineries still shut in due to Katrina’s passage a month ago. As many as a half-dozen of these facilities will re-open in the next week; others will take weeks or even months to repair and bring back online.
That damage assessment should come as little surprise given the tracks of these two storms.
Source: US Energy Information Administration
Source: US Energy Information Administration
As you can see from the maps above, Katrina followed a more easterly track than Rita. The storms’ paths crossed very different parts of oil country. The result was that Rita affected drilling and refining operations that weren’t damaged by Katrina. And the industry had not fully recovered from Katrina by the time Rita hit–drilling rigs and platforms were still being moved back into position and repaired. Bottom line:
This vicious one-two punch will continue to interrupt the energy business for at least the next three to six months.
While certainly not as devastating a storm for the industry, last year’s Hurricane Ivan offers a roadmap for how long it can take to restore production.
Source: US Energy Information Administration
According to the EIA, Ivan shut in significant Gulf oil and gas production up until March of this year, a full six months after the storm hit. On the bright side, the worst damage to the industry after Ivan was repaired within about a month and a half of landfall.
But the impact of these storms lays bare an even more long-lasting problem for the US: vast under-capacity to produce, transport and refine oil and natural gas.
Refining capacity in the US peaked in 1983 and has fallen dramatically since then. There is literally no spare refining capacity to offset supply shocks. On the production front, it’s next to impossible for the US to replace lost Gulf gas production because America has only limited facilities to import gas in the form of liquefied natural gas (LNG). And oil can take weeks or months to arrive from overseas by tanker ship.
Supply interruptions aren’t necessarily one-off or particularly extraordinary events. For example, if the meteorologists are correct, we could see unusually strong activity in the tropics for at least the next decade or so. Hurricane activity comes in cycles, and according to most experts the late 1990s were the starting point for another wave of heightened activity. There have been several such cycles in past decades.
Storms aren’t the only cause of supply disruptions–political instability in the Middle East has periodically disrupted crude supplies for decades. As I’ve explained in the past, I seriously doubt Saudi Arabia has the capacity to ramp up its supplies of crude fast enough to meet surging global demand over the next few years.
The culprit for this under-capacity goes far beyond two devastating hurricanes in the Gulf. Specifically, a prolonged period of low oil and gas prices in the ‘80s and ‘90s led to massive underinvestment in exploration, import infrastructure and refining capacity.
As I’ve outlined in the past, I believe that cycle is turning. Higher oil and gas prices have led to better profitability for energy companies. These companies see the lack of infrastructure and are starting to spend that cash on improvements. Undoubtedly, investment will target all aspects of the energy business from advanced deepwater projects and liquefied natural gas (LNG) facilities to refinery upgrades and, perhaps, the first new refinery in nearly 30 years on US soil.
In the short run Gulf coast energy infrastructure will need to be repaired. Damaged and flooded refineries will require new equipment. And rigs will need to replace lost pipes, bits and equipment.
There’s one company that’s uniquely leveraged to the new oilfield construction boom–I’m adding Dresser-Rand (NYSE: DRC) to the Wildcatters Portfolio.
Dresser-Rand makes advanced compressors that are used in refineries, LNG terminals and even offshore platforms. Dresser is an old name in the oil business and has developed some close and unique relationships with some of the largest integrated oil companies.
I’m also adding infrastructure and construction plays Tidewater (NYSE: TDW) and Cheniere Energy (AMEX: LNG) to How They Rate as buy recommendations. Tidewater will be tracked in future issues and periodic Flash Alerts as a trade recommendation. Finally, I’m raising contract driller Rowan Companies (NYSE: RDC) from a hold to a buy in How They Rate.
I’ll be sending out a Flash Alert next week providing a detailed review of all current trade recommendations and any updates to my advice. The next issue of The Energy Strategist (October 12, 2005) will include a quarterly review of the performance of and updated advice on all portfolio picks.
Before we delve into these recommendations in greater depth, let’s take a closer look at some of the major supply bottlenecks facing the oil and gas business.
Oilfield Bust To Boom
It makes little sense to invest money in energy projects when oil is averaging less than $20 per barrel and natural gas trades under $5 per thousand cubic feet. Those were exactly the conditions that persisted during the late 1980s and throughout the 1990s. Predictably, most energy companies weren’t undertaking major investments during this period.
Source: Chevron, Exxon Mobil
The above chart shows capital spending by two major oil companies, Chevron (NYSE: CVX) and Exxon Mobil (NYSE: XOM), over the past 20 years. The chart clearly shows that through most of the late ‘80s and throughout the ‘90s, both firms drastically scaled back their capital expenditure (capex) investments–they simply were unwilling to spend big when oil and gas prices were perennially depressed.
That’s begun to change over the past few years. As energy prices began rising, so did profits and cash flow. As the chart shows, budgets are now increasing, a trend evident across the industry.
Refining Shortage
Perhaps the most egregious lack of investment globally has been in refining capacity. As most TES subscribers are aware, refiners perform the vital step of converting crude oil into useful products like gasoline, diesel and jet fuel.
As all consumers are keenly aware, retail gasoline prices all across the US are hovering around $3 per gallon, up from a national average of $2.35 at the beginning of August, an increase of roughly 25 percent. Over the same period crude oil has risen by just a little over 5.5 percent. The reason for the disconnect: a shortage of refining capacity. This problem has been brewing for some time.
No new refineries have been built in the US since 1976. Even worse, increasingly stringent environmental regulations have rendered many older refineries unusable–the number of refineries operating in the US fell sharply after 1990 as the Clean Air Act came into effect.
In fact, according to the Oil & Gas Journal a total of 30 refineries representing almost 1 million barrels of daily capacity have closed since 1995 alone.
Source: Oil & Gas Journal
It’s clear that US refining capacity peaked in 1983 and fell off sharply after that. While it has recovered somewhat in recent years, that’s been due to expansion and upgrading of existing refineries rather than construction of new facilities. Many of these refineries are clustered along the
Gulf Coast. This year’s hurricane season shows just how many refineries can get knocked out by a single storm.
But while refining capacity peaked in the early ‘80s, US gasoline demand did not. Instead, the US has relied increasingly on imports of gasoline from abroad to meet ever-increasing demand; nearly 2.9 million barrels per day in gasoline imports were necessary to meet demand in 2004 alone. Imports accelerated rapidly even though US refineries operated at more than 93 percent of capacity, near the physical limits of safe operation.
Eventually, new refineries will have to be built in the US to alleviate this shortage. Traditionally, new refinery projects have encountered opposition from several quarters; some environmentalists have opposed these facilities and refineries are difficult to site due to local opposition. With oil and gas prices so depressed in the ‘90s, many companies were reluctant to shell out the cash necessary to build a new refinery.
Sentiment is shifting on both counts. High gasoline prices are turning the public’s attention to the refinery shortage and political opponents to refinery construction in Congress appear to be softening their stance. Meanwhile, the big refiners are in better shape to fund new refinery construction thanks to higher energy prices.
But even if no new refineries are ever constructed in America, the industry will still need to undertake infrastructure investment on a massive scale. The reason is two-fold. First, by installing more advanced equipment, refiners can squeeze more gasoline out of a barrel of oil; more importantly, refiners with the most advanced equipment can process cheaper heavy and sour grades of crude, crudes that are harder to refine and contain more pollutants. In an environment of strong demand, there is an obvious incentive to undertake such investment.
Second, the Clean Air Act and other environmental regulations require major spending on the part of the refiners. According to estimates from the American Petroleum Institute (API), the oil industry spent nearly $50 billion between 1994 and 2003 on bringing refineries into compliance with environmental regulations. Spending to reduce emissions is set to continue for some time.
Refining Defined
To understand why refineries require such major investment, consider the steps involved in turning crude oil into gasoline, diesel and other useful products. Crude oil itself is mainly a mix of hydrocarbon molecules, basically hydrogen and carbon atoms bonded together in chains of different lengths. In addition to hydrocarbons, most crudes contain pollutants such as sulphur and salts or sometimes metals like nickel. Most of these non-hydrocarbon molecules have to be removed during refining. And the hydrocarbon molecules must also be broken down into smaller chains of usable form.
The first step in most refineries is some form of distillation. Distillation is actually a relatively straightforward process that takes advantage of the fact that different hydrocarbon molecules have different boiling points. Refiners simply heat crude–the feedstock of the refining process–to extremely high temperatures and inject it into a tall cylindrical column called a distillation tower in gaseous form. Lighter components of crude (such as gasoline) rise to the top of the tower while heavier elements will stick near the bottom.
The lightest elements of crude oil will boil at just 60 degrees Fahrenheit, rising to the top of the distillation tower. The heaviest elements will remain in solid form up to approximately 1,200 F and will tend to collect near the bottom of the tower. Gasoline, diesel and jet fuel are all considered lighter components of crude–most boil at less than 650 F.
Different elements of crude will rise to different levels of the distillation tower and can be removed in separated form. Distillation essentially separates crude based on density. Depending on the crude type being refined, a single barrel of crude could yield as little as 5 percent to as much as 40 percent gasoline using that basic process.
To remove pollutants such as sulphur and nitrogen, refiners use a complex process called hydrotreating. This involves placing the products of the distillation process under extreme pressures of between 400 and 2,000 pounds per square inch (psi)–to put that in perspective, normal atmospheric pressure at sea level is about 14.7 psi. The feedstock for hydrotreating is also heated to as hot as 500 F to 800 F.
This heated and pressurized gas is then mixed with pure hydrogen and a variety of chemical catalysts. Under extreme heat, pressure and in the presence of catalysts, the sulphur will bind with hydrogen to form hydrogen sulphide, a gas that can be more easily removed. Nitrogen, another common impurity, also bonds with the hydrogen gas under these conditions to form ammonia, another relatively easy to remove impurity.
But simply distilling crude and removing impurities wouldn’t be enough to meet global demand for gasoline and diesel. Such components make up less than half of the crude oil stream in many cases. But heavier elements of crude–longer hydrocarbon molecules–can be broken apart to form lighter elements such as gasoline. This process is broadly known as upgrading.
Upgrading can involve different processing. Some of the more common are catalytic cracking (colloquially called “cat” cracking) and hydrocracking. The exact processes involved here are not important. What is important is that both processes involve heating heavier elements of crude oil to extreme temperatures and often under extreme pressures. Catalysts are added to the stream to literally break long stings of carbon molecules into shorter, lighter molecules.
As you might expect, upgrading and hydro treating require some fairly sophisticated equipment. This includes equipment to heat and compress the crude as well as manage temperatures and the addition of catalysts.
More to the point, most environmental regulation targets sulphur emissions. To meet ever more stringent sulphur regulations, refiners must install ever more complex hydro treating facilities. This means installing millions of dollars in additional equipment. Over the next few years, gasoline sulphur regulations will tighten even further in the US. The nation is also mandating a shift to ultra-low sulphur diesel fuel by June of 2006.
The US isn’t the only market undergoing such a shift. Europe is increasingly becoming a key market for diesel fuel; governments across the Continent are encouraging diesel fuel use over gasoline. With Europe shifting to some ultra-strict sulphur regulations for diesel, refineries there will need to spend big to upgrade their facilities. Europe is even considering a switch to diesel fuels with essentially zero sulphur content by the beginning of 2009.
And it’s not just the developed world that’s making the low-sulphur switch. India removed lead from gasoline in 2000 and is mandating a switch to diesel fuel with less than 500 parts per million (ppm) of sulphur this year; in 2000, the standard was 2,500. While this is still well above European and US norms, India has effected the change far more quickly. Estimates currently suggest it will cost more than $5.5 billion in refinery upgrades to meet these more stringent regulations.
Bottom line: refiners will be forced to spend big to meet environmental regulations in the coming years. What’s more, high profitability in the refining industry will mean there’s an incentive to keep improving refining efficiency and perform upgrades that allow facilities to accept cheaper but harder to refine feedstocks.
What About Gas?
Refining is only one of many bottlenecks exposed for the world to see by Katrina and Rita. While natural gas prices get less play in the press than gasoline, natural gas has shot up from under $10 per thousand cubic feet before Katrina to more than $13–an all-time record high–after Rita.
While rising gas prices may be less obvious to the average consumer than $3 per gallon gasoline, next winter’s heating bills are sure to change that. Just as the hurricanes interrupted refining operations, the storms caused massive disruptions to US natural gas infrastructure, including offshore gas production in the Gulf, gas processing and transport pipeline systems.
I won’t bore you by rehashing all the fundamentals of the natural gas market (covered in great depth in the The Energy Strategist, July 13, 2005, “Liquid Energy” ), but suffice it to say that natural gas will be the fastest growing fuel worldwide for at least the next 20 years.
Source: US Energy Information Administration
As the above chart indicates, the developed world will see solid growth in demand for gas. Most of that gas will be needed to power an increasingly large fleet of natural-gas-fired power plants.
Demand will grow even faster in the developing world. The fact is that as an economy develops, demand for electricity increases rapidly. An increasingly wealthy class of Asians is demanding the same sort of consumer goods and services as their counterparts in the US and Europe. That means more demand for electricity and, by extension, natural gas.
The problem is that for most of its history, gas has been a rather localized fuel. In the US, for example, domestic sources of natural gas have traditionally covered most of domestic demand. What couldn’t be covered by domestic production was simply imported by pipeline from neighboring Canada.
This is no longer the case. US gas production has probably peaked and Canada production is close to a peak. Unconventional and hard to reach sources of gas will help slow or prolong significant production declines, but domestic gas sources will not be sufficient to meet the nation’s demands.
To fill this breach, gas will become a globally traded fuel like oil. To accomplish this, natural gas must be converted to a liquid form–liquefied natural gas (LNG)–by cooling and compressing it under extreme pressure. Once liquefied, gas can be transported on specialized tanker ships from distant gas fields in gas-rich areas like Siberia and the Middle East to markets in North America, Europe and, increasingly Asia.
The global trade in LNG is set to explode in the next 25 years. The chart below offers a closer look at global gas trade.
Source: Oil & Gas Journal, Exxon Mobil
By 2030, Exxon projects that the US will import more than one-quarter of its daily gas demand, the vast majority of that in the form of LNG. That’s up from just 10 percent of demand in 2010 and close to zero a decade ago. Asia will also see strong growth–imports will account for 9 percent of demand in 2010 to about 24 percent in 2030.
And then there’s Europe, which will import more than 70 percent of its gas needs by 2030, up from about 50 percent today. Some of that will be in the form of LNG; the balance will likely come via pipeline from distant fields in eastern Russia (Siberia).
Gas trade of this magnitude will also require massive infrastructure investment. LNG requires the building of expensive and technically complex plants at both the producing and consumption end. Once gas in distant fields is produced it must be gasified at a plant that cools and compresses the gas for transport. Gas imported into a market like the US needs to be regasified and injected into the domestic pipeline system.
That infrastructure spending is already underway. Total spending on LNG infrastructure stood at nearly $97 billion in 2003 alone. Due to the rapid growth of this technology, that’s likely to increase to as much as $150 billion in 2010.
In addition, imported gas, like domestic gas, requires further processing before it’s ready for use. Gas processing involves the removal of natural gas liquids–products like propane and butane that occur naturally mixed with the gas. Just as with crude oil, sulphur and other chemical pollutants have to be removed from the gas stream before that gas is ready for use. Some of that processing work will likely be carried out near the source of gas production, while other steps will likely be carried out once the LNG hits its destination ports.
The pipelines that are used to move gas from ports and individual gas wells to the consumer are by no means simple networks of steel pipe. To keep gas moving and pressure high, compressors and turbines must also be installed along the route. The pipes themselves need periodic inspection for damage and maintenance; this includes subsea pipes that connect offshore production facilities with the onshore pipeline system.
Finally, most natural gas is stored prior to use. Contrary to popular belief storage facilities are not (in most cases) giant, above ground or underground tanks. Instead, natural gas is normally stored in older fully depleted gas reservoirs located close to ultimate sources of consumption. To get the gas into such underground storage facilities require intense pressurization–that, in turn, requires more equipment.
The Upstream Market
When it comes to production, energy companies are focusing their investment into two main areas: recovering more oil from mature, well-explored reserves and building giant deepwater projects. Traditional land-based oil and gas regions have been explored for over a century. The vast majority, if not all, of the giant onshore fields have already been discovered.
So too have shallow-water reserves. The shallow-water Gulf of Mexico is an important oil-producing area, but it’s not new. Much of the exploration activity in the region consists of exploiting smaller pockets of harder-to-drill hydrocarbons or using advanced technologies to boost production from mature fields.
The big new reserves to be found in the coming years will undoubtedly be in more hostile deepwater environments. The deepwater has not been as completely explored and until recently, energy prices were too low to make deepwater development economical.
Deepwater reserves require much more infrastructure investment than either shallow-water or onshore projects. Such reservoirs are rarely connected directly to the shore via pipeline; to do so would be enormously expensive or impractical. Instead, individual wells are produced using subsea equipment–valves, pipelines and electronic equipment located on the seafloor. Production from scores of subsea wells is then transported by subsea pipeline to floating (or permanent) production/storage platforms.
Those platforms perform some basic processing of hydrocarbons, such as separating them into oil and natural gas. Eventually, products can be offloaded by tanker ships for transport to onshore pipeline grids.
Production from mature or non-conventional reservoirs also requires special attention and investment. The problem with many mature fields is that the natural underground pressure in the reservoir drops as gas and oil are produced. This makes it more difficult to produce hydrocarbons the longer a well is operated.
Oil is not found in vast underground caverns but is instead trapped in tiny pores and crevices of rock. When a well is first spudded, oil will naturally flow through these pores to the wellpipe, and through that pipe to the surface due to the pressure of underground reservoirs. But this primary production leaves behind a lot of oil. Not all oil located underground will naturally flow to the wellhead for production–as much as 60 to 80 percent of oil in a reservoir can be left in that reservoir after primary production is complete.
Myriad technologies exist to produce more of this left-behind oil from mature fields, including gas reinjection. Gas and oil are often located together in a reservoir. Depending on the pressures in the reservoir in question, gas can exist in gaseous form; because it’s lighter than oil it tends to rise to the top of the formation in what’s known as a gas cap. If under higher pressure, natural gas can actually be dissolved in the crude itself.
No matter how the gas occurs, it helps to keep the crude oil under pressure–pressure is what keeps oil moving through the reservoir and to the wellhead. And as pressure drops, gas dissolved in crude can actually begin to bubble out of solution. This bubbling action actually helps lift oil from a reservoir, a phenomenon is known as dissolved gas drive.
During gas reinjection, natural gas produced with the oil can actually be reinjected into the formation to keep pressures high. In some cases it’s also injected into the well pipe itself. The gas them bubbles back to the surface, helping to lift the crude oil.
Still more complex is carbon dioxide injection, a common mature recovery technique in the US. Sometimes heated carbon dioxide can be injected into a reservoir to literally push oil through the pores of the reservoir. By flooding a field with carbon dioxide some Texas producers have been able to squeeze significantly more oil out of reservoirs that have been producing for decades.
Again, as you might imagine, all of these advanced recovery techniques require some complex infrastructure. Giant pumps and compressors are needed, for example, to inject gases into a reservoir. And offshore deepwater fields require highly complex subsea equipment that can be remotely controlled by computer and must be installed on the seafloor directly, often at depths of a mile and a half or more.
How To Play It
Dresser-Rand (NYSE: DRC) is almost uniquely positioned to benefit from the global bottlenecks in refining, LNG capacity and production growth. It’s one of the only companies touching just about every aspect of the energy infrastructure business, from the wellhead to the consumer.
Over the next five years, the energy infrastructure boom will really kick off as the big oils put their cash to work in reversing the underinvestment of the long oilfield depression of the 1980s and 1990s.
Dresser-Rand is a leading global producer of highly specialized compressors and turbines, nearly 95 percent of which are used in the energy business. In addition to manufacturing and selling such products, Dresser also offers after-market servicing and spare parts both for its own equipment and that of the competition.
As I outlined above, new gasoline and diesel sulphur regulations require extensive hydrotreating capacity additions at the world’s refineries. This is not just a US and European issue. Some of the most dramatic new environmental standards will be coming into effect in fast-growing markets like China and India. Hydrotreating crude and gasoline to remove sulphur requires pressurizing; Dresser’s compressors are used to create that necessary pressure.
The same is true of upgrading operations–the reactions used to crack crude oil into smaller molecules all require extreme pressure. Increasingly, the world’s marginal sources of crude supply are “heavier” oils. For example, Saudi Arabia’s giant offshore Safaniya field is that nation’s main source of spare oil producing capacity. Whenever the desert kingdom increases oil production, the marginal supplies tend to be from this field. And Safaniya is a heavy crude oil field–crude from the field, containing many heavy hydrocarbon molecules that need to be broken apart to form lighter products, is tough to refine.
The same is true of the vast Canadian oil sands. Bitumen, the near-solid crude oil produced from the sands, tends to be rather heavy and can be high in sulphur. It therefore requires significant upgrading. Heavy oils mean the globe needs more upgrading capacity–upgrading operations require pressure, and creating that pressure means using large compressors and turbines.
It should come as little surprise that refining is already Dresser’s largest end market, accounting for nearly one-third of total revenues. Growth in this end market should continue to accelerate. Most of the big US refining companies have stated they are now ready to meet sulphur regulations. This is not the case outside the US; refiners in Europe and Asia still have to carry out more investment in infrastructure to meet the new regs. And all refiners around the world will be keen to upgrade their systems to accept the more marginal grades of crude now in greatest supply worldwide.
Fortunately, Dresser has a superb position overseas. As the chart below illustrates, a little over a third of revenues come from the US. The balance is well distributed from around the rest of the world. Dresser maintains service and support centers in 106 countries to support its overseas aftermarket and servicing operations.
Source: Dresser-Rand
Refining is clearly only one piece of the puzzle. Dresser garnered an additional 30 percent of its 2004 revenues from sales into the upstream market, mainly oil and gas exploration and production.
As explained above, deepwater operations also require the use of compression equipment. Crude oil and gas can be produced together from a single subsea well. Pressure is used to separate these two commodities on board floating production vessels. Pressurized chambers are also used to as part of other gas processing operations such as de-sanding and removing water vapor in the natural gas stream.
Dresser has garnered several major contracts to supply compression equipment for floating production, storage and offloading platforms (FPSOs), ships that are used to produce hydrocarbons from offshore, subsea wells.
Onshore, compressors are used in what’s known as the gas gathering pipeline system. The gas gathering system is a network of small-diameter pipes used to transport gas from individual wells to gas processing plants. As wells mature and pressures drop, gas gathering systems must be enhanced with compressors to make sure gas moves through the system effectively. Closer still to the wellbore, Dresser supplies gas reinjection equipment.
Another 20 percent of revenues for Dresser come from the midstream gas business. Basically, that means pipeline infrastructure. When moving gas over long distances, compressors are required to boost speed. And as I outlined above, gas stored in underground reservoirs is pressurized using compressors.
More exciting from a growth standpoint is the LNG business. To date, Dresser has a roughly 25 percent global market share in LNG regasification compressors and more than a third of the global market for liquefication. Dresser missed out on a few large LNG orders in recent years to the likes of General Electric (NYSE: GE).
But more recently it’s focused attention on building out its LNG business. Dresser has the most advanced compression technology on the market. Because this equipment is more reliable, it has less downtime–downtime means lost revenues. There’s a growing sentiment that Dresser will grab a big LNG contract win within the next six months; such a win would be a strong near-term catalyst for the stock.
Other Competitive Advantages
I see several other key competitive advantages for Dresser. The first is the company’s gigantic existing installed base of equipment. The reason this is an advantage is that Dresser garners most of its revenues and earnings from aftermarket sales and services, not the original sale of equipment. Because compressors can last for several decades, the big business is the sale of spare parts and maintenance contracts. After-market work is about two-thirds of the company’s revenue mix.
Dresser equipment accounts for roughly half the current global installed base. As you might expect, Dresser does a good chunk of the maintenance and repair work on its own installed base.
Another big advantage is that Dresser focuses almost exclusively on the high end of the compressor market. That means that most of its units are custom made to handle a particular job or project. Companies like Hanover Compressor (NYSE: HC) tend to manufacture and lease out lower-end compressor units.
The advantage of the high-end market is two-fold. First, high-end compressors are the sort installed in big projects like new LNG terminals and deepwater developments. Such projects take years of planning and development to complete; Dresser normally has a very good idea of its likely revenues because its compressors are part of these longer-term projects. Second, the high-end compressor market is dependant on technology and reliability more than price; Dresser’s units are generally recognized as technologically superior to other units on the market so it doesn’t have to compete solely on costs.
A final advantage for Dresser is the value-pricing contract and the company’s strategic alliances. Instead of simply selling a compressor unit for a fixed price and then agreeing to separate service terms, such contracts actually bundle together service and manufacturing services. The company buys the unit and hires Dresser to service and maintain it. Dresser also receives added revenues for reliability–by maintaining the unit and limiting downtime, Dresser actually earns larger revenues. This type of contract reflects the reality that downtime for refiners and LNG terminals spells lost revenues.
The advantage to the customer is that a value-pricing contract provides the highest reliability and service and minimizes downtime. For Dresser, such contracts are a way of locking customers in–it would be very difficult for a competitor to take any of Dresser’s after-market business when the equipment is covered by such a contract.
Roughly half of Dresser’s new revenues are part of alliances with energy firms. These global alliance contracts normally entail Dresser forming a very tight relationship with a particular company to supply compressors. Most such contracts are value-based in some way.
Dresser Rand is now a component in the Wildcatters Portfolio.
Other Infrastructure Plays
My other favorite plays on global energy infrastructure are Cooper Cameron (NYSE: CAM) and FMC Technologies (NYSE: FTI), members of the Wildcatters Portfolio. Both are plays on subsea equipment, a key link in developing deepwater reserves as outlined above. (For more on that market, check out The Energy Strategist, April 13, 2005, “Going Deep”.)
I’m also adding Tidewater (NYSE: TDW) to How They Rate as a buy recommendation and will continue to track the stock as a trade recommendation. Tidewater is the leading supply ship operator globally with a fleet of more than 500. Supply ships are used to transport products used in the drilling process from the shore to offshore drilling rigs and production platforms. Items transported include workers and heavy equipment like drill pipe, cement and fuel. These ships are also used to aid offshore construction projects.
Some of Tidewater’s ships are also equipped to perform specialized functions. For example, some offshore platforms are moored or anchored–some of Tidewater’s ships are designed to help place those anchors effectively on the sea floor. Also, many drilling rigs aren’t designed to move great distances under their own power–Tidewater owns powerful tug-like boats for towing rigs into place.
Tidewater has a particularly strong presence in the Gulf of Mexico. Fortunately, the company has reported no major damage to ships as a result of the recent passage of the hurricanes. Though its headquarters has been temporarily moved from New Orleans to Houston, there’s been no disruption of operations.
Like the contract drillers and tanker ship companies, Tidewater charges a certain day-rate for leasing out its ships and crews. Due to the global pick-up in offshore projects and construction activity, those day-rates have been rising. The stock is a direct play on the growth in offshore investment activity.
In the short run, Tidewater will benefit from hurricane-related construction and clean-up efforts in the Gulf. Longer-term, higher spending on offshore infrastructure will power demand.
Finally, I’m adding Cheniere Energy (AMEX: LNG) to How They Rate as a buy. Cheniere constructs LNG terminals and facilities in the US, and has ownership interests in four proposed LNG terminals. Three of the terminals have already received government approval and construction has started on two. Both should be up-and-running within the next three years.
Cheniere has also lowered its risk by selling regasification capacity to the big energy companies in long-term contracts. This will ensure that the company is not particularly vulnerable to commodity price swings in the gas market.
Cheniere has an early lead in the LNG terminal business. That said, it’s still not a profitable company and likely won’t be until contract revenues start rolling in after 2008.
Does It Matter?
By Yiannis G. Mostrous
Not a single day goes by without someone saying that China and India are consuming the world’s oil. If the Asian giants would only slow down, we could all drive our SUVs to work and back without thinking of the monthly payment on the gas-only credit card.
Well, they might do just that.
Anecdotal evidence coming from China is showing that oil demand is gradually slowing down, not so much due to the per-barrel price (the Chinese government subsidizes oil prices), but because Chinese companies are having some difficulty making profits. A gradual slowdown in manufacturing has also lowered transportation intensity.
So we may see oil at $55 next year. But just two short years ago everyone was talking about $25 oil. Never happened, never will.
Oil is making a new base at around $40 and the world will have to accept it. Of course, when oil trades at $70 and gradually moves back to $55 everyone is pleased. Nevertheless, the new higher base will be a reality, and given the short supply of memory power, no one will dare mention $25.
The recent hurricanes proved how vulnerable the world’s energy infrastructure is. And do not be fooled: as easy as the per-barrel price of oil can go down to $55, it can also go up to triple digits. From terrorism to political instability to the weather, there are plenty of upward catalysts to worry about.
The world has only 1.4 million barrels per day of spare production capacity, or less than 2 percent of current global demand–not a safe buffer. Unless global demand collapses, the long-term case for energy stocks (with the obligatory ups and downs) remains intact.
Our favorite big energy stocks continue to be ExxonMobil (NYSE: XOM), Total (NYSE: TOT), Marathon Oil (NYSE: MRO), BP (NYSE: BP) and ConocoPhillips (NYSE: COP).
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