Liquid Gold
Natural gas prices in the US remain well off their 2005 post-hurricane highs. And gas drilling activity in North America has remained subdued because of weak prices, rising drilling costs and bloated inventories of gas in storage.
But this short-term reality obscures the long-term growth to come from the gas market. The simple fact is that gas is an important fuel for power plants as well as a key source of heat used in a variety of industrial activities.
Better still, natural gas is a far more environmentally friendly fuel than crude oil or coal; gas demand has been accelerating in key markets such as Europe and the US.
Unfortunately, production basins near these key markets have been depleted and are seeing declining production. Gas consumers are increasingly forced to source their natural gas from more distant reservoirs. That all adds up to growth for liquefied natural gas (LNG) technology.
A host of companies are seeing rising orders and growth as a result of all that spending. Better still, it doesn’t matter one whit where US gas prices are trading; large, international LNG projects are completely insensitive to commodity prices. In this issue, we’ll take a closer look at LNG technology, and the key beneficiaries of growth in the LNG market.
Asia is experiencing a 4.7 percent annualized growth in demand for natural gas as gas consumption continues to rise. And it’s less polluting than other fossil fuels such as coal. I see several ways to profit from this. See Gas Growth.
Exporting natural gas was a problem in the past because of the process necessary to transport it. However, new liquefying technologies are making it easier to move this material to and from areas previously unable to do so. This also spells increased returns for tankers, which are responsible for such transportation. See Going Liquid.
There are three key areas to watch regarding LNG demand: North America, Europe and Asia-Pacific. Previously self-sufficient countries are seeing a decline in production, which will require more importation of natural gas supplies. Several key exporters will benefit from this rise in demand as countries work to remain price competitive with other nations. See Drivers for LNG Growth.
I already hold several key LNG plays in the TES portfolios. But I’ve had my eye on a few other companies as well that I’m adding to both the portfolios and my How They Rate soverage. See How to Play It.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
Global natural gas demand is booming. In fact, natural gas demand has been growing significantly faster than demand for crude oil and other liquid fuels, a pattern that’s projected to continue for the foreseeable future. Check out the chart below for a closer look.
Source: Energy Information Agency (EIA) International Energy Outlook 2007
This chart illustrates average annualized growth in liquid fuel, which doesn’t include liquefied natural gas, and natural gas consumption by region. I further divided each region by grouping countries as either members of the Organization for Economic Co-operation and Development (OECD) or non-members. The OECD regions represent the developed world, while non-OECD regions represent developing nations like China and India.
Although it’s clear that, in every region of the world, natural gas demand is set to grow at a faster pace than liquid fuels, there are some particularly notable data points on this chart. For example, the Energy Information Agency (EIA) currently projects that demand for natural gas will grow at a 1.5 percent annualized pace in developed Europe even as liquid fuel demand remains essentially stagnant out to 2030—a dramatic disparity in growth.
And just about every investor the world over has heard about the tremendous growth in oil demand coming from Asia. It’s worth noting, however, that natural gas demand from non-OECD countries in Asia is growing at nearly twice the pace of liquid fuel demand.
And if you think that Asia’s 4.7 percent annualized growth sounds modest, think again. Over a 25-year period, 4.7 percent annualized growth spells a more than threefold jump in demand for natural gas from the region.
To put these percentage growth figures into context, check out the chart below.
Source: EIA
This chart illustrates historic and projected growth in gas consumption in terms of trillions of cubic feet per year. Globally, gas consumption totaled about 100 trillion cubic feet in 2004 and will surpass 160 trillion cubic feet in 2030.
The two primary uses of natural gas globally are generating electric power and industrial uses. Industrial uses include the use of natural gas to manufacture chemicals, fertilizers and plastics, as well as natural gas that’s used to produce heat for refining and oil sands production processes.
The majority of the growth in global gas demand is coming from the electric power sector. As I’ve highlighted on several occasions in TES, demand for electricity globally is growing far faster than demand for oil, particularly in the emerging markets.
Gas has some advantages over coal or oil as fuel for power plants. Chief among those is it produces far lower emissions of pollutants, including sulphur dioxide, mercury and even carbon dioxide.
As I’ve noted before, I’m not here to save the world or make judgments about whether global warming is real or to what extent it will affect the global climate.
The simple fact is that global warming is receiving plenty of attention all over the world, and governments are starting to regulate and tax carbon emissions. Therefore, as investors, we can’t ignore the issue or the global political climate. However, we can certainly find ways to profit from it.
Gas is one way to profit from global-warming legislation and taxation. Burning natural gas in a power plant emits around 40 to 50 percent less carbon dioxide than coal. (For a more complete analysis of environmental drivers for gas use, check out the June 20 issue of TES, Europe’s Gas.)
Of course, growth in industrial demand is also having an impact, particularly in the developing world. As you might expect, rapid economic growth in the developing world is driving strong growth in demand for plastics for everything from consumer packaging to building materials.
And, as I explained at length in the Sept. 19 issue of TES, Down on the Farm, Asian demand for fertilizers is booming. Because the plastics and fertilizer industries are important industrial consumers of gas, all this adds up to higher demand.
Back to In This Issue
LNG is nothing more than a super-cooled version of natural gas. When gas is cooled to around minus 260 degrees Fahrenheit (minus 162 degrees Celsius), it condenses into a liquid.
Better still, as gas cools, it takes up less space; LNG takes up roughly one-six-hundred-and-tenth the volume of gas in its natural gaseous state. To put that into context, a beach ball-sized volume of gas shrinks to the size of a standard pingpong ball when it’s converted to LNG.
The benefit of this is transport. Traditionally, the vast majority of natural gas has been transported in its normal gaseous state by pipeline. So most natural gas consumed in the US was either produced domestically or imported by pipeline from neighboring Canada.
By extension, gas reserves located far from existing pipeline infrastructure had little or no value. Although oil from such fields can be loaded onto tankers and shipped anywhere in the world, gas was considered stranded. Stranded natural gas was routinely burned (flared) or reinjected into the ground as a form of permanent storage.
LNG frees gas from the pipeline grid. If you’re able to turn natural gas into a liquid, it can be loaded onto tankers just like crude oil and transported anywhere in the world. Gas reserves once considered stranded and useless can be exploited using LNG technologies.
The basic LNG supply chain is simple. The gas is produced the same way as if it were to be transported by pipeline to the consumer. This raw natural gas is then transported by pipe to a liquefaction facility. These liquefaction facilities are located in the gas-exporting country.
The liquefaction facility represents the largest single cost center in the LNG supply chain. Basically, the gas is treated to remove some of its impurities, such as corrosive sulphur, carbon dioxide and water, and then fed into a gas liquefaction unit known as a train. Most liquefaction facilities are made up of multiple trains.
Although it’s obviously on a much larger scale, the basic process of cooling natural gas isn’t much different than your home refrigerator or air conditioning system. The principle at work is that gases heat up when they’re compressed and cool down when pressures are released.
It’s not the natural gas itself that’s compressed and decompressed but a refrigerant gas such as propane. Therefore, LNG trains employ the use of a series of massive compressors and a wide variety of refrigerant gases. The exact process varies somewhat between projects.
After the gas is liquefied, it’s loaded onto specialized LNG tanker ships. These ships typically have large spherical storage tanks visible on the deck of the tanker. See the picture below for a closer look.
Source: Woodside Petroleum
These tank storage units are designed with multiple layers of insulation to keep the LNG cool during transport. Nonetheless, even with multiple layers of insulation, LNG cargo does warm up slightly during the course of the voyage–typically around 0.15 percent of the cargo boils each day. This is called boil-off gas.
If the boil-off gas was allowed to build up too much, pressure inside the tanks would increase. In modern LNG tankers, it’s actually removed from the storage tanks and used to help propel the tanker ship.
LNG tanks are never really fully emptied; a small quantity of so-called heel gas is retained. This gas helps to retain the LNG tanks at super-cooled temperatures during their journey back to pick up another load of LNG.
The final step in the LNG supply chain is the regasification terminal. These terminals are located in the importing country. Natural gas is reheated to more normal temperatures and then injected into the pipeline network to be used just like normal gas.
It’s important to note the difference between LNG and gas-to-liquids (GTL) technologies. LNG is just normal gas cooled into a liquid state and then regasified for use in exactly the same end-markets as gas carried entirely by traditional pipelines.
I explained GTL technology at some length in the April 12 issue of TES, Finding New Btus. This technology involves a series of chemical processes—the Fischer-Tropsch (FT) process–to actually convert gas into a diesel-like liquid fuel.
As you might expect, there are significant upfront capital costs involved with constructing an LNG supply chain, particularly for liquefaction facilities. That’s why producers typically secure long-term gas supply deals with customers for much of the output from their liquefaction facilities. This helps to ensure they’re able to garner an acceptable return on investment and a ready market for the gas.
Of course, there’s also a spot LNG market. An electric utility or industrial customer can arrange for a one-off specific amount of LNG delivery at a pre-determined competitive rate. The spot market accounts for between 10 to 15 percent of the global LNG trade right now, but spot transactions are becoming an ever-larger part of the LNG market.
LNG tanker ships can be owned by the gas producer, the gas importer or third-party tanker ship operators. In the latter case, operators charge a certain fee for the lease of their ships.
Unlike many crude oil and refined products tankers, these tanker rates are also secured by long-term contracts. Contracts to transport LNG from a particular liquefaction project are negotiated before the tanker company actually arranges for construction.
For example, Proven Reserves Portfolio holding Teekay LNG Partners (NYSE: TGP) leases all its ships on 15- to 20-year contracts that guarantee it a reasonable return. Typically, the company signs the contract long before the ships have left the shipyard. The company uses that stable contract base to justify and finance the cost of new tanker construction.
Back to In This Issue
Source: Oil & Gas Journal, EIA, BP Statistical Review or World Energy 2007
In this chart, I present natural gas international trade growth statistics for both the trailing 10-year period and for 2006.
I see two points worth noting from this chart. First, on a trailing 10-year basis, trade in natural gas across international borders has grown at nearly twice the pace of global gas production and consumption. In other words, international trade is becoming a more important part of the global gas supply picture.
And second, LNG trade is growing significantly faster than overall gas trade. Total global trade in natural gas has averaged about 5.4 percent annualized over the past decade but shrank to just 2.5 percent in 2006.
But last year’s drop-off in growth was due entirely to a slump in trade via pipelines for 2006. Growth in LNG trade has averaged nearly 8 percent annualized over the past decade and accelerated to a whopping 11.7 percent last year.
The major reasons for the growth in natural gas trade and LNG is that gas reserves near the big consuming markets have been depleted and production is falling. Imports of natural gas are, therefore, absolutely crucial to meet growing demand and fill the gap left by falling domestic output. Here’s a rundown of gas trade developments in the three prime centers of natural gas consumption worldwide:
North America
The US is far and away the biggest, single, gas-consuming nation in the world. Consider, for example, that the US consumes about 60 billion cubic feet of gas per day compared to just 42 billion for all the Asia-Pacific countries combined.
Nevertheless, up until the late 1980s, America was essentially energy self-sufficient when it came to natural gas. Check out the chart below.
Source: BP
This chart shows consumption and production of gas in the US. The gap between the consumption and production lines indicates the amount of natural gas the nation needs to import.
America’s import requirements began to ramp up in the ’90s, accelerating into the latter days of that decade. The reason is that the US built a huge amount of gas-fired power capacity in the ’90s.
Gas demand ramped up as utilities needed to supply all those new plants. Demand for gas to fire these plants grew far faster than production throughout the ’90s.
And another notable problem has emerged since 2000: US gas production has peaked. US gas production is no higher now than it was in the early ’90s. This isn’t due to any voluntary production restraint; it’s simply due to the maturation of gas reservoirs. The large gas fields that once supplied all the gas the US needed have now been in production for years, and output is slowing.
The best way to illustrate that US gas wells are mature and past peak production is to look at the two charts below in tandem: one of the active gas rig count and one of natural gas production.
Source: Bloomberg, Baker Hughes
Source: EIA
I used a monthly chart of natural gas production over the past few years to better illustrate the gradual, yet notable, decline in US gas production.
The active rig count is nothing more than a simple measure of how many rigs are actively drilling for natural gas in the US. As you can see, the rig count is currently near a multi-year high; the rig count has been accelerating in an almost uninterrupted fashion for the past few years.
The conclusion is simple: Producers are aggressively drilling more wells, bringing a record number of drilling rigs to bear. Yet despite all these new wells and new drilling activity, gas production isn’t growing. In fact, gas production is in decline.
To look at the same data in another way, consider that the average US gas well flowed some 185 million cubic feet per day in 1990; today, that figure is closer to 120 million cubic feet. US producers are targeting smaller, less prolific reserves.
In addition, they’re fighting rapid declines in gas production from older wells. US producers are drilling aggressively just to try to maintain current production.
All this adds up to an increasing need for the US to import natural gas. At first, transporting Canadian gas south through pipelines could easily satisfy the nation’s import requirements. Not surprising, US gas imports from Canada more than doubled from 1.43 trillion cubic feet per year in 1990 to 3.6 trillion cubic feet in 2002.
But Canadian gas imports aren’t sufficient to meet America’s needs any longer. The problem in Canada is much the same as in the US: Canada’s gas fields are also maturing, and production is in decline as well.
Moreover, Canadian gas demand has been rising at a faster pace than in the US in recent years. One big driver for that growth in demand is Canadian oil sands production.
Producing the oil sands requires the use of large amounts of steam. The primary energy source for producing all that heat and steam is natural gas. Therefore, plans to ramp up oil sands production in coming years spell inexorably rising demand for gas and less gas available for export to the US.
It should come as little surprise that US imports of LNG are set to rise sharply in the coming years. Check out the chart below for a closer look.
Source: EIA
As you can see from this chart, the EIA expects LNG to overtake pipeline imports from Canada as the No. 1 source of imported gas into the US by the middle of the coming decade. LNG imports are set to fill in the gaps left because of the decline in Canadian output.
And this isn’t just some pie-in-the-sky estimate by the EIA. The fact is that LNG imports are already having a meaningful impact on the US natural gas market.
The chart below shows actual LNG imports as a percentage of total imports from the first quarter of 2006 through the second quarter of 2007. I’ve also included short-term EIA estimates and preliminary data for the remainder of 2007 and the entirety of 2008.
Source: EIA
What’s clear from this chart is that imports of LNG surged in the first two quarters of 2007, accounting for more than 24 percent of total US natural gas imports.
The reason for the surge was twofold. First and foremost, US natural gas prices, though still significantly off their 2005 post-hurricane highs, were well above gas prices in Europe and Asia. LNG, like crude oil, can be sent to the markets where returns are most favorable; because the US had relatively high gas prices, the nation was able to attract the LNG imports.
Second, Canadian gas production looks troubled right now. Because of the slump in gas prices, the Canadian rig count has fallen sharply. Producers just aren’t drilling very aggressively.
Because Canadian gas wells have a rapid decline rate, Canadian production has begun to fall. Canada wasn’t able to export as much gas as normal in the first six months of 2007. Therefore, LNG helped to fill that supply gap.
The chart below shows that US LNG imports actually shot to record levels earlier this year.
Source: EIA
Since that time, the EIA estimates that LNG shipments have fallen back to more normal levels. The problem this time around is some shutdowns at Japanese nuclear power plants meant that Japan needed to import more gas. With returns for selling gas higher in Japan during the past few months, that nation has attracted LNG imports.
The US currently has five operating LNG regasification terminals: Everett, Mass.; Cove Point, Md.; Elba Island, Ga.; Lake Charles, La.; and one terminal in the Gulf of Mexico. Total throughput capacity of these facilities totals about 5.8 billion cubic feet per day.
I’m often asked about regulatory hurdles for new LNG developments. Although new LNG regasification operations often are the target of local opposition, there are a number of new facilities scheduled for construction in the next few years. This includes a large number in and around the Gulf Coast near existing energy infrastructure, where locals tend to be less likely to object to new terminals.
There are also plans to site several new gasification terminals in the Gulf of Mexico. This eliminates some of the permitting problems entirely.
It will take a few more years for these new terminals to be constructed and begin accepting shipments. But I see no reason that US regasification capacity will be insufficient to handle the sort of LNG imports required to meet natural gas demand.
The US LNG market is dominated by producers in the Atlantic basin. The chart below offers an overview of the main sources of US LNG so far in 2007.
Source: EIA
The cost of delivering LNG to the US markets depends on a number of factors, including the transport distance and the cost of production. For example, Qatar has among the lowest gas production costs of any country in the world. But because of its distance to the US, the EIA estimates that it costs $1.75 per million British thermal units (MMBtu) to transport LNG from Qatar to the US Gulf.
However, according to 2005 estimates from the EIA, all-in costs for delivering LNG range from about $2.67 to $6.86 per MMBtu. This isn’t much different that the production cost range for gas-focused exploration and production (E&P) firms in the US.
And despite the fact that LNG means additional gas supplies for the US, LNG also puts a sort of floor under gas prices. The US will need to be increasingly price competitive with other nations–including China and India–for spot LNG supplies. To attract marginal LNG imports, the US market will need to offer prices that either meet or exceed prices of gas elsewhere.
Bottom line: The US will need to drastically ramp up gas imports in the coming years, and much of that import demand will fall to LNG.
Europe
I won’t linger on this market because I offered a complete, detailed assessment of the European gas market in the June 20 issue of TES.
Suffice it to say that European gas demand is growing faster than gas demand in the US. And I’m not talking about just the Eastern European countries that are seeing the most rapid economic growth but the developed nations of Western Europe.
Between 2004 and 2030, OECD Europe’s total gas demand is projected to jump from 18.8 trillion cubic feet (tcf) to 26.9 tcf, a total increase of 43 percent. In OECD North America, demand will increase by only 16.5 percent over the same time period. See the chart below for a closer look.
Source: EIA
By far the largest contributor to that increase is the electric power sector. The EIA estimates that OECD Europe will burn more than 11.1 tcf of gas in power plants by 2030, up from 4.6 tcf in 2004. That’s growth of more than 140 percent.
During the same time period, the US electric power sector is only likely to see growth of 9 percent. Given that the EIA estimates that the US will only consume about 6 tcf annually of natural gas in power plants by 2030, it’s not hard to see how important Europe is becoming to the global natural gas market.
There are a few main drivers of that increased use. First up, as I noted above, the EU already has carbon-dioxide regulations in place. Gas is the most expedient way for a nation to reduce carbon-dioxide emissions; gas emits about 40 to 50 percent carbon than an equivalent-sized coal plant.
The second reason is much the same as for the US: Europe’s traditional domestic sources of gas are in decline. As I explain the June 20 issue, North Sea gas production has peaked even as gas demand surges necessitating more imports.
In fact, OECD Europe already imports about 40 percent of its natural gas requirements. By 2030, the EIA projects Europe’s import dependence will skyrocket to 65 percent of demand.
To finance its gas gap, the EU looks east to Russia. Russia is far and away the world’s largest producer of natural gas, and it’s estimated to have the world’s largest reserves of natural gas. Much of this gas moves by pipeline.
But it’s clear that Europe would prefer to diversify its gas import supply. That means investing in LNG regasification terminals.
The UK was actually the world’s first LNG importer; its first LNG cargo arrived back in 1964 from Algeria. But with the discovery of North Sea supplies, Britain became gas self-sufficient and the LNG terminal was closed.
But that process has now been thrown into reverse because of the decline in North Sea production. Britain now has an LNG terminal located in Kent that received its first shipments in 2005.
That terminal is being steadily expanded in size, and now there are two brand new terminals under construction in Wales along the nation’s western coast. There’s also an operating LNG terminal in southern Scotland.
Spain, Portugal, Belgium, Greece, Italy and France also have several existing LNG import terminals. In 2006, Spain and France were the largest two importers; Spain imported 24.4 billion cubic meters (bcm), and France imported 13.9 bcm of LNG.
Most of these nations also have early plans for additional terminals that would increase their ability to import gas. The chart below shows the source countries for most European LNG imports as of 2006.
Source: BP
It’s clear from this chart that Europe’s suppliers are much the same as for the US, though the percentages are somewhat different. The reason for that is obvious: Trinidad dominates US LNG imports because it’s so close to the mainland US, reducing transport costs. Similarly, North Africa’s proximity to the EU makes it an obvious source of LNG imports.
But the European and US markets are becoming more related. North Africa is increasing in importance as a source of US imports, and Trinidad certainly isn’t meaningless to Europe.
These two key gas-consuming regions are in competition. For example, LNG imports into the US slumped in 2005 and 2006 because gas prices were more attractive in the EU. LNG shipments could be diverted to these nations, where returns were higher.
Asia-Pacific
I outlined the basic outlook for the Asia-Pacific LNG markets in the Sept. 13 issue of The Energy Letter, Liquid Energy.
To summarize, Japan and South Korea are currently the world’s two largest importers of LNG, accounting for about 39 percent and 16 percent, respectively, of world trade. The reason is simply that these countries have only small, domestic reserves of hydrocarbons; both nations have been largely import dependent for decades.
Japan has no domestic natural gas production to speak of and relies on imports for substantially all of its 8.2 billion cubic feet (bcf) of daily consumption. Japan currently imports no natural gas by pipeline; all of that gas comes from LNG.
Australia, Malaysia and Indonesia are Japan’s largest sources of LNG imports. Because a good deal of Indonesian gas is set to be diverted to the fast-growing domestic market, Australia and Malaysia are likely to be the dominant sources of Japanese LNG imports in the coming years.
Japan is a developed country, but gas demand growth is relatively rapid. Japan’s gas consumption is expected to jump from 3 tcf per year in 2003 to more than 4.3 tcf by 2030. Just as with Europe, this is mainly a result of the need to cut back on carbon emissions. Much of that growth will likely continue to be met with LNG.
South Korea is much the same story. Gas demand totals 3.3 bcf per day; most of that demand is satisfied with LNG imports.
Oman, Qatar and Malaysia are the three largest sources of South Korean LNG. South Korean gas demand is expected to increase by 67 percent in the coming 23 years, a bit faster growth than in Japan.
Although Japan and South Korea dominate current trade in LNG and are showing slow-but-steady growth in imports, the real sizzle is found in the non-OECD Asian nations. The dominant growth drivers here are, as you might expect, China and India. Check out the EIA’s forecasts for Chinese and Indian demand and supply for gas in the chart below.
Source: EIA International Energy Outlook 2007
Currently, the China and India gas markets are essentially in balance. Production is nearly enough to satisfy demand. But because of the rapid growth in demand for gas, this gap will grow to a staggering 4.1 tcf annually by 2030.
Therefore, these markets will be importing every bit as much gas as Japan by 2030. Although some of this demand is likely to be settled by pipeline imports from markets like Russia and Iran, LNG will play a prominent role.
Already, China and India are players in the LNG market. China received its first shipment of LNG in fall 2006. The country imported about 1 billion cubic meters (35 bcf) of LNG for 2006.
India actually imported far more, a total of 8 billion cubic meters (282 bcf). Australia accounted for all of China’s LNG imports, while Qatar was the dominant player in the India gas market.
More broad, Asian Pacific’s growing demand for LNG will likely be met via exports from other Asia-Pacific nations as well as from the Middle East. Qatar overtook Indonesia this year as the world’s largest producer of LNG. Although transport costs from Qatar to Asia are higher than from Indonesia, Qatar’s massive North gas field offers some of the lowest production costs in the world.
I expect Qatar to remain a key supplier.
Indonesia will remain a big supplier, but it’s in decline. The country’s Tangguh LNG project still hasn’t fully started up; this will be a new push for Indonesian production.
However, the two country’s existing LNG projects went into production from 1978-86 and are now showing steady production declines. In addition, Indonesia gas consumption growth is booming, so more gas will be diverted to domestic uses over time. Nevertheless, Indonesia will remain a key global exporter for the foreseeable future.
Malaysia will also remain a big player in Asian LNG. The country has three LNG liquefaction facilities and has taken steps to expand production from each. However, any plans for further plants are currently on hold.
Perhaps the most interesting LNG supplier of all from an investment standpoint, however, is Australia. The nation is politically stable, and unlike many other resource-rich countries, the government has been fair and transparent in its treatment of resource access and taxation.
As a result, Australia has benefited from a massive increase in investment on the part of global energy firms. For a closer look, check out the chart below.
Source: EIA
Australia’s natural gas production is set to increase at an annualized pace of 4.3 percent out to 2030. This is the fastest production growth projected for any country, anywhere in the world. The vast majority of that gas will be exported. In fact, Australia alone accounts for all the gas production growth forecast for the developed world out to 2030.
The country has two operating LNG projects: Darwin LNG and North West Shelf. The majority owner of Darwin is ConocoPhillips; the liquefaction plant made its first sale in February of last year.
Currently, this facility can produce about 3.5 million metric tons (3.9 million short tons) of natural gas per year. All that production is being sold to Japan under a 17-year agreement. It’s possible that the facility could be expanded to roughly triple its current size with existing permits, though that would require piping in gas from other fields.
The North West Shelf (NWS) project has been in operation since the late ’80s, though it’s been expanded significantly since that time. This facility is owned by a consortium of six major integrated oil companies, with Australia’s Woodside Petroleum (Australia: WPL, OTC: WOPEY) as the operator.
Located in Western Australia, NWS produces around 11.5 million metric tons of LNG per year. Although the project’s biggest customer is Japan, China’s only LNG imports in 2006 came from the NWS project.
But there are several huge LNG projects planned in the next few years. Specifically, Gorgon LNG—majority owned by Proven Reserves Portfolio bellwether Chevron Corp–is scheduled for completion in 2010. This facility would have a capacity of about 10 million metric tons of LNG per year.
Woodside Petroleum has two additional facilities, Withnell Bay and Burrup Peninsula. The former is scheduled for completion next year and will produce about 4.4 million metric tons of gas. The latter will be completed in 2010 and will produce in the 4.3 million to 4.8 million metric ton range.
With all these new LNG projects coming on stream, Australia looks like it’s in a good position to continue to be a dominant player in Asian LNG.
Back to In This Issue
BG Group (London: BG/, OTC: BRGYY)–Wildcatter BG Group is a top-notch play on the Atlantic Basin LNG trade. The company operates in the LNG business at every conceivable level, from production to regasification and marketing.
BG has four basic business units. Ranked by importance in terms of operating profits, these units are: E&P, LNG, transmission and distribution, and power generation. E&P and LNG are far and away BG’s most important business units. Buy BG Group up to 90.
Dresser-Rand (NYSE: DRC)–Wildcatter Dresser-Rand has been among the best-performing picks in the Wildcatters Portfolio during the past year. I’ve profiled the stock on several occasions, including the Nov. 22, 2006, issue, “Leading Income,” and the Oct. 5 flash alert, “Buying the Dip.”
Dresser makes compressors and turbines used in a variety of energy-related applications; energy-related fields make up about 93 percent of Dresser’s business. Among its more important end markets are floating production storage and offloading ships–basically floating oil and gas production platforms used in offshore field developments. And compressors are also used heavily in refining operations, especially operations related to the processing of heavy and sour crude oils.
But as I noted above, LNG liquefaction terminals also use compression equipment. Dresser’s management believes this is as much as a $100-million-per-year opportunity for the company. Buy Dresser-Rand below 40.50.
Teekay LNG Partners (NYSE: TGP)–Teekay LNG Partners is a master limited partnership (MLP) that owns a fleet of LNG tanker ships. All of these ships are leased under long-term arrangements—typically 15 to 20 years–to major LNG projects, including new LNG developments in Qatar and Indonesia. These contracts provide for a fixed rate plus an adjustment to account for cost inflation.
In the second quarter, Teekay LNG hiked its quarterly distribution to 53 cents per unit (MLP lingo for share), equivalent to a yield of about 6.7 percent. That represents a 15 percent jump over its prior quarterly payout of 46.25 cents per unit.
The reason that Teekay LNG increased its dividend is that the company accepted delivery of new tanker ships. As soon as the ships were delivered, the company put them out on pre-negotiated long-term contracts.
As the cash from these contracts started to hit the bottom line, Teekay was able to boost its payout. I calculate that the company’s second quarter payout amounted to just 86 percent of the actual distributable cash flow earned during the quarter. That’s healthy coverage for an MLP.
Teekay has several new LNG ships scheduled for delivery over the next few years. This opens up the possibility for further bumps to the distributions as these ships start earnings revenues.
In fact, Teekay LNG should be able to sustain distribution growth in the 10 to 15 percent annualized range over the next three years. That would put its quarterly payout at about 75 cents in three year’s time. That would equate to a yield of 9.5 percent at current prices. Teekay LNG Partners is a buy under 40.
For more on why I believe Teekay and the other MLPs have seen a pullback of late, check out the Oct. 3 issue, The Partnerships.
Chart Industries (NSDQ: GTLS)–Chart Industries manufactures and sells a variety of cryogenic equipment and engineered parts. Chart manufactures these products for a variety of industries, including energy and medical.
However, roughly 56 percent of 2006 revenues came from energy-related businesses and nearly 80 percent of the company’s backlog is related to energy. Therefore, Chart is becoming an ever-purer play on the energy business.
One of the company’s primary growth markets in recent years has been LNG. For example, Chart makes advanced heat exchangers, used in both the LNG and gas processing markets.
In the LNG market, heat exchangers are used during the liquefaction process. Gas typically goes through multiple stages of refrigeration, and heat exchangers are used at each step.
As for processing, natural gas is composed mainly of methane but also includes other hydrocarbons such as propane and gases such as carbon dioxide. To separate these gases, processors can rely on their different cooling and boiling points. This process also requires the use of heat exchangers.
Chart also sells these products into the industrial gases business. Major customers include firms such as Air Products & Chemicals and Praxair. Although that may not sound like the company is energy-related, think again.
Hydrogen gas produced by companies like Air Products and Praxair is used to remove sulphur from crude oil. Industrial gas manufacturers have seen huge growth in sales for refiners in recent years.
And one way to improve the fuel efficiency of many industrial processes—such as steel production—is to boost the oxygen content of the air. This can also reduce emissions of everything from sulphur to carbon dioxide. This fact has been benefiting the industrial gas business as well.
In addition to heat exchangers, Chart also makes vacuum-insulated LNG pipes–pipes that are specially sealed and insulated to allow for the transport of super-cooled LNG. Clearly, if you transported LNG through a normal pipe, you’d not only damage the pipe but also allow the LNG to heat up and boil off. The pipes Chart makes are highly specialized.
In Chart’s second quarter, the company’s backlog of unfilled orders in the energy and chemical business rose to more than $58 million. Better still, the company is in the final few quarters of clearing some older legacy contracts that don’t offer the company as high a profit margin as it gets newer business. As these older contracts roll off the books, management expects profit margins to continue improving.
The equipment markets can be lumpy because of the timing of large orders. This can create some volatility in related stocks.
This is especially true for smaller firms such as Chart. But the company’s enviable position in a fast-growing market makes it worth the risk. Chart Industries is added to the aggressive Gushers Portfolio as a buy under 35.
Woodside Petroleum (Australia: WPL, OTC: WOPEY)–Woodside is Australia’s largest pure-play E&P company. Woodside has properties in various stages of production in the US, deepwater Gulf of Mexico, Australia and Africa. The company is a particularly important player in the Australian LNG market.
Woodside is one of the six owner/participants in Australia’s North West Shelf venture. The company is also the official operator of the entire LNG operation.
In the most recent quarter, that venture produced 33,701 metric tons of LNG; Woodside’s share of that production totaled more than 5,315 tons per day, a pace of nearly 2 million tons per year.
The company is currently expanding the NWS venture to include a fifth train. This $2.4 billion project should come on line and begin producing LNG for shipment by the end of next year. Total capacity for the fifth train will be 4.4 million metric tons per year, making it the largest train at the project.
Woodside also received approval for its new Pluto LNG project on the Burrup Peninsula in late July. Woodside has already negotiated the sale of 3.75 million metric tons of LNG per year to Japanese utilities under a long-term supply deal. Total output from this project should be approximately 4.5 metric tons per annum, all from a single train.
Shell, also a big global player in LNG, owns a roughly one-third stake in Woodside. That’s a sign of confidence in Woodside’s general strategy. I’m adding Woodside Petroleum to the How They Rate coverage universe as a buy recommendation.
Saipem (Italy: SPM, OTC: SAPMF)—Italy-based Saipem began as a wholly owned subsidiary of Italian oil giant Eni. But the firm was spun off as a separate company back in 1984; Eni still holds a 43 percent stake.
Saipem’s business is divided into three pieces: offshore, onshore and drilling. The offshore business includes installing offshore oil and gas platforms, laying subsea pipelines, and various other construction and large-scale engineering projects.
The offshore business is attractive due to its international focus and leverage to the hottest oil and gas markets. The large international projects that Saipem works on aren’t particularly sensitive to commodity prices; these are multi-year deals run by major integrated oils and national oil companies.
And Saipem also has significant leverage to deepwater field developments, one of the fastest-growing markets in the energy patch. Offshore revenues jumped 20 percent in the first half of 2007, and Saipem’s backlog of projects continues to grow for this unit, totaling more than EUR4.3 billion ($6.15 billion).
Saipem’s onshore business has significant leverage to LNG. The company constructs liquefaction trains and regasification facilities. Saipem has built nine liquefaction trains in Nigeria and Qatar in the past 10 years.
In addition to trains, Saipm also constructs and designs pipelines, storage facilities and other related oil and gas infrastructure. Revenues in the onshore business exploded 95 percent in the first half of this year.
Saipem is a solid, all-around play on strong energy growth themes, including LNG, deepwater development, energy infrastructure and international project development. I’m adding Saipem to the How They Rate coverage universe as a buy recommendation.
Back to In This Issue
But this short-term reality obscures the long-term growth to come from the gas market. The simple fact is that gas is an important fuel for power plants as well as a key source of heat used in a variety of industrial activities.
Better still, natural gas is a far more environmentally friendly fuel than crude oil or coal; gas demand has been accelerating in key markets such as Europe and the US.
Unfortunately, production basins near these key markets have been depleted and are seeing declining production. Gas consumers are increasingly forced to source their natural gas from more distant reservoirs. That all adds up to growth for liquefied natural gas (LNG) technology.
In This Issue
Investment in LNG infrastructure globally is accelerating. Global spending on LNG infrastructure is expected to top $250 billion in the next 30 years as LNG capacity rises at a 15 percent annualized pace.A host of companies are seeing rising orders and growth as a result of all that spending. Better still, it doesn’t matter one whit where US gas prices are trading; large, international LNG projects are completely insensitive to commodity prices. In this issue, we’ll take a closer look at LNG technology, and the key beneficiaries of growth in the LNG market.
Asia is experiencing a 4.7 percent annualized growth in demand for natural gas as gas consumption continues to rise. And it’s less polluting than other fossil fuels such as coal. I see several ways to profit from this. See Gas Growth.
Exporting natural gas was a problem in the past because of the process necessary to transport it. However, new liquefying technologies are making it easier to move this material to and from areas previously unable to do so. This also spells increased returns for tankers, which are responsible for such transportation. See Going Liquid.
There are three key areas to watch regarding LNG demand: North America, Europe and Asia-Pacific. Previously self-sufficient countries are seeing a decline in production, which will require more importation of natural gas supplies. Several key exporters will benefit from this rise in demand as countries work to remain price competitive with other nations. See Drivers for LNG Growth.
I already hold several key LNG plays in the TES portfolios. But I’ve had my eye on a few other companies as well that I’m adding to both the portfolios and my How They Rate soverage. See How to Play It.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
- BG Group (UK: BG, OTC: BRGYY)
- Chart Industries (NSDQ: GTLS)
- Dresser-Rand (NYSE: DRC)
- Saipem (Italy: SPM, OTC: SAPMF)
- Teekay LNG Partners (NYSE: TGP)
- Woodside Petroleum (Australia: WPL, OTC: WOPEY)
Gas Growth
I’ve highlighted the growth prospects for natural gas on several occasions in The Energy Strategist. At the risk of sounding repetitive for long-time subscribers, here’s a brief review.Global natural gas demand is booming. In fact, natural gas demand has been growing significantly faster than demand for crude oil and other liquid fuels, a pattern that’s projected to continue for the foreseeable future. Check out the chart below for a closer look.
Source: Energy Information Agency (EIA) International Energy Outlook 2007
This chart illustrates average annualized growth in liquid fuel, which doesn’t include liquefied natural gas, and natural gas consumption by region. I further divided each region by grouping countries as either members of the Organization for Economic Co-operation and Development (OECD) or non-members. The OECD regions represent the developed world, while non-OECD regions represent developing nations like China and India.
Although it’s clear that, in every region of the world, natural gas demand is set to grow at a faster pace than liquid fuels, there are some particularly notable data points on this chart. For example, the Energy Information Agency (EIA) currently projects that demand for natural gas will grow at a 1.5 percent annualized pace in developed Europe even as liquid fuel demand remains essentially stagnant out to 2030—a dramatic disparity in growth.
And just about every investor the world over has heard about the tremendous growth in oil demand coming from Asia. It’s worth noting, however, that natural gas demand from non-OECD countries in Asia is growing at nearly twice the pace of liquid fuel demand.
And if you think that Asia’s 4.7 percent annualized growth sounds modest, think again. Over a 25-year period, 4.7 percent annualized growth spells a more than threefold jump in demand for natural gas from the region.
To put these percentage growth figures into context, check out the chart below.
Source: EIA
This chart illustrates historic and projected growth in gas consumption in terms of trillions of cubic feet per year. Globally, gas consumption totaled about 100 trillion cubic feet in 2004 and will surpass 160 trillion cubic feet in 2030.
The two primary uses of natural gas globally are generating electric power and industrial uses. Industrial uses include the use of natural gas to manufacture chemicals, fertilizers and plastics, as well as natural gas that’s used to produce heat for refining and oil sands production processes.
The majority of the growth in global gas demand is coming from the electric power sector. As I’ve highlighted on several occasions in TES, demand for electricity globally is growing far faster than demand for oil, particularly in the emerging markets.
Gas has some advantages over coal or oil as fuel for power plants. Chief among those is it produces far lower emissions of pollutants, including sulphur dioxide, mercury and even carbon dioxide.
As I’ve noted before, I’m not here to save the world or make judgments about whether global warming is real or to what extent it will affect the global climate.
The simple fact is that global warming is receiving plenty of attention all over the world, and governments are starting to regulate and tax carbon emissions. Therefore, as investors, we can’t ignore the issue or the global political climate. However, we can certainly find ways to profit from it.
Gas is one way to profit from global-warming legislation and taxation. Burning natural gas in a power plant emits around 40 to 50 percent less carbon dioxide than coal. (For a more complete analysis of environmental drivers for gas use, check out the June 20 issue of TES, Europe’s Gas.)
Of course, growth in industrial demand is also having an impact, particularly in the developing world. As you might expect, rapid economic growth in the developing world is driving strong growth in demand for plastics for everything from consumer packaging to building materials.
And, as I explained at length in the Sept. 19 issue of TES, Down on the Farm, Asian demand for fertilizers is booming. Because the plastics and fertilizer industries are important industrial consumers of gas, all this adds up to higher demand.
Back to In This Issue
Going Liquid
Growth in global natural gas consumption is impressive but pales in comparison to growth in liquefied natural gas (LNG) trade. LNG is far and away the fastest-growing major sub-segment of the natural gas market.LNG is nothing more than a super-cooled version of natural gas. When gas is cooled to around minus 260 degrees Fahrenheit (minus 162 degrees Celsius), it condenses into a liquid.
Better still, as gas cools, it takes up less space; LNG takes up roughly one-six-hundred-and-tenth the volume of gas in its natural gaseous state. To put that into context, a beach ball-sized volume of gas shrinks to the size of a standard pingpong ball when it’s converted to LNG.
The benefit of this is transport. Traditionally, the vast majority of natural gas has been transported in its normal gaseous state by pipeline. So most natural gas consumed in the US was either produced domestically or imported by pipeline from neighboring Canada.
By extension, gas reserves located far from existing pipeline infrastructure had little or no value. Although oil from such fields can be loaded onto tankers and shipped anywhere in the world, gas was considered stranded. Stranded natural gas was routinely burned (flared) or reinjected into the ground as a form of permanent storage.
LNG frees gas from the pipeline grid. If you’re able to turn natural gas into a liquid, it can be loaded onto tankers just like crude oil and transported anywhere in the world. Gas reserves once considered stranded and useless can be exploited using LNG technologies.
The basic LNG supply chain is simple. The gas is produced the same way as if it were to be transported by pipeline to the consumer. This raw natural gas is then transported by pipe to a liquefaction facility. These liquefaction facilities are located in the gas-exporting country.
The liquefaction facility represents the largest single cost center in the LNG supply chain. Basically, the gas is treated to remove some of its impurities, such as corrosive sulphur, carbon dioxide and water, and then fed into a gas liquefaction unit known as a train. Most liquefaction facilities are made up of multiple trains.
Although it’s obviously on a much larger scale, the basic process of cooling natural gas isn’t much different than your home refrigerator or air conditioning system. The principle at work is that gases heat up when they’re compressed and cool down when pressures are released.
It’s not the natural gas itself that’s compressed and decompressed but a refrigerant gas such as propane. Therefore, LNG trains employ the use of a series of massive compressors and a wide variety of refrigerant gases. The exact process varies somewhat between projects.
After the gas is liquefied, it’s loaded onto specialized LNG tanker ships. These ships typically have large spherical storage tanks visible on the deck of the tanker. See the picture below for a closer look.
Source: Woodside Petroleum
These tank storage units are designed with multiple layers of insulation to keep the LNG cool during transport. Nonetheless, even with multiple layers of insulation, LNG cargo does warm up slightly during the course of the voyage–typically around 0.15 percent of the cargo boils each day. This is called boil-off gas.
If the boil-off gas was allowed to build up too much, pressure inside the tanks would increase. In modern LNG tankers, it’s actually removed from the storage tanks and used to help propel the tanker ship.
LNG tanks are never really fully emptied; a small quantity of so-called heel gas is retained. This gas helps to retain the LNG tanks at super-cooled temperatures during their journey back to pick up another load of LNG.
The final step in the LNG supply chain is the regasification terminal. These terminals are located in the importing country. Natural gas is reheated to more normal temperatures and then injected into the pipeline network to be used just like normal gas.
It’s important to note the difference between LNG and gas-to-liquids (GTL) technologies. LNG is just normal gas cooled into a liquid state and then regasified for use in exactly the same end-markets as gas carried entirely by traditional pipelines.
I explained GTL technology at some length in the April 12 issue of TES, Finding New Btus. This technology involves a series of chemical processes—the Fischer-Tropsch (FT) process–to actually convert gas into a diesel-like liquid fuel.
As you might expect, there are significant upfront capital costs involved with constructing an LNG supply chain, particularly for liquefaction facilities. That’s why producers typically secure long-term gas supply deals with customers for much of the output from their liquefaction facilities. This helps to ensure they’re able to garner an acceptable return on investment and a ready market for the gas.
Of course, there’s also a spot LNG market. An electric utility or industrial customer can arrange for a one-off specific amount of LNG delivery at a pre-determined competitive rate. The spot market accounts for between 10 to 15 percent of the global LNG trade right now, but spot transactions are becoming an ever-larger part of the LNG market.
LNG tanker ships can be owned by the gas producer, the gas importer or third-party tanker ship operators. In the latter case, operators charge a certain fee for the lease of their ships.
Unlike many crude oil and refined products tankers, these tanker rates are also secured by long-term contracts. Contracts to transport LNG from a particular liquefaction project are negotiated before the tanker company actually arranges for construction.
For example, Proven Reserves Portfolio holding Teekay LNG Partners (NYSE: TGP) leases all its ships on 15- to 20-year contracts that guarantee it a reasonable return. Typically, the company signs the contract long before the ships have left the shipyard. The company uses that stable contract base to justify and finance the cost of new tanker construction.
Back to In This Issue
Drivers for LNG Growth
In 2006, a total of about 31.3 trillion cubic feet of natural gas was traded across international borders. Pipelines still account for about 76 percent of that trade. But LNG trade now accounts for some 24 percent of global gas trade and 7.2 percent of gas consumption. Check out the chart below.Source: Oil & Gas Journal, EIA, BP Statistical Review or World Energy 2007
In this chart, I present natural gas international trade growth statistics for both the trailing 10-year period and for 2006.
I see two points worth noting from this chart. First, on a trailing 10-year basis, trade in natural gas across international borders has grown at nearly twice the pace of global gas production and consumption. In other words, international trade is becoming a more important part of the global gas supply picture.
And second, LNG trade is growing significantly faster than overall gas trade. Total global trade in natural gas has averaged about 5.4 percent annualized over the past decade but shrank to just 2.5 percent in 2006.
But last year’s drop-off in growth was due entirely to a slump in trade via pipelines for 2006. Growth in LNG trade has averaged nearly 8 percent annualized over the past decade and accelerated to a whopping 11.7 percent last year.
The major reasons for the growth in natural gas trade and LNG is that gas reserves near the big consuming markets have been depleted and production is falling. Imports of natural gas are, therefore, absolutely crucial to meet growing demand and fill the gap left by falling domestic output. Here’s a rundown of gas trade developments in the three prime centers of natural gas consumption worldwide:
North America
The US is far and away the biggest, single, gas-consuming nation in the world. Consider, for example, that the US consumes about 60 billion cubic feet of gas per day compared to just 42 billion for all the Asia-Pacific countries combined.
Nevertheless, up until the late 1980s, America was essentially energy self-sufficient when it came to natural gas. Check out the chart below.
Source: BP
This chart shows consumption and production of gas in the US. The gap between the consumption and production lines indicates the amount of natural gas the nation needs to import.
America’s import requirements began to ramp up in the ’90s, accelerating into the latter days of that decade. The reason is that the US built a huge amount of gas-fired power capacity in the ’90s.
Gas demand ramped up as utilities needed to supply all those new plants. Demand for gas to fire these plants grew far faster than production throughout the ’90s.
And another notable problem has emerged since 2000: US gas production has peaked. US gas production is no higher now than it was in the early ’90s. This isn’t due to any voluntary production restraint; it’s simply due to the maturation of gas reservoirs. The large gas fields that once supplied all the gas the US needed have now been in production for years, and output is slowing.
The best way to illustrate that US gas wells are mature and past peak production is to look at the two charts below in tandem: one of the active gas rig count and one of natural gas production.
Source: Bloomberg, Baker Hughes
Source: EIA
I used a monthly chart of natural gas production over the past few years to better illustrate the gradual, yet notable, decline in US gas production.
The active rig count is nothing more than a simple measure of how many rigs are actively drilling for natural gas in the US. As you can see, the rig count is currently near a multi-year high; the rig count has been accelerating in an almost uninterrupted fashion for the past few years.
The conclusion is simple: Producers are aggressively drilling more wells, bringing a record number of drilling rigs to bear. Yet despite all these new wells and new drilling activity, gas production isn’t growing. In fact, gas production is in decline.
To look at the same data in another way, consider that the average US gas well flowed some 185 million cubic feet per day in 1990; today, that figure is closer to 120 million cubic feet. US producers are targeting smaller, less prolific reserves.
In addition, they’re fighting rapid declines in gas production from older wells. US producers are drilling aggressively just to try to maintain current production.
All this adds up to an increasing need for the US to import natural gas. At first, transporting Canadian gas south through pipelines could easily satisfy the nation’s import requirements. Not surprising, US gas imports from Canada more than doubled from 1.43 trillion cubic feet per year in 1990 to 3.6 trillion cubic feet in 2002.
But Canadian gas imports aren’t sufficient to meet America’s needs any longer. The problem in Canada is much the same as in the US: Canada’s gas fields are also maturing, and production is in decline as well.
Moreover, Canadian gas demand has been rising at a faster pace than in the US in recent years. One big driver for that growth in demand is Canadian oil sands production.
Producing the oil sands requires the use of large amounts of steam. The primary energy source for producing all that heat and steam is natural gas. Therefore, plans to ramp up oil sands production in coming years spell inexorably rising demand for gas and less gas available for export to the US.
It should come as little surprise that US imports of LNG are set to rise sharply in the coming years. Check out the chart below for a closer look.
Source: EIA
As you can see from this chart, the EIA expects LNG to overtake pipeline imports from Canada as the No. 1 source of imported gas into the US by the middle of the coming decade. LNG imports are set to fill in the gaps left because of the decline in Canadian output.
And this isn’t just some pie-in-the-sky estimate by the EIA. The fact is that LNG imports are already having a meaningful impact on the US natural gas market.
The chart below shows actual LNG imports as a percentage of total imports from the first quarter of 2006 through the second quarter of 2007. I’ve also included short-term EIA estimates and preliminary data for the remainder of 2007 and the entirety of 2008.
Source: EIA
What’s clear from this chart is that imports of LNG surged in the first two quarters of 2007, accounting for more than 24 percent of total US natural gas imports.
The reason for the surge was twofold. First and foremost, US natural gas prices, though still significantly off their 2005 post-hurricane highs, were well above gas prices in Europe and Asia. LNG, like crude oil, can be sent to the markets where returns are most favorable; because the US had relatively high gas prices, the nation was able to attract the LNG imports.
Second, Canadian gas production looks troubled right now. Because of the slump in gas prices, the Canadian rig count has fallen sharply. Producers just aren’t drilling very aggressively.
Because Canadian gas wells have a rapid decline rate, Canadian production has begun to fall. Canada wasn’t able to export as much gas as normal in the first six months of 2007. Therefore, LNG helped to fill that supply gap.
The chart below shows that US LNG imports actually shot to record levels earlier this year.
Source: EIA
Since that time, the EIA estimates that LNG shipments have fallen back to more normal levels. The problem this time around is some shutdowns at Japanese nuclear power plants meant that Japan needed to import more gas. With returns for selling gas higher in Japan during the past few months, that nation has attracted LNG imports.
The US currently has five operating LNG regasification terminals: Everett, Mass.; Cove Point, Md.; Elba Island, Ga.; Lake Charles, La.; and one terminal in the Gulf of Mexico. Total throughput capacity of these facilities totals about 5.8 billion cubic feet per day.
I’m often asked about regulatory hurdles for new LNG developments. Although new LNG regasification operations often are the target of local opposition, there are a number of new facilities scheduled for construction in the next few years. This includes a large number in and around the Gulf Coast near existing energy infrastructure, where locals tend to be less likely to object to new terminals.
There are also plans to site several new gasification terminals in the Gulf of Mexico. This eliminates some of the permitting problems entirely.
It will take a few more years for these new terminals to be constructed and begin accepting shipments. But I see no reason that US regasification capacity will be insufficient to handle the sort of LNG imports required to meet natural gas demand.
The US LNG market is dominated by producers in the Atlantic basin. The chart below offers an overview of the main sources of US LNG so far in 2007.
Source: EIA
The cost of delivering LNG to the US markets depends on a number of factors, including the transport distance and the cost of production. For example, Qatar has among the lowest gas production costs of any country in the world. But because of its distance to the US, the EIA estimates that it costs $1.75 per million British thermal units (MMBtu) to transport LNG from Qatar to the US Gulf.
However, according to 2005 estimates from the EIA, all-in costs for delivering LNG range from about $2.67 to $6.86 per MMBtu. This isn’t much different that the production cost range for gas-focused exploration and production (E&P) firms in the US.
And despite the fact that LNG means additional gas supplies for the US, LNG also puts a sort of floor under gas prices. The US will need to be increasingly price competitive with other nations–including China and India–for spot LNG supplies. To attract marginal LNG imports, the US market will need to offer prices that either meet or exceed prices of gas elsewhere.
Bottom line: The US will need to drastically ramp up gas imports in the coming years, and much of that import demand will fall to LNG.
Europe
I won’t linger on this market because I offered a complete, detailed assessment of the European gas market in the June 20 issue of TES.
Suffice it to say that European gas demand is growing faster than gas demand in the US. And I’m not talking about just the Eastern European countries that are seeing the most rapid economic growth but the developed nations of Western Europe.
Between 2004 and 2030, OECD Europe’s total gas demand is projected to jump from 18.8 trillion cubic feet (tcf) to 26.9 tcf, a total increase of 43 percent. In OECD North America, demand will increase by only 16.5 percent over the same time period. See the chart below for a closer look.
Source: EIA
By far the largest contributor to that increase is the electric power sector. The EIA estimates that OECD Europe will burn more than 11.1 tcf of gas in power plants by 2030, up from 4.6 tcf in 2004. That’s growth of more than 140 percent.
During the same time period, the US electric power sector is only likely to see growth of 9 percent. Given that the EIA estimates that the US will only consume about 6 tcf annually of natural gas in power plants by 2030, it’s not hard to see how important Europe is becoming to the global natural gas market.
There are a few main drivers of that increased use. First up, as I noted above, the EU already has carbon-dioxide regulations in place. Gas is the most expedient way for a nation to reduce carbon-dioxide emissions; gas emits about 40 to 50 percent carbon than an equivalent-sized coal plant.
The second reason is much the same as for the US: Europe’s traditional domestic sources of gas are in decline. As I explain the June 20 issue, North Sea gas production has peaked even as gas demand surges necessitating more imports.
In fact, OECD Europe already imports about 40 percent of its natural gas requirements. By 2030, the EIA projects Europe’s import dependence will skyrocket to 65 percent of demand.
To finance its gas gap, the EU looks east to Russia. Russia is far and away the world’s largest producer of natural gas, and it’s estimated to have the world’s largest reserves of natural gas. Much of this gas moves by pipeline.
But it’s clear that Europe would prefer to diversify its gas import supply. That means investing in LNG regasification terminals.
The UK was actually the world’s first LNG importer; its first LNG cargo arrived back in 1964 from Algeria. But with the discovery of North Sea supplies, Britain became gas self-sufficient and the LNG terminal was closed.
But that process has now been thrown into reverse because of the decline in North Sea production. Britain now has an LNG terminal located in Kent that received its first shipments in 2005.
That terminal is being steadily expanded in size, and now there are two brand new terminals under construction in Wales along the nation’s western coast. There’s also an operating LNG terminal in southern Scotland.
Spain, Portugal, Belgium, Greece, Italy and France also have several existing LNG import terminals. In 2006, Spain and France were the largest two importers; Spain imported 24.4 billion cubic meters (bcm), and France imported 13.9 bcm of LNG.
Most of these nations also have early plans for additional terminals that would increase their ability to import gas. The chart below shows the source countries for most European LNG imports as of 2006.
Source: BP
It’s clear from this chart that Europe’s suppliers are much the same as for the US, though the percentages are somewhat different. The reason for that is obvious: Trinidad dominates US LNG imports because it’s so close to the mainland US, reducing transport costs. Similarly, North Africa’s proximity to the EU makes it an obvious source of LNG imports.
But the European and US markets are becoming more related. North Africa is increasing in importance as a source of US imports, and Trinidad certainly isn’t meaningless to Europe.
These two key gas-consuming regions are in competition. For example, LNG imports into the US slumped in 2005 and 2006 because gas prices were more attractive in the EU. LNG shipments could be diverted to these nations, where returns were higher.
Asia-Pacific
I outlined the basic outlook for the Asia-Pacific LNG markets in the Sept. 13 issue of The Energy Letter, Liquid Energy.
To summarize, Japan and South Korea are currently the world’s two largest importers of LNG, accounting for about 39 percent and 16 percent, respectively, of world trade. The reason is simply that these countries have only small, domestic reserves of hydrocarbons; both nations have been largely import dependent for decades.
Japan has no domestic natural gas production to speak of and relies on imports for substantially all of its 8.2 billion cubic feet (bcf) of daily consumption. Japan currently imports no natural gas by pipeline; all of that gas comes from LNG.
Australia, Malaysia and Indonesia are Japan’s largest sources of LNG imports. Because a good deal of Indonesian gas is set to be diverted to the fast-growing domestic market, Australia and Malaysia are likely to be the dominant sources of Japanese LNG imports in the coming years.
Japan is a developed country, but gas demand growth is relatively rapid. Japan’s gas consumption is expected to jump from 3 tcf per year in 2003 to more than 4.3 tcf by 2030. Just as with Europe, this is mainly a result of the need to cut back on carbon emissions. Much of that growth will likely continue to be met with LNG.
South Korea is much the same story. Gas demand totals 3.3 bcf per day; most of that demand is satisfied with LNG imports.
Oman, Qatar and Malaysia are the three largest sources of South Korean LNG. South Korean gas demand is expected to increase by 67 percent in the coming 23 years, a bit faster growth than in Japan.
Although Japan and South Korea dominate current trade in LNG and are showing slow-but-steady growth in imports, the real sizzle is found in the non-OECD Asian nations. The dominant growth drivers here are, as you might expect, China and India. Check out the EIA’s forecasts for Chinese and Indian demand and supply for gas in the chart below.
Source: EIA International Energy Outlook 2007
Currently, the China and India gas markets are essentially in balance. Production is nearly enough to satisfy demand. But because of the rapid growth in demand for gas, this gap will grow to a staggering 4.1 tcf annually by 2030.
Therefore, these markets will be importing every bit as much gas as Japan by 2030. Although some of this demand is likely to be settled by pipeline imports from markets like Russia and Iran, LNG will play a prominent role.
Already, China and India are players in the LNG market. China received its first shipment of LNG in fall 2006. The country imported about 1 billion cubic meters (35 bcf) of LNG for 2006.
India actually imported far more, a total of 8 billion cubic meters (282 bcf). Australia accounted for all of China’s LNG imports, while Qatar was the dominant player in the India gas market.
More broad, Asian Pacific’s growing demand for LNG will likely be met via exports from other Asia-Pacific nations as well as from the Middle East. Qatar overtook Indonesia this year as the world’s largest producer of LNG. Although transport costs from Qatar to Asia are higher than from Indonesia, Qatar’s massive North gas field offers some of the lowest production costs in the world.
I expect Qatar to remain a key supplier.
Indonesia will remain a big supplier, but it’s in decline. The country’s Tangguh LNG project still hasn’t fully started up; this will be a new push for Indonesian production.
However, the two country’s existing LNG projects went into production from 1978-86 and are now showing steady production declines. In addition, Indonesia gas consumption growth is booming, so more gas will be diverted to domestic uses over time. Nevertheless, Indonesia will remain a key global exporter for the foreseeable future.
Malaysia will also remain a big player in Asian LNG. The country has three LNG liquefaction facilities and has taken steps to expand production from each. However, any plans for further plants are currently on hold.
Perhaps the most interesting LNG supplier of all from an investment standpoint, however, is Australia. The nation is politically stable, and unlike many other resource-rich countries, the government has been fair and transparent in its treatment of resource access and taxation.
As a result, Australia has benefited from a massive increase in investment on the part of global energy firms. For a closer look, check out the chart below.
Source: EIA
Australia’s natural gas production is set to increase at an annualized pace of 4.3 percent out to 2030. This is the fastest production growth projected for any country, anywhere in the world. The vast majority of that gas will be exported. In fact, Australia alone accounts for all the gas production growth forecast for the developed world out to 2030.
The country has two operating LNG projects: Darwin LNG and North West Shelf. The majority owner of Darwin is ConocoPhillips; the liquefaction plant made its first sale in February of last year.
Currently, this facility can produce about 3.5 million metric tons (3.9 million short tons) of natural gas per year. All that production is being sold to Japan under a 17-year agreement. It’s possible that the facility could be expanded to roughly triple its current size with existing permits, though that would require piping in gas from other fields.
The North West Shelf (NWS) project has been in operation since the late ’80s, though it’s been expanded significantly since that time. This facility is owned by a consortium of six major integrated oil companies, with Australia’s Woodside Petroleum (Australia: WPL, OTC: WOPEY) as the operator.
Located in Western Australia, NWS produces around 11.5 million metric tons of LNG per year. Although the project’s biggest customer is Japan, China’s only LNG imports in 2006 came from the NWS project.
But there are several huge LNG projects planned in the next few years. Specifically, Gorgon LNG—majority owned by Proven Reserves Portfolio bellwether Chevron Corp–is scheduled for completion in 2010. This facility would have a capacity of about 10 million metric tons of LNG per year.
Woodside Petroleum has two additional facilities, Withnell Bay and Burrup Peninsula. The former is scheduled for completion next year and will produce about 4.4 million metric tons of gas. The latter will be completed in 2010 and will produce in the 4.3 million to 4.8 million metric ton range.
With all these new LNG projects coming on stream, Australia looks like it’s in a good position to continue to be a dominant player in Asian LNG.
Back to In This Issue
How to Play It
We already have some significant exposure to growth in LNG inside the TES portfolios. In addition, in this issue, I’m adding Chart Industries (NSDQ: GTLS) to the Gushers Portfolio as a new buy recommendation and several new names to my coverage universe. Here’s a rundown:BG Group (London: BG/, OTC: BRGYY)–Wildcatter BG Group is a top-notch play on the Atlantic Basin LNG trade. The company operates in the LNG business at every conceivable level, from production to regasification and marketing.
BG has four basic business units. Ranked by importance in terms of operating profits, these units are: E&P, LNG, transmission and distribution, and power generation. E&P and LNG are far and away BG’s most important business units. Buy BG Group up to 90.
Dresser-Rand (NYSE: DRC)–Wildcatter Dresser-Rand has been among the best-performing picks in the Wildcatters Portfolio during the past year. I’ve profiled the stock on several occasions, including the Nov. 22, 2006, issue, “Leading Income,” and the Oct. 5 flash alert, “Buying the Dip.”
Dresser makes compressors and turbines used in a variety of energy-related applications; energy-related fields make up about 93 percent of Dresser’s business. Among its more important end markets are floating production storage and offloading ships–basically floating oil and gas production platforms used in offshore field developments. And compressors are also used heavily in refining operations, especially operations related to the processing of heavy and sour crude oils.
But as I noted above, LNG liquefaction terminals also use compression equipment. Dresser’s management believes this is as much as a $100-million-per-year opportunity for the company. Buy Dresser-Rand below 40.50.
Teekay LNG Partners (NYSE: TGP)–Teekay LNG Partners is a master limited partnership (MLP) that owns a fleet of LNG tanker ships. All of these ships are leased under long-term arrangements—typically 15 to 20 years–to major LNG projects, including new LNG developments in Qatar and Indonesia. These contracts provide for a fixed rate plus an adjustment to account for cost inflation.
In the second quarter, Teekay LNG hiked its quarterly distribution to 53 cents per unit (MLP lingo for share), equivalent to a yield of about 6.7 percent. That represents a 15 percent jump over its prior quarterly payout of 46.25 cents per unit.
The reason that Teekay LNG increased its dividend is that the company accepted delivery of new tanker ships. As soon as the ships were delivered, the company put them out on pre-negotiated long-term contracts.
As the cash from these contracts started to hit the bottom line, Teekay was able to boost its payout. I calculate that the company’s second quarter payout amounted to just 86 percent of the actual distributable cash flow earned during the quarter. That’s healthy coverage for an MLP.
Teekay has several new LNG ships scheduled for delivery over the next few years. This opens up the possibility for further bumps to the distributions as these ships start earnings revenues.
In fact, Teekay LNG should be able to sustain distribution growth in the 10 to 15 percent annualized range over the next three years. That would put its quarterly payout at about 75 cents in three year’s time. That would equate to a yield of 9.5 percent at current prices. Teekay LNG Partners is a buy under 40.
For more on why I believe Teekay and the other MLPs have seen a pullback of late, check out the Oct. 3 issue, The Partnerships.
Chart Industries (NSDQ: GTLS)–Chart Industries manufactures and sells a variety of cryogenic equipment and engineered parts. Chart manufactures these products for a variety of industries, including energy and medical.
However, roughly 56 percent of 2006 revenues came from energy-related businesses and nearly 80 percent of the company’s backlog is related to energy. Therefore, Chart is becoming an ever-purer play on the energy business.
One of the company’s primary growth markets in recent years has been LNG. For example, Chart makes advanced heat exchangers, used in both the LNG and gas processing markets.
In the LNG market, heat exchangers are used during the liquefaction process. Gas typically goes through multiple stages of refrigeration, and heat exchangers are used at each step.
As for processing, natural gas is composed mainly of methane but also includes other hydrocarbons such as propane and gases such as carbon dioxide. To separate these gases, processors can rely on their different cooling and boiling points. This process also requires the use of heat exchangers.
Chart also sells these products into the industrial gases business. Major customers include firms such as Air Products & Chemicals and Praxair. Although that may not sound like the company is energy-related, think again.
Hydrogen gas produced by companies like Air Products and Praxair is used to remove sulphur from crude oil. Industrial gas manufacturers have seen huge growth in sales for refiners in recent years.
And one way to improve the fuel efficiency of many industrial processes—such as steel production—is to boost the oxygen content of the air. This can also reduce emissions of everything from sulphur to carbon dioxide. This fact has been benefiting the industrial gas business as well.
In addition to heat exchangers, Chart also makes vacuum-insulated LNG pipes–pipes that are specially sealed and insulated to allow for the transport of super-cooled LNG. Clearly, if you transported LNG through a normal pipe, you’d not only damage the pipe but also allow the LNG to heat up and boil off. The pipes Chart makes are highly specialized.
In Chart’s second quarter, the company’s backlog of unfilled orders in the energy and chemical business rose to more than $58 million. Better still, the company is in the final few quarters of clearing some older legacy contracts that don’t offer the company as high a profit margin as it gets newer business. As these older contracts roll off the books, management expects profit margins to continue improving.
The equipment markets can be lumpy because of the timing of large orders. This can create some volatility in related stocks.
This is especially true for smaller firms such as Chart. But the company’s enviable position in a fast-growing market makes it worth the risk. Chart Industries is added to the aggressive Gushers Portfolio as a buy under 35.
Woodside Petroleum (Australia: WPL, OTC: WOPEY)–Woodside is Australia’s largest pure-play E&P company. Woodside has properties in various stages of production in the US, deepwater Gulf of Mexico, Australia and Africa. The company is a particularly important player in the Australian LNG market.
Woodside is one of the six owner/participants in Australia’s North West Shelf venture. The company is also the official operator of the entire LNG operation.
In the most recent quarter, that venture produced 33,701 metric tons of LNG; Woodside’s share of that production totaled more than 5,315 tons per day, a pace of nearly 2 million tons per year.
The company is currently expanding the NWS venture to include a fifth train. This $2.4 billion project should come on line and begin producing LNG for shipment by the end of next year. Total capacity for the fifth train will be 4.4 million metric tons per year, making it the largest train at the project.
Woodside also received approval for its new Pluto LNG project on the Burrup Peninsula in late July. Woodside has already negotiated the sale of 3.75 million metric tons of LNG per year to Japanese utilities under a long-term supply deal. Total output from this project should be approximately 4.5 metric tons per annum, all from a single train.
Shell, also a big global player in LNG, owns a roughly one-third stake in Woodside. That’s a sign of confidence in Woodside’s general strategy. I’m adding Woodside Petroleum to the How They Rate coverage universe as a buy recommendation.
Saipem (Italy: SPM, OTC: SAPMF)—Italy-based Saipem began as a wholly owned subsidiary of Italian oil giant Eni. But the firm was spun off as a separate company back in 1984; Eni still holds a 43 percent stake.
Saipem’s business is divided into three pieces: offshore, onshore and drilling. The offshore business includes installing offshore oil and gas platforms, laying subsea pipelines, and various other construction and large-scale engineering projects.
The offshore business is attractive due to its international focus and leverage to the hottest oil and gas markets. The large international projects that Saipem works on aren’t particularly sensitive to commodity prices; these are multi-year deals run by major integrated oils and national oil companies.
And Saipem also has significant leverage to deepwater field developments, one of the fastest-growing markets in the energy patch. Offshore revenues jumped 20 percent in the first half of 2007, and Saipem’s backlog of projects continues to grow for this unit, totaling more than EUR4.3 billion ($6.15 billion).
Saipem’s onshore business has significant leverage to LNG. The company constructs liquefaction trains and regasification facilities. Saipem has built nine liquefaction trains in Nigeria and Qatar in the past 10 years.
In addition to trains, Saipm also constructs and designs pipelines, storage facilities and other related oil and gas infrastructure. Revenues in the onshore business exploded 95 percent in the first half of this year.
Saipem is a solid, all-around play on strong energy growth themes, including LNG, deepwater development, energy infrastructure and international project development. I’m adding Saipem to the How They Rate coverage universe as a buy recommendation.
Back to In This Issue