America’s Gas Growth

The US imports more than 13.5 million barrels of crude oil each day, roughly 210 billion gallons per year. That’s equivalent to a quarter of total global trade in crude. Although America depends on imports to meet oil demand, that’s certainly not true of all energy commodities.

Most investors are aware that the US is home to the world’s largest coal reserves; in fact, the nation is increasingly becoming a key exporter of coal to Europe and Asia.

However, many are surprised to learn that the US ranks second only to Russia in natural gas production. In addition, thanks to strong growth from a handful of world-class unconventional gas fields, the US is the world’s fastest-growing producer and stands a good chance of overtaking Russia within five years. 

LNG Trade

Just three years ago, the country faced a very different picture. Back then, conventional wisdom held that US natural gas production had peaked and would soon begin to decline. At the same time, Canada’s natural gas production was also hitting a wall and, due to increased domestic demand, Canada would soon have to scale back natural gas exports to the US.

That would leave the US with only one option: import more gas in the form of liquefied natural gas (LNG). 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 ping pong 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.

As recently as last year, the US Energy Information Administration (EIA) projected that US LNG imports would soar from less than a billion cubic feet per day (bcf/d) in 2006 to more than 4.5 bcf/day by 2030.

Source: EIA Annual Energy Outlook 2007

In response to these expectations, firms have built significant LNG regasification capacity to handle all of that projected demand. In total, there are currently eight operating LNG terminals in the US and two in Mexico that are designed, at least partly, to serve US markets. The total import capacity totals almost 11 bcf/d. And there are still proposals on the table for an additional 12 terminals. But there’s a big problem: The demand for LNG imports that many projected just isn’t there.

Consider that unlike crude oil, natural gas trades at very different prices in different parts of the world. For example, at this time, US natural gas prices are less than half what they are in Europe and Asia.

The reason for this is simple. Only a handful of countries have LNG liquefaction capacity; many more have the ability to only import LNG.

If crude oil prices are lower in the US than Europe, producers could put oil on a tanker and ship it to Europe to take advantage of the pricing differential. But because the US only has one LNG liquefaction terminal (in Alaska) this is essentially impossible when it comes to natural gas. That is why gas prices in Europe have remained more than twice the US price for several months—there’s no way to arbitrage that gap.

But there is an impact on US LNG market. Companies with available LNG cargoes are not sending those shipments to the US. Instead, they’re exporting LNG to the EU and Asia where prices are far higher. The result: According to the EIA, US LNG imports have collapsed from more than 2.1 bcf/d in 2007 to less than 1 bcf/d this year. Check out the chart below for a closer look.

Source: Bloomberg

This chart compares US-traded natural gas prices to gas prices in the UK. Although the EIA projects a slight uptick in LNG imports into the US next year, that looks like wishful thinking. With such a wide gap in prices, only minimal LNG will find its way into the US for the foreseeable future.

Unconventional Change

As I noted in my last article for New World 3.0, “Oil 3.0” the big shift in the US natural gas supply picture is a direct result of growth in unconventional natural gas reserves.

Unconventional fields are nothing more than reservoirs that can’t be produced economically using traditional oilfield techniques. But the development and widespread acceptance of three-dimensional (3D) seismic mapping, hydraulic fracturing and horizontal drilling enable unconventional production. I explained all three of these technologies in “Oil 3.0.”

Rapid growth in production from unconventional fields has driven a near 8 percent jump in US gas production year-over-year. The granddaddy of all unconventional gas fields in the US is the Barnett Shale located in north-central Texas.

The Barnett has been under production to some extent since the early 1980s; however, the pace of that development has clearly accelerated over the past few years. The chart below offers a closer look.

Source: Texas Railroad Commission

According to the Texas Railroad Commission (TRC), there are now more than 7,770 wells drilled in the Barnett Shale region of Texas and 3,679 drilling permits were issued in 2007 alone. In fact, in just the period from January through May of this year, the TRC issued 1,669 drilling permits; on an annualized basis, that works out to more than 4,000 permits for 2008. This compares to just 1,112 permits issued in 2002.

All that drilling activity is obviously bearing fruit. The chart above shows that production from the Barnett has ballooned from 28 bcf in 1997 to nearly 1.1 trillion cubic feet (tcf) last year. That’s a jump of nearly 40 times in just a decade. For the record, the TRC also estimates 345 bcf of production in the first quarter of this year; annualized that’s about 1.4 tcf or 3.85 bcf/d.

But the Barnett is only the beginning. In recent years, US producers have announced the discovery and development of several major unconventional shale gas plays in the US and Canada. The list includes, the Marcellus Shale found in Appalachia and the Haynesville Shale of Louisiana that could contain 5 times more gas than the Barnett.

These shale plays are truly world-class reserves.  This is obvious from the fact that global oil giant BP (NYSE: BP) has agreed to buy a stake in some shale acreage owned by America’s largest gas producer, Chesapeake Energy (NYSE: CHK). When the major integrated oil companies are investing in a region, you can bet it’s not an insignificant play.

Strong growth in North American unconventional gas production has totally shifted the consensus on the North American gas market. One of the main factors contributing to the decline in US gas prices over the past three months has been fears of a US gas glut; unconventional production growth is so strong North America now has a surplus of gas.

In fact, several US producers have now scaled back their drilling plans to prevent such a glut of gas from developing.  For example, Chesapeake has decided to take what amounts to two steps. The first is to shut in roughly 125 to 150 million cubic feet (MMcf) of gas production in Oklahoma.

This really isn’t a totally new move for Chesapeake. The firm has shut-in production in the region temporarily before. It’s one of Chesapeake’s more marginal plays. And if gas prices rise back over the $10 per million British thermal units (MMBtu) mark for some period of time, Chesapeake can always restart this production relatively quickly.

In addition, Chesapeake is cutting its capital spending plans by about 17 percent (USD3.2 billion) between the second half of 2008 and the end of 2010. Of this total, USD1.9 billion is a direct reduction in drilling activity; the remaining total is simply a reflection of recent deals Chesapeake has closed to sell off stakes in some of its plays and operate certain wells as joint ventures.

Even more amazing, producers are now talking about the potential to develop new sources of gas demand to help offset production growth. The top two contenders in this regard: compressed natural gas (CNG) and LNG liquefaction capacity.

CNG is just natural gas that’s used to power vehicles as replacement for conventional gasoline. At current prices, CNG would trade at about half the price of conventional gasoline. It produces more than 80 percent lower emissions of pollutants like sulphur dioxide, nitrous oxides and particulate matter. CNG also looks like a viable alternative in light of carbon dioxide (CO2) regulations being imposed around the world; CNG emits about half the carbon of conventional gasoline.

Despite these advantages, I seriously doubt you’ll see widespread use of CNG in passenger cars for at least five years. Building out the stations and infrastructure needed to support passenger cars running on CNG is a daunting task. However, CNG proponents such as T. Boone Pickens really aren’t focusing their attention on the passenger car market near term but on long-haul trucks (18-wheelers) and fleet vehicles such as buses and taxis. Building out infrastructure to support these commercial markets would be far easier. This would also be a huge source of additional demand for gas produced in the US.

Another leading possibility is an LNG liquefaction terminal. Such a facility would allow US gas to be converted into LNG and shipped overseas to take advantage of much higher prices abroad. EU countries are currently extremely dependant on imported gas that’s primarily sourced from Russia. Although Russia will remain a key supplier, some nations are building out LNG import capacity in an effort to diversify supply sources; US LNG shipments would prove an attractive option.

Building an export terminal is expensive, and permitting such a facility would face issues especially from the normal “Not in My Backyard” (NIMBY) crowd. However, Chesapeake pointed out there are already plans to build a liquefaction plant in Canada; US gas exports could be handled through that facility. In addition, permitting a plant just across the border in Mexico might be easier.

Chesapeake suggested that it’s pursuing this option seriously. It’s hard to handicap the odds of an LNG export terminal in the US, but the longer overseas prices remain elevated, the more likely such a deal will be announced. This, too, would be a key source of demand for US producers.

How to Play the Change

Outside the US, the LNG market will continue to grow. The EU is a huge importer of natural gas; the region produces 18.6 bcf/d and consumed close to 47 bcf/d. And I suspect that import dependence is only going to grow in coming years as the region isn’t blessed with the massive unconventional reserves that the US has been able to exploit.

One advantage of natural gas over other fossil fuels is that it’s cleaner. In particular, burning natural gas emits about half the carbon of burning coal. The EU already regulates carbon emissions; therefore, EU countries have rapidly ramped up their consumption of gas in an effort to cut emissions of CO2.

While most gas imported into the EU comes from Russia, countries across the Continent are seeking to build LNG import terminals to diversify supplies.

Meanwhile, Asia is a fast-growing LNG market. There are several large LNG liquefaction projects underway in Australia aimed primarily at supplying Asia’s needs. And it’s likely that large quantities of LNG from the Middle East will also find their way into fast-growing Asian markets.

One of the world’s leading players in LNG is Britain’s BG Group (London: BG; OTC: BRGYY). BG is involved in all aspects of LNG supply including production and liquefaction of gas, LNG transport and import capacity. In fact, the company dominates the Atlantic Basin trade in LNG.

BG owns liquefaction capacity in Egypt, Trinidad and Tobago. In Egypt, the company has access to two LNG trains. The first delivers roughly 3.6 million metric tons per annum under a long-term supply deal with Gaz de France (OTC: GZFCF). The company purchases LNG from the second train for sale all over the world.

And in Trinidad and Tobago BG is a shareholder in four LNG trains; most of the production from these trains has traditionally been sold into the US. That said, BG does have some flexibility to divert those cargoes to other markets to realize higher prices.

In addition, the company has plans for potential liquefaction plants in Nigeria and Australia. In Nigeria, BG currently purchases LNG and ships it abroad for resale. However, the company signed a deal in 2007 to produce four LNG liquefaction trains in Nigeria capable of liquefying 5.5 million metric tons of LNG per annum each. BG owns a 14.25 stake in this project with the Nigerian national oil company; Royal Dutch Shell (NYSE: RDS.B) and Chevron (NYSE: CVX) are also partners in the deal.

Finally, this year BG inked a deal with the Queensland Gas Company (Australia: QGC, OTC: QGSCF) in Australia to develop gas reserves in onshore Queensland and consider the potential for a 3 million to 4 million metric ton per annum liquefaction facility. The primary destination for those cargoes would likely be Asia.

BG owns two regasification plants in the US that haven’t seen much business this year thanks to depressed US gas prices. But the company has the flexibility to send its LNG to other markets where prices are far more attractive; for example, last year, the firm supplied 50 percent of Atlantic basin LNG volumes into the Asian markets. And the company also sells extensively to markets in Europe and South America.

And BG is more than just a pure-play on LNG. The company also has a thriving exploration and production (E&P) business. In addition to other promising fields, BG owns a stake in some of Brazil’s recent massive deepwater discoveries including the Tupi field. Buy BG Group under USD110.

For a play on the growth in US unconventional production, consider E&P firms with a solid acreage position in America’s most promising shale plays.

One example would be EOG Resources (NYSE: EOG), outlined at length in “Oil 3.0.” For a pure-play unconventional gas producer, Chesapeake Energy is tough to beat.

The company is the third-largest natural gas producer in the Barnett Shale of Texas. Chesapeake’s production for the Barnett stood at 466 million cubic feet per day (MMcf/d) at the end of the second quarter, up 126 percent over the same quarter one year ago and up 13 percent from the first quarter. By the end of 2008, Chesapeake expects production of at least 675 MMcf/d. That’s about a 45 percent jump in production over current levels.

In addition to the Barnett, Chesapeake has acreage in the Marcellus Shale of Appalachia, the Fayetteville Shale of Arkansas and, most importantly, the red-hot Haynesville Shale of Louisiana.

The Fayetteville is the most advanced of these three plays. In 2008 alone, its estimated 1,000 wells will be drilled in the Fayetteville region. The play is part of a larger gas-producing region known as the Arkoma Basin; in addition to unconventional shale wells, parts of this basin are amenable to conventional production techniques.

Industry participants suggest that current production from the Fayetteville Shale stands at roughly 750 MMcf/d. Chesapeake estimates that this play can grow 300 MMcf/d to 400 MMcf/d each year for the next few years. This would put the Fayetteville shale at about 1.5 bcf/d of production by 2011. This is significant growth.

Chesapeake has 415,000 acres leased in the core of the Fayetteville Shale and estimates that it could ultimately drill more than 5,200 wells. Currently, the firm produces about 135 MMcf/d and should see that grow to 180 million cubic feet by year’s end.

Chesapeake also sold a 25 percent stake in its Fayetteville projects as part of a joint venture with oil giant BP. In exchange for that stake, Chesapeake received USD1.1 billion in cash and USD800 million towards its Fayetteville drilling program.

Of Chesapeake’s two remaining plays, the Haynesville is likely is most promising. The company has the largest acreage position of any E&P firm in the core of this play. While production is still limited, Chesapeake has drilled some impressive wells in the region.  In fact, while the company recently stated that it’s planning to scale back some drilling operations elsewhere, Chesapeake has maintained an aggressive expansion plan for Haynesville. Buy Chesapeake Energy under $35.

And don’t forget gas infrastructure, the pipelines and processing facilities needed to process and move gas from wellhead to market.

One major problem for gas producers is that natural gas tends to trade at very different prices in different parts of the US. For example, current NYMEX natural gas futures prices are trading in the USD7 to USD8 per MMBtu range. However, Chesapeake noted that in some parts of the US, the company is receiving just USD3 to USD4 per MMBtu; at those prices, most producers are unprofitable.

Right now, for example, gas at the Opal Hub in Wyoming gas is trading at USD3.33 per MMBtu, less than half the current Henry Hub price. Meanwhile, New York gas trades at a premium to Henry Hub.

The reason has to do with infrastructure. Opal is located in the Rockies, and there’s extremely limited capacity to store gas in this region. In addition, there just aren’t enough pipelines in the area that can carry large quantities of gas east to markets like Henry Hub.

Kinder Morgan Energy Partners (NYSE: KMP) is a major player in the US natural gas infrastructure market. Kinder’s biggest recent project is the so-called Rockies Express (REX) pipeline that’s designed to carry gas from the infrastructure-starved Rockies east as far as the Pennsylvania-Ohio border.

The western portion of REX is already complete and ramping up to full capacity; Kinder even has plans to expand that capacity given high demand. As you can imagine, producers in the Rockies are anxious to move gas east and realize USD7 to USD8 per MMBtu rather than dumping their gas for USD3 per MMBtu.

By year’s end, the eastern segment of the pipe is scheduled for completion, although it will take considerable time for the pipeline’s throughput to ramp up to full capacity. After that, Kinder is evaluating proposals to extend the pipeline all the way to New York.

In addition to REX, Kinder also has a major pipeline dubbed the Midcontinent Express that extends from Oklahoma across northern Texas and Louisiana, eventually terminating in Mississippi. The pipeline passes through or near some of the hottest unconventional plays in the US including Barnett and Haynesville. While that pipeline was originally designed to carry 1.5 bcf/d of gas, Kinder is already looking to boost capacity to 1.8 bcf/d. With a solid 7.5 percent yield, Kinder Morgan Energy Partners rates a buy under USD60.

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