Despite fears about a US recession, a hard landing for China’s economy and the EU sovereign-debt crisis escalating into a global credit crunch, the price of most oil varietals have remained stubbornly elevated. This resilience reflects tight supply-demand conditions in the global oil market.  

Source: Bloomberg

West Texas Intermediate (WTI) crude oil remains a deeply flawed benchmark of oil prices and global supply and demand conditions. WTI underpins the crude oil futures that trade on the New York Mercantile Exchange and has been the most widely watched benchmark for North American oil price for decades. Innumerable media outlets in the US and Europe still quote WTI prices as the price of oil.

This inordinate focus on WTI made sense at one time. The US has been the world’s largest oil consumer for more than a century; market conditions stateside had long served as a reasonable gauge of global supply and demand conditions. Moreover, as you can see in the graph, the price of WTI and other benchmarks of light, sweet crude oil prices have tracked each other closely in the past. Brent crude oil, a widely referenced international benchmark, historically has traded at a slight discount to WTI because this varietal of oil is of slightly inferior quality.

As I’ve noted on several occasions, this relationship has deteriorated to the point that a barrel of Brent crude oil in early September went for roughly $30 more than a barrel of WTI–a whopping 35 percent premium.

Despite its storied history as the go-to oil price, WTI clearly doesn’t reflect supply-demand conditions in the global oil market. Most international benchmarks for heavy, sour crude oil even command a premium to WTI; for example, Mexico’s Maya currently fetches about a $14 per barrel premium to WTI, compared to the heavy, sour varietal’s normal discount of $5 to $15 per barrel.

This anomalous relationship remains in force, though WTI has closed the gap slightly after rallying from its September low a bit faster than Brent crude oil.

Brent crude oil, which tells us everything we need to know about the supply-demand balance in global oil markets, trades at roughly $113 per barrel—up from $94 per barrel at the end of 2010 and about $80 per barrel 12 months ago. (WTI crude oil, which tells us everything we need to know about supply and demand conditions in Cushing, Okla., is roughly flat on a year-over-year basis.)  

Readers often ask me why oil prices have rallied roughly 30 percent from year-ago levels amid concerns about weakness in the global economy and the threat of a global credit crunch.

At these levels, oil prices suggest that the odds of a recession or credit crisis are rather low. Meanwhile, equities markets have discounted a substantial economic downturn. Both markets can’t be correct: Either stock prices are too pessimistic about economic conditions, or oil prices are too optimistic. We continue to believe that the former is true.

In This Issue

The Stories

1. Despite the summer swoon and concerns about the EU sovereign-debt crisis, a tight supply-demand balance has kept oil prices elevated. Demand for this vital resource should continue to grow into 2012. See Crude Realities: The Demand Side.

2. Incremental growth in oil production is hard–and expensive–to come by. As OPEC’s spare productive capacity diminishes, expect oil prices to head higher. See Crude Realities: The Supply Side.

3. We remain bearish on US natural gas prices in the near term, but rising demand for liquefied natural gas and near-term capacity constraints should keep LNG prices elevated through 2013, The post-2014 outlook is a bit more uncertain. See Natural Gas: Staying Liquid Pays Off.

4. Not sure which Portfolio holdings you should buy now? Check out the Fresh Money Buys.

The Stocks

EOG Resources (NYSE: EOG)–Buy <125
Cheniere Energy Partners LP (AMEX: CQP)–SELL in Energy Watch List
BG Group (LSE: BG, OTC: BRGYY)–Buy < GBp1,650
Oil Search (ASX: OSH, OTC: OISHY)–Buy < AUD8
Weatherford International (NYSE: WFT)–Buy < 28
Schlumberger (NYSE: SLB)–Buy < 100
Baker Hughes (NYSE: BHI)–Buy < 60

Crude Realities: The Demand Side

Crude oil prices remain elevated because of a tight supply-demand balance. Let’s start with the demand side of the equation.

Some investors still ask me why oil prices remain high even though demand is weak. This question assumes that sluggish growth in the US and other developed economies necessarily vitiates oil demand.  

In 2010 the world consumed about 88.2 million barrels of oil per day–2.7 million barrels per day more than in 2009. Whether you look at the incremental increase in demand or the percentage gain, oil demand in 2010 increased at the second-fastest pace in 30 years. Much of this rebound stemmed from the snap-back in consumption that followed the severe 2008-09 recession. But the magnitude of this recovery took many analysts and industry participants by surprise.   

Investors should also remember that although US oil demand remains well under its 2004-05 high, global oil demand hit a new peak in 2010. Demand growth in 2011 won’t match up with last year’s resurgence. However, the International Energy Agency’s (IEA) forecast still calls for global oil demand to grow by more than 1 million barrels per day to 89.3 barrels per day. This uptick in consumption hardly qualifies as weak; oil demand has grown at an average annual rate of 1.05 million barrels per day since 1990.

The IEA has raised its estimate of 2011 crude oil demand sharply higher since July 2010. Although the agency has trimmed its projection by about 300,000 barrels per day since August, these estimates remain far higher than they were six months ago.

Source: International Energy Agency

The IEA first published its estimate of 2012 global oil demand in July and has steadily reduced this projection by roughly 500,000 barrels per day. Even with these revisions, global oil demand is expected to expand by 1.3 million barrels per day. If this scenario pans out, global oil demand would exceed 90 million barrels per day for the first time in history.

Of course, accurately forecasting global oil demand is at best an inexact science that inherently entails multiple revisions. Signs of economic weakness in the US and emerging markets have prompted IEA economists to lower their estimates of 2011 and 2012 oil demand.

Oil prices also factor into the IEA’s revisions. When oil prices are elevated, demand growth invariably slows.

While researching and planning each issue of The Energy Strategist, I examine market and economic trends to see whether my outlook for oil prices still holds.

Since the US and other developed economies hit a soft patch in spring, the risk to global economic growth skewed to the downside. At the same time, oil prices remained elevated. These factors prompted me to call for crude oil prices to drop from sky-high levels in the April 7, 2011, issue:

Recent developments [unrest in the Middle East and North Africa] suggest that oil prices will easily average more than $100 per barrel in 2011. Investors also shouldn’t rule out a move to $140 per barrel at some point this year–a price point I had expected in 2012. I see a 50-50 chance that oil breaches $140 per barrel in 2011. As before, Brent crude oil will lead any rallies; WTI should continue to trade at a discount to Brent for the foreseeable future. But don’t expect Brent crude oil to remain above $120 per barrel for a prolonged period, as demand growth would suffer.

Contrary to popular belief, sky-high oil prices aren’t welcome news for energy producers, oil services companies and other stocks in the energy patch. Although profits may jump in the short term, inordinately high oil prices tend to erode global demand and set the stage for a correction. Producers would prefer that oil prices hover around $100 per barrel, a sustainable level that generates solid profits and encourages drilling activity. Fears of demand destruction are one of the main reasons energy stocks fall or rally only slightly when oil prices jump.

This view has largely proved correct. Brent crude oil topped out near $130 per barrel and WTI had continued to trade at a historically high discount to its counterparts. The price of Brent crude also pulled back over the summer, though the benchmark never breached $100 per barrel. Oil prices should average north of $100 per barrel this year.

Don’t expect another run-up in Brent crude oil prices this year: Economic growth remains sluggish in developed nations, and oil prices are still high enough to generate some meaningful demand destruction.

By the same token, I don’t foresee much additional downside for oil prices in early 2012 because economic risks have receded. In fact, US gross domestic product likely grew at the fastest pace in the third quarter since the second half of 2010.

China’s economic growth has decelerated to a 9.1 percent annualized pace, a sustainable rate which suggests that policymakers successfully curbed speculation and inflationary pressures. Look for Beijing to stop tightening monetary policy and to start taking steps to promote growth by early 2012.

Although the Europe’s ongoing sovereign-debt crisis remains a threat, EU policymakers appear ready to take some decisive steps that should prevent the debacle from erupting into a 2008-style credit crunch.

Now that we’ve gotten the view from 10,000 feet, let’s examine the outlook for oil demand in two key regions: the Americas and the emerging markets.

Source: International Energy Agency

The Americas

Although the financial media agonizes over every data point related to the US economy, the entire Americas–the US, Canada and Latin America–are expected to consume about 100,000 barrels per day more oil in 2012. That works out to roughly 7 percent of the IEA’s forecast for oil demand growth.

A US recession poses the biggest threat to oil demand in the Americas; the US accounts for about two-thirds of oil consumption in the region. The risk of a US recession always remains elevated in a slow-growth environment, but my Recession Radar indicates that the risk of the US economy contracting over the next 12 months is roughly 25 percent. At one point this summer, my proprietary model indicated there was a greater than 40 percent chance of the US lapsing into recession.

Source: Bloomberg

The Citigroup US Economic Surprise Index tracks how major data points measured up to consensus expectations. When the index declines, economic data are falling short of analysts’ estimates. When the index increases, economic data are trumping Wall Street’s consensus expectations. This graph also tracks the performance of the S&P 500 to demonstrate the tight correlation between trends in the economy and stock market.

For example, the precipitous decline in the Citigroup US Economic Surprise Index in late 2008 corresponds to the nadir of the 2008-09 bear market. The index also declined in summer 2010, a move that coincided with a severe pullback in the S&P 500.

This year, the Citigroup US Economic Surprise Index topped out in early March, moved into negative territory and bottomed in early June. In this case, the index’s downdraft preceded the S&P 500’s summer correction by about two months.

Three factors contributed to the weakness in the Citigroup US Economic Surprise Index this spring: temporary headwinds, real economic weakness and overly optimistic expectations.

The temporary headwinds included the spike in oil prices that followed the outbreak of the Libyan civil war and supply-chain disruptions stemming from the March 2011 earthquake and tsunami that devastated Japan’s Tohoku region. But energy prices have pulled back in subsequent months, and automobile sales have recovered now that the supply chain has returned to normal functionality.

Some economists also were too bullish about the US economy’s growth prospects at the beginning of 2012. Analysts’ over-exuberance was partly a function of historical comparisons; this recovery has fallen short of prior postwar recoveries because consumers are focused on saving and paying down debt, activities that eat into discretionary spending.

Economists were slow to reduce their estimates in spring and early summer. Later, they misjudged the depth of the slowdown and slashed their forecasts too much. Two months ago, most economists called for US GDP to expand 1 percent to 1.5 percent in the third quarter. Recent data points have prompted economists to raise their estimate of third-quarter economic growth to between 2 and 2.5 percent. If economic data continue to surprise to the upside, economists will need to raise their estimates for fourth- and first-quarter GDP growth.

At the same time, the summer swoon wasn’t all temporary factors and wonky economic expectations. The protracted debate over the US debt ceiling and Standard & Poor’s downgrade of the US government’s credit rating didn’t help matters. Meanwhile, the risk associated with the ever-present EU sovereign-debt crisis also weighed on business and consumer confidence.

Amid all this uncertainty, US economic data have improved markedly in recent months, returning the Citigroup US Economic Surprise Index to positive territory. Meanwhile, two of my favorite forward indicators–the Institute for Supply Management’s Manufacturing Purchasing Managers Index and the Conference Board’s Index of Leading Economic Indicators–never fell to levels consistent with a recession.

My outlook for the US economy remains unchanged: Halting GDP growth that averages roughly 2 percent annually. In this environment, investors should gird themselves for periodic softness in economic activity and a volatile stock market.

Although US economic data have improved, the S&P 500 continued to fall through the end of the third quarter. Only on rare occasions does the performance of the Citigroup Economic Surprise Index deviate from the stock market to this extent. Europe’s woes were likely the cause of this anomaly. The yields on bonds issued by the Italian and Spanish governments spiked in early August, heightening the risk of a potential default and credit crunch.

Thus far, stress in the interbank lending market has yet to approach levels seen in late 2008 and early 2009. Meanwhile, the EU’s ailment has yet to jump to US or other global credit markets.

We stick by our contention that EU policymakers eventually will take decisive action to control the sovereign debt-crisis. All national governments within the eurozone have approved the European Financial Stability Facility’s (EFSF) expanded powers, overcoming the unpopularity of these bailouts in Germany and other fiscally responsible nations.

Shortly after the enhanced EFSF was approved, rumors of a rescue plan orchestrated by Germany and France began to circulate. Much of the scuttlebutt has focused on using the EFSF to guarantee the first 20 percent of all losses on bonds. The fund then only needs to put up one-fifth of the notional value of bonds it guarantees, effectively multiplying its firepower to more than EUR2 trillion. The bailout will also likely include a deeper haircut on Greek sovereign bonds and a credible stress test and recapitalization plan for EU banks.  

A plan of this nature should be enough to calm investors’ addled nerves.

That’s not to suggest that the bailout being contemplated would solve the EU’s sovereign-debt crisis overnight. Italy and other fiscally weak nations will need years of austerity to reduce their debt burdens to healthier levels. Nevertheless, the threat of a global credit crunch would decline substantially, and investor and business confidence would likely improve.

Bottom line: US economic data have improved and the risk of a credit freeze is fading. Against that backdrop, IEA may find cause to raise its 2012 outlook for US oil demand. At the very least, downside risk to US oil demand appears limited.

Weekly US oil demand statistics from the Energy Information Administration (EIA) also show scant sign of weakness. This graph tracks the year-over-year change in the four-week moving average of oil demand.

Source: Energy Information Administration

Oil consumption contracted by more than 10 percent on a year-over-year basis in late 2008 and early 2009–the most severe demand destruction in US history.

This year pales in comparison. Although demand weakened in spring and early summer–likely because of the sudden spike in oil prices–consumption has leveled out and started to recover now that oil prices have receded. Consumers have also grown accustomed to paying higher prices at the pump; the shock of the big run-up in gasoline prices earlier this year has faded from memory. An uptick in GDP growth and retail sales suggest that oil demand will expand in the near term.

US demand for diesel also remains robust and is up 6 percent on a year-over-year basis. Demand for diesel, which is used in industrial processes and to deliver parts and finished goods, usually fluctuates based on manufacturing activity. With the US out of the soft patch in which it was mired earlier this spring, the IEA could increase its estimates of domestic oil demand once again.

Asia-Pacific and Emerging Markets

The IEA’s forecast for 2012 oil demand calls for the fastest growth to occur in the Middle East and the Asia-Pacific region. Rapidly expanding economies such as China and India will account for much of this demand growth, but Japanese oil consumption also stands to rise. Although the nation had made enormous progress in its recovery from the March 2011 earthquake, much of its nuclear power capacity remains idled. Oil-burning options are among the only readily available substitutes.

Several factors are expected to contribute to the surge in oil demand in the Middle East. For one, the region benefits directly from elevated oil and natural-gas prices. In addition, Saudi Arabia and other nations responded to the “Arab Spring” protests earlier this year by announcing major social spending programs designed to placate the masses and boost the domestic economy–an incremental positive for energy demand.

Emerging markets don’t face the same economic headwinds as the developed world. Whereas many developed nations are struggling with deflation and a painful deleveraging process, inflation is the biggest problem for emerging markets.

Brazil, India and China–among other nations–have tightened monetary policy aggressively and allowed stimulus measures instituted during the Great Recession to expire. These governments have sought to slow the pace of economic growth to sustainable levels.

Source: Bloomberg

This graph tracks China’s annualized consumer price inflation rate. Over the past year, inflation in China has soared from about 4 percent–roughly in line with the Central Bank’s target–to as high as 6.5 percent over the summer. Most analysts had called for inflation in China to peak at less than 6 percent, but prices have remained persistently high.

Beijing has implemented several measures to cool the red-hot economy and tame inflation. Chinese Premier Wen Jiabao wrote in late August that stabilizing prices is the nation’s top economic priority. The central bank has increased the one-year base lending rate to 6.56 percent from 5.31 percent one year ago and has taken steps to curb speculation in the housing markets and rein in bank lending.

These efforts appear to be working: Core inflation, which excludes food and energy prices, has cooled notably, and the headline rate has declined in each of the past two months to 6.1 percent from 6.5 percent.

Food prices often drive inflation in emerging markets. In China, trends in the cost of pork–a staple that accounts for a large proportion of household meat consumption–also reflect rising grain prices (pigs must be fed) and provide valuable insight into inflationary trends.

Source: Bloomberg

After shooting higher for more than a year, pork prices in China have finally stabilized. Slower growth or a contraction in food prices should presage lower inflation

The Bloomberg consensus estimate calls for China’s consumer price index to yield an average inflation rate of 4.5 percent in the fourth quarter. This figure might prompt the government to ease monetary conditions or offer other forms of fiscal stimulus if authorities feel growth is slowing too quickly.

Unlike the Federal Reserve and other developed-world central banks, China has plenty of room to cut rates. And unlike the US and EU governments, China isn’t saddled with public-sector debt and could tighten interest rates. We expect Beijing to unveil at least a few growth measures by early 2012. At any rate, GDP growth of 9.1 percent remains robust, albeit off last year’s blistering pace.

Inflation is also an issue in India. The graph above tracks wholesale prices for farm products and indicates that food price inflation remains elevated, ­­though the rate at which prices are increasing has declined significantly since the beginning of 2011.

Vehicle sales are one of the best indicators of oil demand growth in emerging markets.

Source: Bloomberg

This graph tracks sales of passenger vehicles in India (annualized monthly sales) and China (straight monthly sales). Car sales in India have continued to increase and recently hit a new high. Automobile sales in China have pulled back from their record high, but have remained solid over the past few months. China in 2010 overtook the US as the world’s largest car market.

Bottom line: The IEA’s forecast for robust oil demand growth in the Asia-Pacific region and other emerging markets appears reasonable and could surprise to the upside if the governments decide to loosen monetary policy. Current data suggest that China’s economy will avoid a hard landing.

Crude Realities: The Supply Side

Much of the commentary on global oil markets focuses on the outlook for demand, but investors shouldn’t ignore the trends playing out on the supply side of the equation.

The IEA has slashed its estimate of non-OPEC oil production at an even faster pace than reduced its forecast for oil demand.

Source: International Energy Agency

This graph shows the IEA’s estimates of non-OPEC oil output for 2011 and 2012. The agency issues its initial estimate for the following year in July and revises this projection as warranted.

Since May, the IEA has lowered its forecast of 2011 non-OPEC production by 900,000 barrels of oil per day to 52.8 million barrels per day. This projection implies year-over-year non-OPEC production growth of only 200,000 barrels of oil per day.

If global oil demand expands by forecast 1 million barrels per day in 2011, non-OPEC production will satisfy only 20 percent; OPEC will need to ramp up production or countries will need to dip into their stockpiles.

Global oil inventories have decline relative to 2010 levels, but these reserves won’t fill the gap. This imbalance–exacerbated by the loss of Libya’s 1.5 million barrels per day of light, sweet crude oil for six months–forced OPEC to tap into spare productive capacity to cap prices and limit demand destruction.

Investors should pay close attention to OPEC’s spare capacity when divining oil prices. In general, oil prices tend to rise when OPEC’s spare capacity declines.

At the end of 2010, effective OPEC’s spare capacity stood at 5.6 million barrels of oil per day. Today, sluggish non-OPEC output growth, rising demand, and supply disruptions have reduced the cabal’s spare capacity to 3.25 million barrels of oil per day. This single statistic tells you a lot about why oil prices have been resilient this year.

Spare capacity should remain tight. Libya’s oil production may recover to between 200,000 and 300,000 barrels per day by early 2012 But the Libyan government has admitted that production won’t return to pre-conflict levels before early 2013.

Meanwhile, the IEA has lowered its estimate of 2012 non-OPEC production by 400,000 barrels of oil per day. Expect OPEC’s spare capacity to dwindle throughout 2012.

I foresee more downside risk to the IEA’s non-OPEC supply estimates than I do for global oil demand. Producers increasingly have to target complex, expensive-to-exploit fields in the deepwater and other remote areas to generate incremental output growth. Drilling activity has also increased in unconventional plays such as North America’s shale oil and gas fields and Canada’s oil sands.

The balance between global oil demand, supply and spare capacity remains tight. Higher oil prices are necessary to incentivize the development of complex fields. Higher prices are also the only way for the global oil market to effectively limit demand; if consumption growth in 2012 matched the IEA’s estimate for 2011 demand growth, the world’s spare capacity would be effectively eliminated.

Based on this outlook, we continue to favor our favorite oil services names, all of which have pulled back because of the recent growth scare and EU sovereign-debt crisis–not the realities of the global oil market. Buy Weatherford International (NYSE: WFT) up to 28, Schlumberger up to 100 and Baker Hughes (NYSE: BHI) up to 60.

Natural Gas: It Pays to Stay Liquid

The rapid development of oil and natural gas reserves trapped in shale and other “tight” reservoir rocks has catalyzed dramatic changes in the US energy picture over the past three to four years.

First and foremost, advances in directional drilling and hydraulic fracturing enabled US exploration and production firms to tap the massive oil and gas reserves formerly trapped in impermeable reservoir rocks.

Directional drilling enables producers to target the most productive portions of a field by carving out a well that branches off horizontally from the vertical shaft. Fracturing, or stimulation, increases the permeability of the reservoir rock, allowing natural gas to flow from the reserve rock into the well. This process involves pumping large quantities of water and a small percentage of chemicals into the rock formation at high pressure, producing a network of cracks. The inclusion of a proppant–typically sand, sand coated with ceramic material or ceramic material–ensures that these passages remain open.

Not only did these production methods and technologies unlock formerly inaccessible energy resources, but these innovations also touched off a land rush that revolutionized the way in which oil and gas companies build their leasehold. Rather acquiring acreage and performing test drilling in manageable chunks, Chesapeake Energy Corp (NYSE: CHK) and other firms deployed massive amounts of capital to scoop up huge swaths of land.

Although this strategy enabled producers outmaneuver rivals and hedge against uneven productivity within a given field, it also saddled these firms with massive drilling inventories that needed to be completed by a set time to ensure that the acreage was held by production.

With ready access to capital through bond and equitiy issues and joint ventures with major integrated oil companies, E&P firms drilled these plays at a frantic pace, flooding the US market with natural gas and depressing prices to record lows for the past several years. The graphs below tell the tale.

 
Source: Energy Information Administration


Source: Bloomberg

As you can see, US natural gas production picked up substantially in 2007 and has continued to head higher. Together, the graphs reflect an apparent anomaly in the domestic market for natural gas: Drilling activity in unconventional plays remains robust despite, depressed natural gas prices–a puzzling disconnect.

Attractive economics in some of the nation’s hottest shale plays partially explain why producers continue to ramp up production.

As we discussed in Why Some Natural Gas Is Worth $7.28, producers in shale plays rich in natural gas liquids (NGL), continue to enjoy solid profit margins. NGLs such as propane, butane and ethane tend to command a higher price that tracks crude oil; for many producers, the associated natural gas has become an afterthought. In fact, many independent E&P firms have shifted capital spending and drilling activity from dry-gas fields such as the Haynesville Shale to more profitable liquids-rich plays.

The shale gas revolution also has dramatically changed the fortunes of US importers of liquefied natural gas (LNG). 

What is LNG? When natural gas is cooled to minus 260 degrees Fahrenheit at a liquefaction facility, it condenses into a liquid that’s roughly 1/600th its original size. In this form, large amounts of natural gas can be safely transported overseas in specially designed ships. Re-gasification terminals warm the LNG to return it to its gaseous state before pipelines transmit the product to end users.

Earlier this decade, most analysts projected that US LNG imports would increase steadily, offsetting lower domestic production. Back in 2003 there were at least two dozen proposals to build new re-gasification terminals. But US LNG imports never reached the 812 billion cubic feet per year that the Energy Information Administration (EIA) projected in its Annual Energy Outlook 2004. In fact, the amount of liquefied gas delivered to the US fell off a cliff after peaking in 2007. In fact, according to the EIA, the US imported only 431 billion cubic feet of LNG in 2010, down from the 2007 peak of 771 billion cubic feet.


Source: Energy Information Administration

This precipitous decline in US LNG imports, coupled with the demand destruction that occurred during the great recession, flooded the market with low-priced LNG in 2009. The commissioning of a number of liquefaction terminals worsened this oversupply.

Much of this gas found its way to European markets such as Spain, Belgium and the UK, which in 2010 became the fourth-largest LNG importer. This influx prompted some Continental countries to reduce purchases of pipeline gas to the lowest levels allowed by contract, replacing these volumes with lower-priced LNG.

Some analysts have suggested that while this trend won’t mark the end of the long-term, oil-indexed gas export contracts favored by the likes of Gazprom (Moscow: GAZP, OTC: OGZPY), the competition could force the Russian giant to become more flexible and reduce the duration of contracts.

Meanwhile, the robust economic recoveries in developing and developed Asian nations supported strong LNG demand growth in 2010. Japan and South Korea once again dominated the global LNG market last year, together accounting for 64 percent of the world’s LNG imports. Geographic obstacles–the Pacific Ocean and North Korea, respectively–prevent both countries from accessing regional pipeline systems.

After the economic downturn sapped LNG demand in 2009, Japan’s LNG imports jumped 8.8 percent in 2010 to 71.3 million metric tons. South Korea’s imports of liquefied gas also recovered to a new high after their 2009 swoon, reflecting a strong recovery in the nation’s industrial sector. China’s intake of LNG cargoes surged in 2010 to 9.7 million metric tons from 5.8 million metric tons–a 67 percent increase.


Source: BP Statistical Review of World Energy 2006-2011

The supply-demand balance in the global LNG market has tightened considerably thus far in 2011, fueled once again by strong demand in Asian markets. China’s monthly LNG imports have posted an average year-over-year increase of 30.7 percent through the end of August, a remarkable feat after the country’s LNG demand surged 67 percent in 2010. Demand usually picks up during the peak summer cooling season and the winter heating season, forcing utilities and distributors ramp up imports to prevent shortfalls.


Source: Bloomberg

New re-gasification capacity should ensure that this momentum continues into 2012. The first 3.5 mmtpa train at PetroChina’s (Hong Kong: 0857, NYSE: PTR) Rudong terminal in Jiangsu province came onstream in June, while the second phase of the firm’s Fujian import facility is partially operational. The first 3 mmtpa train at PetroChina’s Dalian re-gasification facility should start up in the fourth quarter.
 
As we forecast in March 24, 2011, issue, The Fallout, Japan’s demand for LNG has spiked after the magnitude-9.0 earthquake permanently damaged the Fukushima Dai-ichi nuclear power plant and forced the government to shut down many of the country’s nuclear reactors for stress tests. Reuters on Oct. 12 reported that only 10 reactors in Japan’s fleet of 54 were operating.

All of this has translated into increased demand for imported natural gas. The latest data from the Federation of Electric Power Companies of Japan indicates that the nation’s 10 largest electricity producers increased their LNG substantially in the summer and fall to offset lost nuclear capacity.


Source: Bloomberg

Although one shuttered nuclear power plant returned to operation in August, reports from Japan indicate that local opposition may delay some reactors from returning to service after the first phase of stress tests is completed. With two of Tokyo Electric Power’s (Tokyo: 9501, OTC: TKECY) three nuclear power stations shut down after the March earthquake and tsunami, the utility is fast-tracking plans to expand its gas-fired capacity in 2012.

Japan’s LNG imports have jumped surged since the earthquake hit–check out the graph below–and we expect this strength to continue. 


Source: Bloomberg

This uptick in LNG demand in China and Japan has elevated prices to levels about which North American producers can only dream–and a short breather in the rollout of new liquefaction capacity through 2013 should ensure than the market for liquefied gas remains tight.


Source: Bloomberg


Source: Bloomberg

This demand growth should have legs. The Chinese government’s long-term plans call for natural gas to account for 10 percent of the country’s energy mix, roughly one-third of which will be imported via pipelines or LNG.

Natural gas has been growing in popularity in China, particularly in power-generation facilities located near major cities. Concerns about air quality mean that many of the high-rise residences constructed during China’s recent housing boom are equipped for piped gas. Further migration to urban areas will only increase demand. China Gas Holdings, a natural gas distributor, recently reported that it expects its annual sales volume to surge to 10 billion cubic meters (Bcm) per day in 2015 from 5.2 Bcm per day in 2010. 

LNG imports will be part of the solution. China’s first re-gasification terminal opened in 2006, and the country currently boasts four operational import facilities, all of which are operated by China National Offshore Oil Corp (CNOOC). The first phase of the pilot Guangdong LNG terminal, which came onstream in September 2006, boasts a total capacity of about 180 billion cubic feet (Bcf) of gas per day, while the Fujian re-gasification terminal that began operations in May 2009 sports an initial capacity of 126 Bcf of gas per day. The company also runs the Shanghai LNG terminal, which can re-gasify 146 Bcf of gas per day.

But that capacity is slated to expand substantially. By 2015, CNOOC should have five LNG import terminals up and running, while PetroChina will have four operational re-gasification facilities and China Petroleum & Chemical Corp (Hong Kong: 0386, NYSE: SNP) will have two. The table below lists all of China’s operational, under construction and proposed LNG terminals.

Source: Reuters

And investors shouldn’t overlook India’s insatiable appetite for energy commodities.

India’s Ministry of Petroleum and Natural Gas expects LNG imports to increase from 33 million cubic meters (mcm) per day to 162 mcm per day by fiscal year 2029-30. Over this period the government expects natural gas to grow to 20 percent of India’s energy mix from 9 percent. LNG imports could easily exceed estimates if expected pipeline imports don’t materialize–a distinct possibility–or domestic production falls short of expectations.

Two LNG terminals currently operate in India, Petronet LNG’s (Bombay: 532522) 10 mmtpa facility at Dahej and Royal Dutch Shell’s (LSE: RDSA, NYSE: RDS.A) 3.6 mmtpa installation at Hazira. Petronet LNG plans to add 2.5 mmtpa of additional capacity. Ratnagiri Gas and Power’s 5 mmtpa plant in Dabhol remains under construction, though 1 mtpa of capacity could come online before the project is completed. Two additional LNG import terminals are in the early stages of planning.

Meanwhile, growing demand for LNG in emerging markets supports higher gas prices in developed economies. South Korea, Japan and China have proved eager to ink deals securing long-term supplies of this critical resource.

Australia’s domestic demand for natural gas should also increase substantially in coming years, as utilities seek to reduce carbon dioxide emissions to comply with new environmental regulations. At the same time, the dramatic expansion of mining and industrial facilities in Western Australia will also drive demand for additional electricity. The majority of these power plants will be fired by natural gas. In 2010 natural gas accounted for only 14 percent of Australia’s electricity generation, compared to about 24 percent in the US.

European demand for LNG should also increase, particularly after Germany’s recent decision to temporarily shutter seven of its nuclear reactors and to accelerate the phasing out its remaining nuclear power plants.

The International Energy Agency’s Medium-Term Oil and Gas Markets 2011 report calls for international gas consumption to grow to 369.5 mmtpa in 2015 from 215.3–a roughly 71 percent increase. Emerging markets, particularly those in the Asia-Pacific region, are expected to account for much of this growth. Natural-gas prices in this region traditionally have been indexed to oil prices.

Natural-gas producers worldwide are salivating over this opportunity. Qatargas’ assistant director for LNG marketing in late September stated that the company aims to double its long-term supply agreements in the Asia-Pacific region from 11 mmtpa per year to more than 20 mmtpa.

North American outifts are also working on LNG export projects to take advantage of rising demand in international markets and superior pricing.

Apache Corp (NYSE: APA) and Wildcatters Portfolio holding EOG Resources (NYSE: EOG) are the progenitors of the Kitimat LNG joint venture, an export facility sited in Bish Cove, British Columbia, that would supply Asian markets with natural gas sourced from the partners’ operations in the Horn River Basin. The source gas for the facility would arrive via the proposed 463-kilometer Pacific Trail Pipelines system.

In 2009 the duo announced a memorandum of understanding (MOU) with Korea Gas Corp (Seoul: 036460) whereby the world’s largest LNG importer would purchase up to 40 percent of Kitimat’s output. The agreement also included an option for Korea Gas to buy an equity stake in the project.

In March 2011, the partners welcomed natural gas producer EnCana Corp (TSX: ECA, NYSE: ECA) to the fold as a 30 percent stakeholder. Apache Corp’s Canadian division remains the operator. The partners awarded the design and construction contract to KBR (NYSE: KBR) and expect to make a final investment decision on the first phase of the project in 2012, once the front-end engineering and design work is completed in 2011. The project is expected to cost USD4.5 billion for the two export terminals.

The initial plan calls for a facility capable of processing 5 mmtpa, though capacity could eventually double in size if warranted. Canada’s National Energy Board on Oct. 13 approved the partnership’s application for a 20-year permit to export up to 10 mmtpa of LNG annually.

At this point, the partners have obtained the requisite environmental approvals and will make their final investment decision in 2012.

We continue to like EOG Resources for its leading positions in some of the hottest US shale oil plays and strong production growth. The company’s involvement in the Kitimat LNG project is an added bonus and could enable the company to earn a higher rate of return on natural gas from its massive Horn River acreage in British Columbia. Take advantage of the recent pullback and buy EOG Resources up to 125.

Another proposed export terminal would be built on the US Gulf Coast. In June 2010, Cheniere Energy Partners LP (AMEX: CQP) proposed adding liquefaction capacity to its Sabine Pass LNG receiving terminal in Cameron’s Parish, La. The sourced gas would come from a number of prolific fields in the region, including the Permian Basin and the Barnett, Haynesville, Eagle Ford, Woodford and Bossier Shale plays.

Initially, the company would add two liquefactions trains, each capable of producing 3.5 mmtpa of LNG. In the event of strong demand from customers, Cheniere Energy Partners would consider installing two additional trains. Thus far, executives from independent gas producers Encana Corp and Chesapeake Energy Corp have voiced their support for the project. Cheniere Energy Partners also announced non-binding MOUs with Morgan Stanley (NYSE: MS), Gas Natural (Madrid: GAS), ENN Energy (Hong Kong: 2688), Sumitomo Corp (Tokyo: 8053), Endesa (Madrid: ELE) and Enel (Milan: ENEL) for 9.8 mmtpa of planned export capacity.

On Sept. 7, 2010, the Dept of Energy approved Cheniere Energy Partners’ request to export about 803 billion cubic feet (bcf) of natural gas annually over the next 30 years to nations with which the US has a free trade agreement. On May 20, 2011, the Dept of Energy approved a second proposal allowing the master limited partnership to export 803 bcf annually to World Trade Organization (WTO) members and non-WTO countries.

On July 26, 2010, Cheniere Energy Partners also initiated the process to gain approval from the Federal Energy Regulatory Commission (FERC) for the siting, construction and operation of its proposed liquefaction facilities. FERC recently articulated its support for the project, pending the resolution of several issues.

We continue to rate Cheniere Energy Partners LP a sell in the Energy Watch List. The firm’s growth prospects depend solely on efforts to add LNG export capacity to its Sabine Pass terminal–an expensive proposition that will require the MLP to raise a significant amount capital by issuing new shares and borrowing heavily. Bottom line: Executing this $6 billion project will be a tall order for a company with a market capitalization of $500 million and almost $3 billion in existing debt.

Although these projects might pique the interest of US investors seeking a release valve for the nation’s glut of natural gas, the real action is in Australia. Over the next decade, more than a dozen ambitious LNG projects are planned to take advantage of rising demand for liquefied gas in China, India and other emerging markets such as Thailand and Vietnam. This table lists Australia’s operational, under construction and proposed export terminals.

Source: Bloomberg, Company Reports

Geoscience Australia and the Australian Bureau of Agricultural and Resource Economics estimate that 92 percent of the nation’s natural gas reserves are located offshore Western Australia and the Northern Territory in the Bonaparte, Browse and Carnarvon basins. Of these three gas-rich areas, the Carnarvon has undergone the most exploration and development. Not surprisingly, the preponderance of Australia’s LNG projects will source their feedstock from these fields.

But the discovery and development of unconventional gas reserves in the eastern portion of Australia have prompted energy companies to pursue four separate liquefaction facilities on the Queensland coast: BG Group’s (LSE: BG, OTC: BRGYY) Queensland-Curtis LNG Project, Santos’ (ASX: STO, OTC: SSLTY) Gladstone LNG Project, ConocoPhillips’ (NYSE: COP) Australia Pacific LNG Project, and Royal Dutch Shell and PetroChina’s Arrow LNG Project.

Although the Surat basin in this region is home to substantial conventional resources, much of the feedstock for these LNG projects will come from Queensland’s prolific coal-seam gas (CSG) plays. CSG is methane that has been trapped in coal deposits by water. Producers liberate the gas by drilling wells into the coal seam–usually to a depth of 300 to 800 meters–and pumping out the water.

Australia first began exploiting CSG on a commercial basis in 1996 in the Bowen Basin, and the rapid development of these plays has enabled Queensland to grow its natural gas production considerably in recent years. According to the Australian Petroleum Production & Exploration Association, CSG output more than doubled over the past three years to 215,216 million cubic feet (Mcf) from 102,733 Mcf in 2007. In 2010 Queensland’s share of Australian natural gas production increased to 14 percent, largely because of CSG development.

With this many projects focused on Asian LNG demand in the works, overbuilding is a distinct risk. All of these projects occuring over roughly the same time frame and in two regions of Australia has also led to substantial wage and cost inflation. To offset these risks, we favor names with strong balance sheets that have already booked much of their projects’ planned capacity under long-term contracts with solid customers.

Wildcatters Portfolio holding BG Group’s LNG operations, which include liquefaction and re-gasification assets as well as the purchase, shipment, marketing and sale of LNG, accounted for roughly 35 percent of the company’s 2010 revenue. BG’s LNG operations and assets span the globe and, in many instances, complement its E&P efforts.

How do these disparate assets work within BG’s business model? BG’s LNG trading and shipping divisions work together to market, sell and deliver LNG volumes to customers worldwide on both a short- and long-term basis. In addition to marketing its own contracted LNG, the firm also buys volumes on regional spot markets and resells this gas to take advantage of regional pricing discrepancies. To support these trading activities, the company’s shipping arm boasts a fleet of owned and contracted ships.

With its low-cost supply base and global operations, BG is well-positioned to benefit in the near and over the long term from tightening in international LNG markets. For example, BG at the end of September inked a head of agreement with Gujarat State Petroleum Corp to provide the Indian outfit with up to 2.5 mmtpa of LNG over a 20-year period. The company has also inked long-term supply contracts for all the initial 8.5 mmtpa capacity on its Queensland-Curtis LNG project that’s slated to come onstream in 2014. Buy BG Group under GBp1,650 on the London Stock Exchange or USD133 in the over-the-counter market.

Oil Search (ASX: OSH, OTC: OISHY) is headquartered in Papua New Guinea’s (PNG) capital of Port Moresby, located on the country’s southern coast. The company’s main base of operations includes the Gulf of Papua, located to the northwest of Port Moresby, as well as the Southern Highlands province.

Oil Search’s 2010 production amounted to 7.657 million barrels of oil equivalent, more than 88 percent of which was crude oil. Note that this is an annual production figure, not barrels per day. The company’s production has declined steadily over the past five years, as depicted in the graph below.

Five years ago, Oil Search produced more than 10 million barrels of oil equivalent; at the end of 2010, its output had declined by roughly 25 percent–largely because of declining pressure in its mature wells.

The company has taken steps to offset that decline, drilling new wells in these older fields that target untapped pockets of oil. For example, Oil Search has sunk wells in Agogo, a smaller satellite field that’s adjacent to Kutubu, the firm’s largest play. One of these wells struck oil and now produces 1,500 to 2,000 barrels per day.

Fields such as Agogo should help to offset declines in Oil Search’s mature fields over the next few years. Management expects the company’s oil production to hover between 6.2 and 6.7 million barrels per year range in 2011-13. For comparison, the firm produced about 6.768 million barrels of crude oil 2010.

Rising oil prices have helped the the company’s bottom line and offset recent output declines. In 2010, for example, Oil Search’s output declined roughly 6 percent from the prior year, but revenue surged 14 percent and earnings before interest and taxation jumped 27 percent.

If all Oil Search had to offer was declining output from a handful of aging oilfields, the stock wouldn’t warrant a second look. But the company is in the midst of a transformation that should quadruple its production. The main driver of this is the Papua New Guinea LNG (PNG LNG) project.

Management estimates that constructing the PNG LNG facility will have cost $14 billion by the time it’s completed in 2014. PNG’s economy is expected to grow about 8 percent and double in size over the next five to seven years, with the PNG LNG deal contributing the majority of that growth.

The main PNG LNG complex is located near Port Moresby and will consist of two LNG liquefaction trains, each capable of producing about 3.3 million metric tons per annum (MTPA) of LNG for export. Gas to feed these trains will be sourced from the Hides, Angore and Juha gas fields located onshore in PNG. Additional gas supplies coproduced from Oil Search’s oil plays will feed these plants.

Like most projects of its size, PNG LNG is owned and funded by a consortium of companies. In this case, ExxonMobil Corp is the largest stakeholder, with a roughly one-third share, and will operate the facility. Oil Search, which holds a 29 percent stake in the project, is the second-largest player in PNG LNG. In addition, the company is responsible for producing the fields that will supply natural gas to the PNG LNG trains.

Although owning ExxonMobil would give investors exposure to the PNG LNG project, this endeavor is one among many for the integrated energy giant. With a market capitalization of roughly USD1 billion, the PNG LNG project could move Oil Search’s earnings needle substantially.  

Other major stakeholders in PNG LNG include the PNG government, which holds a16.8 percent stake; Australian energy firm Santos (ASX: STO, OTC: SSLTY), which owns a 13.5 percent stake; Nippon Oil, which owns a 4.7 percent interest; and local landholders who collectively hold a 2.8 percent interest in project.

PNG LNG is slated to come online in 2014, with both trains running by year-end. Oil Search’s share of total production will be 18 million barrels of oil equivalent per year–a huge uptick from its 2010 output of 7.6 million barrels of oil equivalent per year.

Long-term supply agreements with major gas consumers cover 100 percent of PNG LNG’s total capacity. Not surprisingly, China and Japan feature prominently in the customer list and would likely be interested in purchasing additional LNG volumes. 

The financing for the project is already in place, with debt funding about 70 percent of the project. Oil Search will owe another $1.2 billion related to the project over the next three years, but strong cash flows from its existing oil projects should be enough to foot the bill. In addition, Oil Search would likely have no trouble tapping the debt markets if additional capital were necessary.

Finally, it always helps to have the most deep-pocketed company on the planet as a lead partner in a project of this magnitude. Proven Reserves Portfolio holding ExxonMobil Corp (NYSE: XOM) has invaluable experience completing projects of this magnitude.

Oil Search’s American depositary receipts (ADR) trade thinly–only a few thousand shares change hands on most days. Investors should buy the local shares on the Australian stock exchange to ensure sufficient liquidity. Buying shares in Australia used to be a pain for US-based investors, but many brokers will now handle such transactions and some will handle the trades online. Investors who opt for the ADRs should use a limit order to avoid overpaying for the stock. Oil Search rates a buy under AUD8; the company’s ADR, which represents 10 local shares, rate a buy up to USD85.

Fresh Money Buys

The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative; the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.

I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of Fresh Money Buys that includes both stocks and some hedge recommendations designed to limit your risk amid market downturns.

I’ve classified each recommendation by risk level–high, low or moderate. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset exposure to energy stocks.

Also, note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased.


Source: The Energy Strategist