Our outlook for crude oil prices remains relatively unchanged since the Jan. 5, 2012, issue of The Energy Strategist, Reading the Tea Leaves. Potential demand destruction brought on by persistently high oil prices should limit upside for oil prices.

That being said, don’t assume that US oil demand is collapsing because of elevated oil prices and sluggish economic growth.

Source: Energy Information Administration

This graph tracks the four-week moving average of petroleum product supplies, a measure that includes heating oil, jet fuel, gasoline and diesel. US oil consumption collapsed during the Great Recession and financial crisis of 2007-09 and has never fully recovered. But consumption has held relatively steady; the most recent data indicates that US oil demand is down about 2 percent year over year.

However, the near-term trend is surprising. Despite elevated prices, US oil demand appears to have picked up over the past two weeks–a sign that consumers have grown accustomed to higher prices. These revised expectations are also reflected in March’s stronger-than-expected retail sales data.

Meanwhile, rising oil consumption in China and other emerging markets continues to drive global demand for oil and refined products. The International Energy Agency (IEA) estimates that global oil demand will expand by 800,000 barrels day in 2012–and there could be more upside to this number when you consider that the International Monetary Fund recently raised its outlook for 2012 global economic growth to 3.5 percent from 3.3 percent.

Bottom line: Spikes in the price of Brent crude oil to more than $120 per barrel would probably slow aggregate demand growth, while dips to less than $110 per barrel would encourage consumption.

The supply side of the equation likewise supports elevated prices.

Source: Energy Information Administration

This graph tracks the total number of unplanned outages in global oil production. Shortsighted pundits argued that the restoration of Libyan oil exports would lower oil prices in early 2012.

Libyan supply disruptions (in green) have declined to less than 0.4 million barrels per day as of April this year from roughly 1.4 million barrels per day in October 2011. (Mea culpa: I didn’t expect the nation to restore its oil output in such rapid fashion.)

But supply disruptions elsewhere have almost completely offset these unexpected gains. The Elgin spill has disrupted production in a portion of the North Sea, while a simmering pipeline dispute between Sudan and South Sudan in Africa has also weighed on output. South Sudan achieved independence in July 2011, but the two countries failed to agree upon pipeline transit fees for oil crossing the new border. The resulting dispute prompted South Sudan to shut in about 400,000 barrels per day oil production in January.

The IEA estimates that non-OPEC crude oil production slipped by 500,000 barrels per day in March, and the agency’s revised forecast calls for this output to increase by 700,000 barrels per day on the year. With demand growing faster than non-OPEC supply, the global oil market remains tight; the world will need to rely on additional output from OPEC to fill the gap.

Within OPEC, Saudi Arabia is the sole member that has significant spare capacity. At present, the organization’s total effective spare capacity stands at less than 3 million barrels per day–a drop in the bucket in a global oil market of almost 90 million barrels per day.

Elevated oil prices have little to do with speculation: A tight supply-demand balance ensures that oil prices have ample support.

My updated forecast calls for the price difference between West Texas Intermediate (WTI) and Brent crude oil to narrow in coming months. WTI has historically commanded a premium of $1 to $2 per barrel relative to Brent, but the relationship has reversed in recent years. At the peak difference between the two benchmarks, Brent crude oil traded at levels that exceeded the price of WTI by almost $30 per barrel.

This anomaly stemmed from local logistical constraints that combined to glut the oil hub of Cushing, Okla., the official delivery point for WTI.

On April 18, 2012, Conservative Portfolio holding Enterprise Products Partners LP (NYSE: EPD) announced that the reversal of its Seaway Pipeline is running ahead of schedule and will be completed by late May instead of late June. The reversed pipeline will transport crude oil from Cushing to the Gulf Coast, where price realizations are much higher. Although the Seaway Pipeline lacks sufficient capacity to eliminate the glut of oil at Cushing, this much-needed escape valve should reduce the spread between WTI and Brent crude oil.   

I continue to expect Brent crude oil to fetch an average of roughly $110 per barrel in 2012, while a barrel of WTI should average more than $100 per barrel. These price ranges should ensure that oil-weighted producers reap sizable profits and encourage drilling activity.

North American Natural Gas

An unusually hot summer or hurricane-related disruptions could lead to a short-lived recovery in North American natural gas prices, but investors shouldn’t expect a sustained rally any time soon.

Source: Energy Information Administration

This graph compares US working natural gas in storage to the five-year average. US natural gas in storage is almost 60 percent above the five-year average for this time of year–a record high that could set the stage for the country to max out its storage capacity. Such an unprecedented event would force producers to shut in wells temporarily until the oversupply abates.

As I explained in the Step Off the Gas, the US natural gas market already faced challenges before the unseasonably warm winter of 2011-12 arrived. The winter that never was reduced heating-related withdrawals, worsening an already oversupplied market.

In light of these challenges, we continue to short First Trust ISE-Revere Natural Gas Index Fund (NYSE: FCG) above 15.50. Investors looking to buy US-focused exploration and production companies should focus on our favorite oil-weighted names: EOG Resources (NYSE: EOG), Oasis Petroleum (NYSE: OAS), GeoResources (NSDQ: GEOI), SandRidge Permian Trust (NYSE: PER) and Mid-Con Energy Partners LP (NSDQ: MCEP).

International Natural Gas

The recent strength in global markets for liquefied natural gas (LNG) stems primarily from robust demand in emerging and developed Asian economies, which continues to tighten supply-demand conditions.

The Chinese government’s long-term plans call for natural gas to account for 10 percent of the country’s energy mix, about one-third of which will be imported via pipelines or as liquefied natural gas (LNG). In ExxonMobil Corp’s (NYSE: XOM) Outlook for Energy: A View to 2040, the integrated energy giant forecasts that China’s natural gas demand will grow at a faster rate than any other nation in the world.

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.

Even after China’s annual consumption of natural gas more than tripled between 2000 and 2009, this extraordinary growth shows no signs of abating. China National Petroleum Corp estimates that domestic natural gas demand in 2011 surged to almost 12.5 billion cubic feet (bcf) per day–up 21 percent from year-ago levels. China imported 2.9 bcf of natural gas per day last year, or 82 percent more than in 2010, to offset production that fell short of apparent demand.

China’s intake of LNG cargoes in 2011 surged to 1.63 bcf per day (about 56 percent of imported natural gas) from 1.25 bcf per day a year ago–a 30 percent increase. That’s on top of a 67 percent increase in China’s LNG imports in 2010. This uptrend has continued into 2012, with imported LNG volumes expanding by 60 percent in January and 26 percent in February.

Source: Bloomberg

Demand usually picks up during the peak summer cooling season and the winter heating season, forcing utilities and distributors to ramp up imports to prevent shortfalls. In addition to these seasonal factors, expansions to import capacity account for much of the overall growth in China’s LNG imports.

China’s first re-gasification terminal opened in 2006, and the country currently boasts five operational import facilities, all of which are operated by China National Offshore Oil Corp (CNOOC). The first phase of the pilot Dapeng LNG terminal, which came onstream in September 2006, boasts a total capacity of about 0.49 bcf of gas per day, while the Putian re-gasification terminal that began operations in May 2009 sports an initial capacity of 0.35 bcf of gas per day. The company also runs the Yanshan LNG terminal in Shanghai, which can re-gasify 0.40 bcf of gas per day.

But that capacity is slated to expand substantially. By 2015, CNOOC alone should have five LNG import terminals up and running, while China National Petroleum Corp (PetroChina) will have four operational re-gasification facilities and China Petroleum & Chemical Corp (Sinopec) will have one. The table below highlights the national oil companies’ operational LNG import facilities and those that are currently under construction.

Source: Reuters, Xinhua News Agency

Note that this table omits roughly 16 projects that are in various stages of planning and may or may not come to fruition.

All these projects are sited on the nation’s eastern coast, which accounts for the bulk of China’s demand. At the same time, a growing number of inland mini-terminals receive smaller LNG cargoes via truck. CNOOC has announced plans to expand its presence in this market and construct smaller-scale LNG carriers to deliver supplies to mini-terminals located on key waterways. 

Investors should also note that these terminals usually only operate near full capacity during periods of peak demand or when spot LNG prices are particularly attractive. With the central government regulating natural gas prices in China, the national oil companies have been saddled with losses because imported LNG comes at a higher cost.

Tax rebates announced by the General Administration of Customs and the State Administration of Taxation will provide some relief to China’s LNG importers. This long-awaited policy shift grants a rebate on value-added taxes applied to imported natural gas, a change that should reduce the losses suffered by the national oil companies’ LNG operations. This policy will remain in effect through 2020.

Toward the end of 2011, the National Development and Reform Commission also made a token move toward liberalizing gas prices, allowing suppliers to negotiate prices with buyers in the southern provinces of Guangdong and Guanxi–as long as those prices are within official limits.

Policymakers calculated this threshold by applying a 10 percent discount to 2010 prices of fuel oil and liquefied petroleum gas (key competitors in some applications). Likely designed to accommodate higher-priced pipeline gas from Turkmenistan, this program should have little effect on prevailing prices; the region already featured higher prevailing natural gas prices than in other areas.

Although the NDRC liberalized natural gas prices on a limited basis and has hinted that the program could eventually expand, official policy will likely focus on stimulating gas demand by keeping prices relatively low.

These moves suggest that Beijing recognizes that LNG imports will be critical to balancing markets during periods of peak demand and offsetting supply shortfalls as demand for natural gas grows. Meanwhile, as we noted in a series of articles on China’s early efforts to develop shale oil and gas resources, investors shouldn’t expect significant production from these resources until the end of the decade. (See Shale Oil and Gas in China, Part 1 and Part 2.)

With 23.9 million metric tons (equivalent to 3.12 bcf per day) of re-gasification capacity under construction and expected to come onstream by 2015, China’s intake of LNG cargoes will expand significantly in coming years.

Despite China’s growing demand for LNG, the developed nations of Japan and South Korea will continue to dominate the global market for this fuel. In 2010 these developed nations accounted for 46 percent of the world’s LNG imports. Geographic obstacles–the Pacific Ocean and North Korea, respectively–prevent both countries from accessing regional pipeline systems.

State-run Korea Gas Corp estimates that South Korea’s LNG imports will grow at an average annual rate of 5.1 percent between 2009 and 2015 and 1.8 percent through 2024. Although the nation’s average annual imports in 2011 surged 16 percent to 4.71 bcf per day, surging Japanese demand in the wake of the Fukushima Daiichi disaster has driven global LNG markets over the past 12 months.

As we forecast in March 24, 2011, issue, The Fallout, Japan’s LNG consumption spiked after the magnitude-9.0 earthquake permanently damaged the Fukushima Daiichi nuclear power plant and forced the government to shut down many of the country’s nuclear reactors for stress tests. Today, all but one of nation’s 54 reactors are offline for maintenance checks and government-mandated technical reviews. Although two facilities have passed these rigorous inspections, they’re unlikely to come onstream before the one operating reactor is closed for maintenance.

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 have substantially increased their use of LNG to offset lost nuclear capacity.

Source: Bloomberg

Japan’s LNG imports have jumped since the earthquake hit–check out the graph below–and we expect this strength to continue for much of 2012.

Source: Bloomberg 

This uptick in LNG demand in China and Japan has elevated prices to levels about which North American producers can only dream.

However, investors should expect LNG import prices to moderate in Asia as Japan’s nuclear fleet returns to operation. Without factoring in the effect of any permanently shuttered reactors, we estimate Japan’s excess LNG imports in the aftermath of the Fukushima Daiichi incident at roughly 1.6 billion cubic feet per day.

With the European economy in recession, we expect LNG demand to remain roughly flat over the next few years, assuming that the unusually warm winter of 2011-12 doesn’t repeat itself. Over the long term, however, European demand should pick up, particularly after Germany’s decision to temporarily shutter seven of its nuclear reactors and to accelerate the phasing out its remaining nuclear power plants. 

The supply side of the equation raises some concerns that global LNG markets could slide into oversupply after 2015.

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.

By virtue of its proximity to these markets and extensive resource base, Australia could be home to about 87.5 million metric tons per annum (11.67 bcf per day) in planned LNG export capacity. The projects on which a final investment decision has been made amount to export capacity of 65.5 million metric tons (8.74 bcf per day). This table lists Australia’s operational, under construction and proposed export terminals.


Source: Bloomberg, Company Reports

This table also omits planned LNG export terminals in the US and East Africa. Although the uncertainty surrounding the global supply-demand balance after 2015 raises questions about the economics of planned projects that lack sufficient contract coverage, owners of LNG tankers stand to benefit handsomely from the growth in LNG export capacity.

If an oversupply or the introduction of low-price US exports causes LNG prices to falter, gas buyers in Europe and Asia will likely lower the amount purchased under long-term agreements to the extent allowed by contractual terms to take advantage of cheap prices in the spot market. 

To take advantage of this trend, we’re adding the recently listed GasLog (NYSE: GLOG) to the Aggressive Portfolio as a buy under 13.

GasLog’s fleet currently consists of two LNG tankers that were delivered in 2010 and are under contract to BG Group (LSE: BG/, OTC: BRGYY) until 2015 and 2016, respectively. More important, shipbuilder Samsung Heavy Industries will deliver eight newly built LNG tankers to GasLog through 2015.

BG Group has already booked the four vessels slated to arrive in 2013 under time charters: Two of these carriers will operate under five-year contracts, while the other pair have fixture terms of six years. Royal Dutch Shell (LSE: RDSA, NYSE: RDS A, RDS B) has locked up two vessels scheduled for delivery in late 2013 and early 2014 under seven-year deals; the final two LNG tankers under construction that will arrive in late 2014 and early 2015 are still available and will likely secure attractive bookings. GasLog also has the option to purchase two additional LNG carriers from Samsung Heavy Industries–if day-rates hold up, expect the company to exercise this option.

In addition to its wholly owned fleet, GasLog manages the 11 ships controlled by BG Group and owns a 25 percent stake in one additional LNG carrier leased under a 20-year time charter. The company’s management activities include supervising the construction of new LNG tankers, maintaining the existing fleet and staffing each vessel with well-trained personnel.

After serving as the sole technical manager for BG Group’s extensive carrier fleet for more than a decade, GasLog boasts one of the most experienced management teams in the business.

The locked-in earnings growth from the firm’s order book is impressive. Management estimates that these charters in 2012 will generate almost $56 million in revenue. As new vessels enter the fleet in 2013 and 2014, this revenue stream will surge to about $133 million in 2013 and $214 million in 2014.

GasLog will return some of this capital to shareholders in the form of a regular quarterly dividend–initially $0.11 per share for the fourth quarter of 2012. (In other words, investors who buy the stock shortly after the IPO won’t receive a dividend for close to 12 months.) At the stock’s current price, that payout would amount to a dividend yield of almost 4 percent. Buy GasLog under 13 in the Aggressive Portfolio.

Thermal and Metallurgical Coal

Thermal coal is coal burned in power plants, while metallurgical (met) coal is used to produce steel. We remain bearish on US thermal coal prices, but I see some upside for international met coal prices into the back half of 2012.

About 98 percent of all steel produced globally is manufactured using one of two basic processes: oxygen-blown and electric-arc furnaces. The main raw material used in an oxygen-blown furnace is pig iron, a type of iron that has 2 percent to 4 percent carbon content.

Pig iron is created in a blast furnace. In a blast furnace, raw iron ore, consisting primarily of iron mixed with oxygen, is heated to extreme temperatures in the presence of carbon. The carbon combines with oxygen in the iron ore to produce carbon dioxide gas, effectively removing the oxygen from the ore. The resultant product is pig iron, a rather brittle and useless substance in its own right.

To create steel from pig iron, much of the carbon and impurities must be removed. In an oxygen furnace, purified oxygen is pumped through molten pig iron. Oxygen bonds with carbon to produce carbon monoxide and with other impurities to produce slag that’s removed from the molten metal.

The result is steel, a low-carbon and low-impurity form of iron. The resultant steel can be alloyed with metals such as tungsten, chromium, molybdenum and nickel to produce a product with various useful properties such as increased strength, lower weight or resistance to rusting.

In contrast, an electric arc furnace uses electricity to heat scrap steel, remove impurities and make steel. Producing steel in such a furnace is cheaper but requires significant quantities of scrap steel to use as feedstock, so it’s a far more common technology in developed countries such as the US than in China.

Worldwide, 70 percent of steel produced is made in oxygen-blown furnaces–compared to roughly 30 percent in electric arc furnaces. In Asia, the world’s most important steel-producing region, around 81 percent of steel production comes from oxygen-blown furnaces. In China, more than 90 percent of steel is produced in oxygen blown furnaces.

China is the key to the global steel industry and, therefore, to global demand and pricing for met coal. China is both the world’s largest consumer and the world’s largest producer of steel, accounting for nearly half of total global production of the alloy. China’s dominance of both sides of the steel industry has increased steadily for years, a trend that’s likely to persist for the foreseeable future.

Source: Bloomberg

As recently as 2001, China accounted for just 15 percent of global steel production and a similar share of consumption. The nation’s rapid economic growth and development in the past decade has resulted in a dramatic increase in demand for steel and a tripling in the country’s share of the global market.

On the demand side, the major factors weighing on steel and metal coal prices are the slowdown in the Chinese economy and related decline in steel demand. But China’s economy appears to have bottomed out, and the pick-up in lending growth in response to the cut in bank reserve requirements is an encouraging trend. In addition, the government is focusing its attention on building more social housing and developing the nation’s second-tier cities; construction accounts for 60 percent of China’s steel demand, so these factors should support considerable growth in met coal demand as well.

On the supply side, the main driver of weakening metallurgical coal prices is fading supply disruptions in Australia, the world’s largest exporter of met coal. Australian production and export capacity was hit hard by severe flooding in late 2010 and early 2011, but this year’s rainy season was much milder and the country was able to restore much of that output. This added as much as 30 million tons of additional supply on a year-over-year basis. Rising high-quality supply and weaker demand growth is a classic recipe for some price pressure.

But with Chinese demand picking up, the met coal market is tightening again. And although Australian weather has been benign thus far, supply disruptions are always a risk in the met coal market.

My outlook for thermal coal is less sanguine, especially in the US. As for natural gas, above-average wintertime temperatures spell less demand for electricity and heating; coal stocks at US utilities piled up last winter to glutted levels. To worsen matters, with natural gas prices near $2 per million British thermal units, utilities with the flexibility to do so have switched from coal to natural gas. Finally, looking further into the future, more stringent US regulations regarding power plant emissions will result in the closure of older coal-fired power plants and greater reliance on cleaner-burning natural gas.

Nonetheless, coal will not disappear as a major source of electricity in either the US or world markets. New regulations from the Environmental Protection Agency regarding coal plant emissions apply only to new plants not currently in the later stages of planning; existing coal plants won’t be impacted, and some will continue to operate for decades to come.

In Asia and Europe, natural gas prices are three to five times prevailing prices in the US; in these markets coal is still the cheapest source of power. India plans to significantly increase its reliance on coal-fired power in coming years, while the idea that China will abandon coal–one energy commodity it produces domestically in abundance–is downright laughable.

Growth Portfolio holding Peabody Energy Corp (NYSE: BTU) remains my favorite pure-play coal mining pick, and the stock presents a compelling value at current prices. Over the past few years, Peabody Energy has boosted its exposure to Australian met coal. The company’s recent acquisition of Macarthur Coal significantly makes it the world’s largest exporter of pulverized coal injection (PCI) coal, a varietal that can be used as a partial substitute for met coal. Peabody Energy will benefit from rising Chinese steel demand and met coal imports in the back half of 2012.

As for thermal coal, Peabody Energy’s main exposure is in the Powder River Basin (PRB) of the western US. Producing coal from the PRB is much cheaper than in Central Appalachia, a region Peabody Energy exited entirely when it spun off Patriot Coal (NYSE: PCX). Demand and pricing for thermal coal produced in the PRB will be affected by the weakness in the US market, but Peabody Energy has the flexibility to shut mines and reduce costs to scale back its output in line with demand and minimize the impact on earnings.  The company also plans to build an export terminal on the West Coast that will allow it to move coal to Asia and participate in the much stronger and tighter seaborne thermal coal market.

Trading at valuations last seen in the depths of the 2008-09 recession and financial crisis, Peabody Energy Corp rates a buy under 45.