Despite the global recession in 2009 and weak natural gas prices in the United States, domestic American natural gas production soared to its highest level in nearly four decades and liquefied natural gas (LNG) imports rose from their sharp drop in 2008.
For 2010, continuing economic improvement could resuscitate domestic demand, particularly in the industrial and commercial sectors, supporting continued strong domestic production. While U.S. imports of pipeline gas from Canada likely will decline further, LNG imports will increase.
Demand Factors
Domestic demand. The U.S. Department of Energy’s (DOE) Energy Information Administration (EIA) estimates that total U.S. natural gas consumption dropped 1.5 percent in 2009 below the previous year’s usage of 23.2 trillion cubic feet (tcf). Although lower gas prices enticed higher use of the fuel for electric power generation in 2009, the recession and other factors such as weather more than offset declines in gas consumption in the industrial, commercial and residential sectors. EIA expects consumption in 2010 to rise 0.7 percent to 62.9 bcf per day, but anticipates that higher gas prices will cause the electric power sector to reduce gas use by 2.8 percent, not fully offset by higher industrial, commercial and residential demand as the U.S. economy continues to grow out of the 2008-2009 recession.
International demand. Generally, the worldwide economic slowdown in 2009 was reflected in weakened demand among major gas consuming countries. Asia performed best during the global recession, with key countries such as China and India posting significant economic growth for the year. Their demand for natural gas reflected their economic resilience. At the end of 2009, India’s Petronet LNG signed contracts for long-term supplies of an additional 2.5 million metric tons of LNG (120 bcf) annually from RasGas of Qatar, making India Qatar’s largest customer. Meanwhile, China plans to open several new LNG import terminals in 2010, and in 2009 China’s Sinopec signed its first LNG agreement. The deal with ExxonMobil will ship 2 MMT (95 bcf) of LNG annually for 20 years from Papua New Guinea to the import terminal Sinopec expects to complete in 2014 in Shandong.
The shutdown of all seven units of Tokyo Electric Power Co.’s (TEPCO) Kashiwazaki Kariwa nuclear power station, caused by a July 2007 earthquake, continued to boost Japan’s demand for LNG imports, but during 2009 TEPCO began to bring the units back on line. Each of its seven units burns about 90 bcf annually, so TEPCO’s need for spot purchases of LNG will drop as each unit goes back into operation.
And Spain, which in recent years has bid up spot LNG prices to cover hydroelectric shortfalls, will see the completion in early 2010 of the Medgaz Pipeline that will carry 280 bcf of Algerian gas to meet its needs.
Supply Factors
Domestic supply. The United States produced 22.045 tcf of natural gas in 2009; the first time domestic marketed production has exceeded 22 tcf since 1973. The boost in homegrown gas pushed America ahead of Russia as the world’s leading natural gas producer.
Unconventional gas production lies behind the reversal in the decline of American gas production, especially shale gas. Over the last decade coalbed methane has accounted for 6-9 percent of domestic gas production, but shale gas has been the headline story, rising from a negligible amount 10 years ago to 2 tcf or more than 10 percent of domestic production in 2008. Initial estimates place 2009 U.S. shale gas production at around 3 tcf—a 50 percent leap over 2008 production.
The entry of the oil majors into shale gas was the big energy story of 2009. Small independent producers such as Chesapeake Energy, XTO Energy, Devon Energy and Southwestern Energy led the exploration and development of shale gas plays such as Marcellus in Pennsylvania, Barnett and Haynesville in Texas and Louisiana, Fayetteville in Arkansas, and Devonian/Ohio between Kentucky, Virginia and West Virginia. As gas prices plummeted from their peak of more than $12 per million British thermal units (MMBtu) in mid-2008 to less than $3/MMBtu early in 2009, the independents were forced to shut some production and scramble for cash.
ConocoPhillips was among the first majors to move, purchasing a leading position in Texas’s Eagle Ford shale before the stampede and also buying into Haynesville Shale. In 2008, British giant BP PLC and Norway’s Statoil struck deals with Chesapeake Energy Corp. for part of its U.S. holdings. In 2009, Italy’s state oil company Eni SpA paid $280 million for a Barnett Shale stake owned by Quicksilver Resources Inc. And at the end of 2009, ExxonMobil agreed to pay $31 billion for Fort Worth gas producer XTO. By January 2010, French oil company Total SA announced a $2.25 billion deal for a 25 percent stake in Chesapeake Energy Corp.’s Barnett Shale, the largest U.S. gas field by production. The two companies also were considering joint shale gas ventures in Texas and Canada.
As a result of the activity in shale gas, the Potential Gas Committee in Colorado last year revised its outlook for American gas supply upward by 35 percent in just two years.
In its Short-Term Energy Outlook (STEO), EIA projects a 2.7 percent reduction in marketed natural gas production in 2010 over 2009, due to the sharp drop in working natural gas rigs in production last year, but sees production increasing by 1.1 percent in 2011.
International supply. Although shale gas remains primarily a North American story, the phenomenon is spreading.
Terminal capacity
China National Offshore Oil Corp. (CNOOC) brought its second LNG terminal online in March 2009 in Fujian province, and its third came online in September in Shanghai, raising its total LNG import capacity to about 400 bcf annually. CNOOC intends to bring two additional terminals, in Zhuhai province and Hainan, online in 2010. Rival PetroChina plans to commission two LNG import terminals next year, one in eastern Jiangsu province and the other in northeastern Liaoning province, while China’s third major petroleum company—Sinopec—expects to open its Guangxi LNG terminal this year. Taiwan’s China Petroleum Corp. opened a 140-bcf/y terminal at Taichung in 2009 to accommodate its contract with Qatar’s RasGas. Elsewhere in Asia, companies in India, Pakistan and the Philippines plan to open LNG terminals in 2010.
In Europe, the Adriatic LNG terminal in Italy, Fos Cavaou in France, South Hook in Wales, and Dragon LNG in the United Kingdom began operation in 2009, adding more than 1.1 tcf of annual capacity. Phase 2 of the South Hook facility should come on-stream in the spring of 2010.
In the United States, ExxonMobil’s 2-bcf/d Golden Pass terminal at Sabine, Texas is due to come online in the second half of 2010, bringing LNG from Qatar. The first of two 450-mmcf/d expansions at El Paso’s Elba Island, Ga., LNG terminal is due for completion in mid-2010. Terminal capacity is hardly a restraint to U.S. LNG imports. The existing nine U.S. terminals used, on average, about 12 percent of their 3,900 bcf of capacity in 2009. Declining demand for LNG imports in the U.S. led both Sabine Pass LNG, La., and Freeport LNG, Texas, in 2008 to request authority to re-export LNG. DOE granted their requests for a period of two years.
Stocks
Working gas in underground storage in the continental United States at the end of 2009 was 3,123 billion cubic feet. This was 286 bcf higher than the same period in 2008 and 316 bcf or 11 percent above the five-year average, despite above-normal withdrawals the final week of 2009 due to colder weather. Gas storage exceeded 3800 bcf throughout the month of November.
Pricing
Like oil prices, natural gas prices peaked in mid-2008 and dropped throughout the rest of that year. But unlike oil prices, which then turned up throughout the spring of 2009, leveling at $70-80 per barrel for the second half of 2009, gas prices continued to drop. Weekly futures prices for gas peaked at $13.46/MMBtu in early July 2008 and then steadily declined to less than $6 per MMBtu in 2008. The crash continued in 2009 with prices bottoming at less than $3/MMBt in August. Prices did not significantly recover, topping $5/MMBtu, until the second week of December 2009. With significantly colder weather in January, prices approached but did not reach $6/MMBtu at Henry Hub.
For 2010, the EIA projects less volatility in Henry Hub spot gas prices than in 2009, with prices moving between $5 and $6 per MMBtu and averaging $5.17 for the year, ultimately rising to an average of $5.65 in 2011.
While both oil and gas prices suffered from the recession, the link between oil and gas prices appears permanently broken. Unlike in Europe and Asia, where imported natural gas prices are linked to oil, although with a six- to nine-month lag, in the U.S. gas imports compete against domestic gas. The sharp increase in domestic gas production—led by the boost from shale gas discoveries—combined with weakened demand, especially in the industrial and commercial sectors, has led to a growing divergence. The traditional rule of thumb—based on energy equivalence—was that oil prices per barrel were about six times natural gas prices per million British thermal units. Thus, with natural gas prices at about $6/MMBtu, one would expect oil to trade at roughly $36 per barrel. As the graphic illustrates (converting oil prices to MMBtu equivalents), this relationship held very strongly through 2006, comparing the U.S. average acquisition cost for oil to the average annual price for natural gas. The far lower U.S. price for gas, compared to oil—and thus to European and Asian LNG imports—has made the U.S. the last choice for LNG exporters since 2006.
This divergence between oil and gas prices led several European gas importers to suggest last year that it was time to revise their long-term gas contracts with Russia and other suppliers to make gas more competitive with other fuels, including spot market gas. In mid-February 2010, Paolo Scaroni, CEO of Italy’s Eni SpA, announced that Eni had reached an agreement with Russia’s Gazprom OAO to make contract gas import prices more flexible. At the same time, in a press conference, Gazprom Deputy Chairman Alexander Medvedev reported said that while Gazprom had renegotiated its European gas contracts to take “into account the trends in the European market and the [economic] crisis,” that the “base principles” of the long-term contracts remained.
Conclusion
When we look back, we may consider 2009 to have been a watershed year in global and U.S. gas markets. The huge surge of U.S. shale gas production fundamentally changed perceptions of U.S. gas supply prospects and may alter future gas production prospects in Europe and Asia as well. The combination of rising shale gas production in gas-importing countries with a glut of capacity in LNG exporting countries finally may break the long-term, oil-linked pricing model for pipeline gas and LNG export contracts, one that has been maintained since the 1970s. Finally, more attractive gas pricing, along with increasing pressure to lower greenhouse gas emissions, could boost gas markets in the industrial, power and even transportation sectors worldwide.
Analysis by Abraham Energy Report Contributing Editor Robert S. Price