China, India Raise Gas Prices...Who Wins, Who Loses? Part 1

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In June, the Governments of both China and India raised administered prices of natural gas to enhance domestic production of the environmentally desirable fuel and to decrease losses to state gas producers.  In India’s case, the changes do not take effect until the next fiscal year, beginning April 2014.

For both countries, the price increases are limited to certain sectors and their beneficial effects will be constrained by the web of governmental controls over the energy market.

This article examines the impact in China; a subsequent article will look at Delhi’s decisions.

China still relies on “King Coal” for two-thirds of its primary energy supplies and more than four-fifths of its electric power inputs (IEA:2009).  Recognizing the damage that coal-related pollution causes, the Government since 2000 has set goals to grow natural gas’s share in total primary energy use from two percent, to less than five percent at present, to eight percent in 2015 and 10 percent in 2020. 

Despite success in boosting domestic natural gas production from some 32 billion cubic metres (bcm) in 2002 to more than 107 bcm in 2012 (BP:2013), China turned to imports of liquefied natural gas (LNG) starting in 2006 from Australia and pipeline gas in 2009 from Turkmenistan (via Kazakhstan and Uzbekistan) to meet demand.  The Turkmen pipeline reached full capacity of 40 bcm annually last year ßand the contract was increased to an eventual 65 bcm/y.  A 2006 agreement to import 60-80 bcm/y of pipeline gas from Russia has foundered on failure to agree on pricing.  China has added Indonesia, Malaysia and Qatar as long-term LNG suppliers to its five receiving terminals, and has additional terminals planned and under construction.

China also boasts the world’s largest shale gas resources, but already has abandoned its target of 6.5 bcm of shale gas production in 2015 in the face of difficult geology, a lack of pipeline capacity, a steeper learning curve on the technology of shale gas exploration and development, and serious water constraints (hydraulic fracturing, which made the shale gas revolution in the U.S. possible, uses vast quantities of water).

The problem is pricing.  China paid $8.79 per million British thermal units (MMBtu) for pipeline gas imports from Central Asia in May 2013; $18.77 for Qatar LNG; $7.98 for Malay LNG; $3.87 for Indonesia; and $3.54 for Australia (Reuters).  In May 2013, China National Offshore Oil Corp. Ltd. (CNOOC), which holds a 13.9 percent stake in Indonesia’s Tangguh LNG plant, agreed to renegotiate the price it pays for LNG destined for CNOOC’s Fujian terminal.  It already agreed in 2006 to increase the price from $2.40 to $3.40 per MMBtu.  New Australian LNG projects will price their product based on oil vs. the promotional price provided for Northwest Shelf LNG to crack the China market back in 2006.

Arrayed against these rates, China’s price push seems puny.  The National Development and Reform Commission’s (NDRC) new natural gas wholesale price, which took effect July 10, represents a15 percent rise to a national average of 1.95 yuan per cubic metre (approximately $9.00/MMBtu).  The higher price does not apply to residential users who make up nearly 30% of China’s gas market and the NDRC announced at the same time it may increase subsidies for farmers, limit the price increase for natural gas feedstocks to fertilizer producers, and urge local governments to give temporary subsidies to drivers of natural gas-fueled taxis.  This means that the increase will fall on industrial and commercial clients, who make up half of China’s natural gas market.  Gas fires less than two percent of China’s power plants.

China’s gas producers certainly will welcome the new prices.  China National Petroleum Corp. (CNPC), the nation’s main gas producer and importer, reportedly booked losses of nearly $7 billion in 2012 by selling natural gas below acquisition cost. 

The NDRC faces a difficult quandary:  it wants to increase gas use, primarily to achieve environmental goals.  Higher prices will prod more domestic production, but higher prices also will stifle demand, especially in the face of continued low prices for coal.  Other than a pilot project in some southern provinces, which started in 2011, administered natural gas prices have not risen in China since 2010. 

The ideal solution would be for the government to move quickly to market pricing for all fuels for all sectors, but there is too much fear that such moves might stoke social unrest.  That explains the shielding of the residential sector, despite its large size and relatively inelastic demand (residential users cannot rapidly or easily switch heating fuels). 

Since a purely market solution is unlikely, again the NDRC will have to turn to economic solutions with Chinese characteristics.  The elements needed to boost natural gas use include:

1. Smaller, but more frequent (annual), natural gas price increases.
2. Application of gas prices increases to all users.
3. Allowance of full pass-through of gas price increases by intermediate users, e.g. electric utilities.
4. Regulatory or fiscal restraints on coal use and promotion of gas use, such as the requirement in Beijing prior to the 2008 Olympics that new apartment and office buildings be piped for eventual gas use.
5. Removal of the value-added tax on coal-bed methane and shale gas exploration and development.
6. More stringent, and more effectively enforced, emissions regulations on coal-fired power plants.
7.  Introduction of a carbon tax, which would impact coal more heavily than gas, although both emit carbon dioxide.

 The NDRC realizes that natural gas must capture a significantly larger share of China’s energy consumption to meet both environmental and energy security goals.  In the transition to more market-based pricing throughout the energy sector, the NDRC must use all of the economic and regulatory levers at its command to move the market toward a more sustainable energy future.