India Backtracks on Gas Price Rises

After India’s previous Congress Party-led government broke the decades-long tradition of holding natural gas prices way below market levels, the newly elected Modi government now is reviewing that courageous, if partial, step toward market pricing.  (For details on prior deal, see below "China, India Raise Gas Prices, Part 2--India," July 29, 2013.)

India has long set energy prices below market levels. This policy resulted in two predictable effects:  significant energy shortages and huge government deficits. Gas demand in India is expected to hit 450 million cubic metres per day by fiscal 2015-16 (starting next April 1), with domestic production of less than 120 mmcm/d and projected imports of 170 mmcm/d, leaving a gap of more than 160 mmcm/d (5.7 bcfd).   The International Energy Agency estimates that India’s subsidies just for oil products jumped from $11.5 billion in 2009 to $30.9 billion in 2011.  In the same period, subsidies for natural gas--a much smaller market--varied from $2 to $3 billion annually.

Despite the environmental and energy security advantages of natural gas in India, gas represents less than six percent of total primary energy requirements.  (Coal, mostly produced domestically, accounts for 45 percent.)  The Government of India provides its fertilizer and petrochemical industries not only subsidized prices for gas, but also priority allocations.  In 2007, these two industries consumed more than two-thirds of all gas used, but the growth of gas-fired power plants dropped that share to about half by 2012.

The rise of gas-fired power rested on hopes for Reliance Industries Ltd.’s (RIL) production from its giant offshore Krishna-Godavari D6 block.  RIL had projected output of 27 million cubic metres per day by 2010, but it has repeatedly failed to reach targets. (In 2011, BP bought a 30 percent stake in the field for $7.2 billion.)  Last year, with KG-D6 producing only 14 mmcm/d, the government’s allocation priority to the fertilizer industry meant that the allocation for power plants, which was cut from November 2011, was completely eliminated. At the time, curtailments to the 18.7 gigawatts of gas-fired power units were estimated at two-thirds of their needs, with an additional 8 GW of capacity nearing commissioning.  Refineries, steel plants, liquid petroleum gas plants and even city gas supplies also faced allocated natural gas cuts. Not all gas supplies are subject to government allocation, exceptions being mainly for imported gas.

In June 2013 the Union (central) Government announced a decision by the Cabinet Committee on Economic Affairs (CCEA) to approve pricing of domestic natural gas at an overage cost of imported liquefied natural gas (LNG) into India and international gas hub rates.  The new formula was to have come into effect on April 1, 2014, with an expected price about US$8.40 per million British thermal units (MMBtu) or double the current price in India. 

With national elections called this past spring, India’s election authority in March ordered the Ministry of Petroleum and Natural Gas to hold off on the scheduled April 1 gas price increase until after the new government took power.  The Bharativa Janata Party won a decisive victory over the Congress Party and Narendra Modi became Indian Prime Minister.

In late June, the new Government’s CCEA announced a three-month deferral of the scheduled gas price increases.  Share prices of Indian producers immediately dropped:  RIL by 3.7 percent, Oil and Natural Gas Corp. by 5.8 percent and Oil India Ltd. by 2.8 percent.  Late last month, the government established a panel of secretaries (senior civil servants) from four ministries:  Expenditure, Power, Fertilizer, and Petroleum & Natural Gas.  The panel will examine gaps in the “Rangarajan Formula,” the basis for the delayed increase, including use of heat value vs. volume, weighting of prices in the formula, assigning different prices based on exploration risk and difficulty, etc.  Once the panel consults with affected parties, it will offer its recommendations to the central government.   MPNG Minister Rajya Pradhan promised Parliament the government would present a new gas pricing formula by Sept. 30.

During more than a decade as Chief Minister (governor) of India’s western state of Gujarat, Modi and the BJP gained a reputation for favoring “development over the dole” and being more business-friendly than the Congress Party. Modi’s focus on industrialization and export-promotion in Gujarat may have led to unreasonable expectations when he moved from Gandhinagar to Delhi and from leading 62.7 million (a bit less than the combined populations of California and Texas) to 1.27 billion (nearly four times the U.S. population. 

Modi’s first Union (national) budget, presented in July, was panned by many as disappointing and lacking the vision of Modi’s campaign.  It did propose building 15,000 kilometres (9,375 miles) of pipelines to complete the national gas grid.  It also emphasized the reduction of fuel subsidies, but provided no details.  Thus, the recommendations of the intra-ministerial committee on natural gas pricing—and the Government’s response--may reveal how far Modi and the BJP are willing to move toward market pricing and away from continuing energy subsidies.

China to Raise Some Natural Gas Prices

China's National Development and Reform Commission announced a more than 20 percent increase in natural gas prices for commercial and industrial users as of Sept. 1, along with removing price controls on imported liquefied natural gas, shale gas and coal bed methane.  The NDRC has a difficult balance to strike between allowing prices to rise sufficiently to encourage expanded domestic gas production and gas import projects, while keeping prices low enough to expand demand to meet environmental goals.  Full story on China's gas prices changes and strategy here.

China Slashes Shale Gas Target

Reuters, citing a Chinese website, reports that China has dropped its target of 60-80 billion cubic metres of shale gas production in 2020 to only 30 bcm.  A likely boost for China's LNG import requirements.  Full story here.

Big Gas Find in China

      As an update to my Nov. 5, 2013, article "China Steps on the Gas," in The Abraham Energy Report, note that UPI yesterday ran a story of a major natural gas find in China's Sichuan Basin.  China National Petroleum Corp. claimed that China's Land and Resources Ministry had verified technically recoverable reserves of one trillion cubic feet of gas at CNPC's Anyue gas field.  First phase production of the field is targeted to reach 140 billion cubic feet (3.96 billion cubic metres) per year.  The full UPI article is available here.

China Shale Gas Resources Redux

-->

Re the June 25, 2012, article below, “Shale Gas Resources Drop, China Next?”, the U.S. Energy Information Administration has lowered its estimate of China’s shale gas resources by 12.5 percent.  The EIA June 2013 Technically Recoverable Shale Oil and Shale Gas Resources, a revision of its April 2011 study, lowered China’s shale gas TRR to 1,115 trillion cubic feet (TCF~31.6 trillion cubic metres) from 1275 Tcf in 2011.  The EIA analysis, performed by Advanced Resources International, Inc., summed new estimates for the Sichuan (626 Tcf), Tarim (216 Tcf), Junggar (36 Tcf) and Songliao (16 Tcf) basins with 222 Tcf from smaller, more structurally complex Yangtze Platform, Jianghan and Subei basins. 

EIA based its revision on “…better information regarding the total organic content and geologic complexity … of the shale gas resource in the Qiongzhusi formation in the Sichuan Basin and Lower Cambrian shales in the Tarim Basin. The Qiongzhusi Shale gas resource estimate was reduced from 349 trillion cubic feet in the 2011 report to 125 trillion cubic feet in this report. The lower estimate resulted from the prospective area being reduced from 56,875 square miles to 6,500 square miles. Similarly, the prospective area of the Lower Cambrian shales was reduced from 53,560 square miles in 2011 to 6,520 square miles in the current report, resulting in a reduction in the shale gas estimate from 359 trillion cubic feet in 2011 to 44 trillion cubic feet now.”

While noting the country-wide shale gas development problems in China of complex geology, limited technological and equipment services, water resource constraints and lack of infrastructure, the EIA observed that the Sichuan basin—which holds more than half of China’s shale gas TRR—has existing pipelines, abundant surface water supplies and close proximity to major municipal markets.  In June, China National Petroleum Corp. (CNPC) commenced construction of the country’s first dedicated shale gas pipeline.  The 92.8 kilometre (57.7 miles) conduit will link Changning block gas wells to an existing gas pipeline that connects with neighboring Yunnan Province.  The new pipe’s designed capacity is 4.5 mmcm (159 mmcf) per day.

EIA’s estimate of China’s technically recoverable shale gas resources still exceeds those of China’s Ministry of Land Resources, noted in the article below.  Further, the EIA/ARI report emphasizes that future exploration and development drilling in China will affect shale gas TRR estimates, and could increase these appraisals.  So while China’s early targets for shale gas production of 6.5 bcm in 2015 and 60-100 bcm in 2020 appear unrealistic, China continues to possess by far the world’s largest shale gas resources.  This resource endowment, combined with recent increases in producer prices for natural gas (see July 16 article below) and a government commitment to reduce the growth of emissions from energy consumption, holds hope for the long-term future of shale gas development in China.

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

-->

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.

Shale Gas Resources Drop, China Next?

            The U.S. Government today nearly halved its estimate of U.S. shale gas resources.  This follows an even more drastic decline in Poland’s shale gas resources by its national geological institute.  As China starts serious drilling of its shale gas resources, will its optimistic resource assessment also drop?

            In April 2011, the Energy Information Administration of the U.S. Department of Energy released World Shale Gas Resources:  An Initial Assessment of 14 Regions Outside of the United States. That ground-breaking study suggested that global shale gas technically recoverable resources (TRR) of 6622 trillion cubic feet (tcf) roughly equaled global proved natural gas reserves.  TRR clearly is a more speculative measure than proved reserves, which define known gas that can be economically produced with current technology.  Still, the TRR figure firmly established global shale gas as a worldwide energy sector game changer.

            World Shale Gas Resources crowned China as king with 1275 tcf of TRR, followed by the U.S. with 862 tcf, Argentina with 774 tcf, and Mexico at 681.  The study found the largest shale gas resources in Europe in Poland (187 tcf) and France (180 tcf).

             In its 2012 Annual Energy Outlook, released today (June 25), the EIA lowered its estimate of U.S. shale gas TRR to 482 tcf—a 44 percent decline.  The fall resulted largely from a 67 percent drop in EIA’s estimate of TRR in the 100,000 square mile Marcellus shale that spreads across eight states from Tennessee to New York, but with most drilling in Pennsylvania and West Virginia.  (New York imposed a moratorium on shale gas exploitation, pending an environmental assessment.)  EIA followed a revision by the U.S. Geological Survey of the Marcellus shale.  EIA emphasized that further drilling could result in a future upward revision of resources and that the lower TRR does not directly correlate to projected production.

            The Polish Geological Institute announced its Assessment of shale gas and shale oil resources in Poland—First report on March 21.  The PGI emphasized that the report should be considered only a conservative, initial estimate as it was based on 39 wells drilled between 1950 and 1990.  Still, Minister Piotr Woźniak, Poland’s Chief Geologist, noted that only 22 wells had been completed since 2010 and a mere 14 were planned for 2012, compared to the thousands drilled annually in the U.S.  The PGI estimated the most probable level of Polish shale gas resources between 346.1 billion cubic metres (12.2 tcf) and 767.9 bcm (27.1 tcf).  Even the high end of the range is 85.5 percent lower than EIA’s estimate in World Shale Gas Resources a year earlier.  Last week the Gazeta Wyborcza reported that ExxonMobil would abandon its shale gas exploration projects in Poland after test wells failed to produce commercial results.

            So back to China.  Already in March 2012, China’s Ministry of Land and Resources scaled back its estimate of the country’s shale gas TRR from 31 tcm (1095 tcf) to 25.1 tcm (886 tcf) based on its most extensive appraisal to date.  The MLR noted that the complicated geology of its shale gas reserves and the relative inexperience of its companies would make shale gas production difficult.  Others have cited China’s regulatory regime, including administrative (versus market) pricing of gas, the lack of pipeline infrastructure, and the fact that some of China’s large shale gas resources, such as those in Xinjiang, are in semi-arid areas, as potential impediments.  Nonetheless, the government of China has moved forward on leasing shale gas tracts.  China’s big three—China National Petroleum Corp./PetroChina, China National Offshore Oil Corp. and Sinopec—all have purchased North American shale gas assets to learn the technology and have brought in Shell, Chevron, BP and others to work Chinese basins.

            China’s current Five Year Plan calls for production of 6.5 bcm (230 bcf) by 2015 from 19 major shale gas regions across the country.  By 2020, China’s National Development and Planning Commission expects shale gas production to jump to between 60 and 100 bcm (2 to 3.5 trillion cubic feet). 

            Whether or not China meets its ambitious shale gas production plans, the U.S. and Polish cases suggest that further drilling in China may well mean further reductions in the estimates of China’s overall shale gas resource.

Japan Looks to U.S. for LNG

The devastating March earthquake and tsunami that struck Japan shut down local nuclear and other power plants and caused an examination of Japan’s other nuclear reactors. The nation then focused on finding alternate energy sources to generate power. Boosting oil- and gas-fired electricity represents the only “quick fix.”

Already by June, imports of liquefied natural gas (LNG) by Japan’s ten power companies soared 31 percent higher than in June 2010. This comes against a backdrop of falling LNG imports from Indonesia, as production declined from fields that feed its old LNG plants such as Arun and Bontang, which provided the core of Japan’s LNG imports. In addition, the Indonesian government now reserves more new gas production for domestic consumption. Coincidentally, China and India, newcomers to the LNG business, increased their LNG imports by about 25 percent in the first half of 2011 over 2010.

The need for new and incremental LNG has led to several actions in Japan. First, as noted above, Japan’s power companies are aggressively seeking available spot LNG. This pushed spot LNG prices over the last few months from about $12 per million British thermal units (MMBtu—roughly equivalent to 1000 cubic feet) to $17/MMBtu. A Merrill Lynch report sees LNG prices rising to $25/MMBtu next year if Japan’s nuclear power stress tests prevent reactors from reconnecting to the national grid. Even if 5 gigawatts of nuclear power return next year, Japan will be shopping for an additional 4.8 million tons of LNG, according to Merrill Lynch.

Second, Japanese firms can invest abroad in gas production that could be exported to Japan. Even before the March catastrophe, Japan’s trading companies had bought into North American shale gas production. In 2010, Mitsui took a nearly one-third stake in Anadarko Petroleum’s Marcellus shale holdings; Sumitomo bought into both Marcellus East Coast and Barnett, TX, shale prospects; and Mitsubishi purchased half of Penn West’s British Columbia production. Despite a change in national leadership, Japan also has reverted to the Liberal Democratic Party past of “guiding” Japan Inc. via the Ministry of Economy, Trade and Industry. METI, through the Japan Oil, Gas and Metals National Corp. (JOGMEC), now will provide financial support to private Japanese corporations for overseas LNG exploration and development, according to a Denki Shimbun article. JOGMEC was created after the Japan National Oil Corporation was abolished, following a finding that decades of Industry Ministry funding for overseas oil and gas e&p had proved ineffective. Perhaps METI feels pressure from the increasing neo-mercantilist overseas ventures of China’s and India’s state-owned oil and gas companies.

Finally, a key potential source to meet Japan’s gas needs is LNG from the United States. In the midst of Japan’s travails, Conoco Phillips and Marathon closed down the only U.S. terminal supplying LNG to Japan. Last year they obtained an extension of their operating permit for the 40-year-old Kenai, Alaska, plant through 2013, but sent their final LNG shipment to Japan in March 2011. (In the 1980s, Japan’s government and utilities repeatedly rebuffed U.S. government pleas to support Alaska’s much larger proposed Yukon Pacific LNG project.)

Less than a decade ago, the U.S. sought to build more terminals to import LNG, as it forecast dropping pipeline gas imports from Canada and falling domestic production. But the surge in U.S. gas production from shale gas stood the market on its head.

New and old American LNG import terminals have requested U.S. government approval to either re-export LNG imports that are not needed in the U.S. market or to export U.S. gas. These include Cheniere’s Sabine Pass, LA; BG Group’s Lake Charles, LA; Dominion’s Cove Point, MD; and Freeport LNG, TX.

Prior to last week’s Asia-Pacific Economic Cooperation Transportation and Energy Ministerial conference in San Francisco, METI officials had asked the U.S. Energy Department to agree to a statement supporting U.S. LNG exports to Japan. DOE declined because in the U.S., the private sector, and not the government, develops and markets energy resources.

Still, Japan’s need for LNG presents a unique opportunity for U.S. firms. Operators of U.S. LNG receiving terminals can re-export unneeded LNG supplies to Japan over the next few years and use this time to lock in long-term LNG export deals with Japan that could fund converting their LNG terminals from import to export facilities. By 2015-16 the first of these American LNG export terminals could be exporting LNG under long-term contracts to Japan and elsewhere. Working with U.S. terminal owners, U.S. shale gas producers could find overseas markets for their gas that would lift the currently low gas price of about $4/MMBtu they receive in the U.S. closer to Asian prices four times higher. Chesapeake Energy, one of the top U.S. shale gas producers, already last year signed an MOU with terminal operator Cheniere Energy to explore exports. Dominion’s terminal in Maryland would provide a convenient outlet for Marcellus shale gas.

Clearly, sizable, long-term U.S. exports of LNG to Japan could provide sizable mutual benefits.

(Disclosure: I own stock in several U.S. gas producers, including Chesapeake.)

Japan Disaster to Spur Asian Shale Gas

The Financial Times Monday noted that as Tokyo Electric Power Co. (TEPCO) lost 9,700 megawatts of nuclear power from Friday’s earthquake and tsunami—nearly 20 percent of Japan’s total electricity generating capacity—British LNG (liquefied natural gas) import prices spiked 12 percent. Even if Japanese authorities do not shut down other nuclear facilities, the loss of these facilities means Japanese electric utilities will have to find additional oil, coal and LNG to generate power. Perhaps for an extended period.
An earthquake at TEPCO’s Kashiwazaki-Kariwa nuclear plant in July 2007 forced a nearly two-year-long shutdown, sending TEPCO scrambling to increase its purchases of crude, fuel oil and LNG. While the 2008 recession lowered TEPCO customer power demand in 2009, the 2008 spike in world oil prices greatly boosted the price of crude, fuel oil and LNG, which in Japan’s contracts is linked to oil. The additional annual cost for these fuel purchases was estimated at the time at more than 70 billion yen (US$ 900 million).
China and India have just begun major LNG import programs. Since 2006, China has constructed four LNG receiving terminals, pushing LNG imports to nearly 10 percent of total Chinese gas supplies. Chinese companies are building another four terminals, and several more are under consideration, as are expansions of existing terminals at Shenzen, Fujian and Shanghai. Shell and Petronet operate LNG receiving terminals in India’s Gujarat State. Additional terminals at Dahbol and Kochi are expected on stream in 2011 and 2012, with plants and Ennore, Mudra, Mangalore and Dighi Port possible.
Both China and India also have stepped up their pursuit of domestic shale gas. State-owned China National Offshore Oil Corp. and PetroChina have made mutli-billion dollar buys of shale gas properties in Canada and the U.S. India’s privately owned Reliance Industries has purchased substantial shale gas assets in the Marcellus and Eagle Ford shale gas basins in the U.S. Additionally, both China and India have begun to explore their domestic shale gas resources and plan to auction domestic shale gas leases this year.
China and India both control the price of domestic natural gas—well below the current LNG import price. A step increase in LNG import prices, caused by TEPCO’s sudden and sustained need for alternative generation fuels, will force both China and India to reconsider LNG's role in their energy mix and propel both to accelerate their domestic shale gas programs.

New Website for Asia Experts

Expertise in the field of contemporary Asian affairs is just one click away with the new online resource AccessAsia (Beta), a free specialized search engine that includes thousands of links to websites of Asian affairs experts. Whether you are seeking expert perspectives on nuclear proliferation in North Korea, scholars on maritime policy in the Malacca Strait, or further insight on Japan's upcoming upper house election, AccessAsia is your #1 source for expertise. The National Bureau of Asian Research in Seattle created this site and, I am pleased to announce, has selected me as one of its experts. To find Asia experts or nominate someone as an Asian expert for the site, click here.