China, India Raise Gas Prices. Part 2--India.

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On June 27, the Government of India 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 comes into effect on April 1, 2014, at which time the price is expected to be about US$8.40 per million British thermal units (MMBtu) or double the current price.

The new pricing formula for each quarter will be calculated based on the 12-month trailing average price, with a lag of one month.  This means that the price for April through June 2014 will be calculated on the 12-month averages ending Dec. 31, 2013.  The newly approved gas pricing formula will be in effect for five years.

The impact of the natural gas price rise in India will differ greatly from a gas price hike China announced at about the same time: 

1.  Although both countries came to a similar price, in China the new price represents a 15 percent raise vs. a doubling in India.

2.  China’s gas price change was effective July 10, while India’s will not bite until April 1, 2014.

3.  While China consumes two and one-half times more gas than India (146 billion cubic metres vs. 55 bcm in 2012—BP), gas represents a larger share of total primary energy requirements in India (8.5%) than in China (4.8%)(BP:2012).

4.  Sectoral use of natural gas varies widely, with China using nearly 30 percent of its gas in residences and India nearly none.  In contrast, China’s non-energy use of gas (primarily refining and petrochemical production, especially fertilizers) amounted to 17 percent compared to 59 percent in India, where gas for fertilizer production is steeply subsidized (IEA:2009).  Finally, gas use in the electric power sector is minimal in China, while gas represents some 10 percent of India’s installed power capacity.

Although the decision to raise Indian wholesale gas prices was taken by the CCEA and not just the Ministry of Petroleum and Natural Gas (MPNG), other ministers lost no time in objecting.  The Ministry of Finance noted that Reliance Industries, Ltd. (RIL), led by Mukesh Ambani, had produced from its KG-D6 offshore gas field well below target and should have to sell targeted production, as well as the cumulative shortfall, at the old $4.20/MMBtu price.  MPNG head M. Veerappa Moily rejected the Finance Ministry critique, noting “There is no confusion; there is no vagueness.  And I don’t think there is scope for any interpretation whatsoever.”  India’s Planning Commission had been pushing for such a gas price boost for two and one-half years.

The Indian Power Ministry already called a meeting with the states and other stakeholders to seek suggestions on easing the impact of the proposed gas price jump.  The Power Ministry also has questioned setting the price in U.S. dollar terms, as that adds volatility given the depreciation of the Indian rupee (Rs).  Finance Minister P. Chidambaram has reassured the power and fertilizer sectors, which receive state-set allocations of natural gas at subsidized prices, that their concerns would be addressed before the price increase takes effect next year.

The power industry has borne the brunt of the production collapse at RIL’s Krishna-Godavari fields from nearly 70 million cubic metres of gas per day (2.4 billion cubic feet per day) in 2010 to some 14 mmcm/d recently.  RIL had committed 29.7 mmcm/d of KG-D6 gas production to 25 power plants, but in Nov. 2011, their allocation was reduced and in March 2013 cut off completely.  A July 18 meeting of the Empowered Group of Ministers, led by Defence Minister A.K. Antony, rejected an Oil & Gas Ministry proposal to abolish the priority ranking and instead confirmed the priority for the fertilizer industry, then liquefied petroleum gas production, power, and city gas.  Practically, this means that unless RIL can turn around KG-D6 production, only the fertilizer industry will be supplied with Krishna-Godavari gas. 

Currently only one-third of the 72 mmcm/d needed for the 18.7 gigawatts (GW) of gas-based power plants throughout India is being met; a further 8 GW of capacity is nearing commissioning without firm gas supplies.  Oil Minister Moily has urged the EGoM to explore other gas supply options for the power sector, including using uncontracted volumes produced by state-owned Oil and Natural Gas Corp. 

An analysis by Bank of America Merrill Lynch, reported a week after the CCEA gas price decision, suggested that the Government of India will collect some Rs 13,000 crore (US$ 2.2 billion) in higher taxes, royalties and dividends, particularly from state-owned gas producers ONGC and Oil India Ltd. (OIL).  Privately-owned RIL would pay about 10 percent of the increased central government revenues.  The analysis opined that much of the additional government revenue from the higher gas price would be funneled into subsidies to protect sectors such as fertilizer and power.

If the government keeps the cost of natural gas to the fertilizer industry unchanged, CRISIL (Credit Rating Information Services of India Limited)

estimates that, even after receiving the higher tax and royalty payments, the central government will lose an additional net Rs 2000-2500 crore (US$335-420 million) for subsidies just for the fertilizer sector.  During 2009-2011, Indian government subsidies for natural gas have varied from $2-3 billion.  This pales in comparison to oil subsidies, which leaped from $11.5 billion in 2009 to $30.9 billion in 2011 (IEA).

The higher natural gas prices should improve the incentive for exploration and development of domestic natural gas in India by domestic private and public companies, as well as foreign firms.  Repeated delays in formulating government policy on shale gas development have kept India from conducting its first shale gas tract leases, unlike China, which conducted its first shale gas bid round in June 2011 and its second in 2012 with 19 blocks awarded in January 2013.  This may not impact India dramatically as it has relatively modest shale gas resources of 2,718 bcm (96 tcf), compared with China, the global leader with 31,573 bcm (1115 tcf USEIA:2013).

The government decision to double natural gas prices represents nothing more than a belated nod to reality.  India increasingly must turn to imported LNG to meet growing, and still not fully satisfied, demand for natural gas.  Indian domestic gas production rose from 27 bcm in 2002 to 51 bcm in 2010, only to fall back to 40 bcm last year.  It commenced imports of LNG in 2004 and reached 20.5 bcm in 2012 (BP), making it the world’s fifth largest LNG importer.  Average prices of imported LNG run some $11-12/MMBtu or three times the current regulated natural gas price in India. 

The disconnect can be seen in the failure of Petronet LNG’s new terminal in Kochi to sign up customers.  The Rs 4200 crore (US$700 million) terminal, due to start operation next month, will initially operate at less than 10 percent of its 5 million tons (6.75 bcm) per year capacity.  Gas Authority of India, Ltd. is seeking renegotiation of its 1.5 MMTY deal for LNG from Australia’s Gorgon project, scheduled to start delivery to Kochi in 2015, as the cost delivered to GAIL customers could approach $17/MMBtu under the current contract.

On the demand side, the continuing subsidies for natural gas use in the power and fertilizer sectors will increase the already significant burden on the central government budget deficit.  Union and state governments in India share a constant concern over feeding the population and an attitude that power—when and where it’s available—should be a “free good,” especially in the agricultural sector.  With these political pressures, it will be difficult to restrain, less alone reduce, gas price subsidies and government volume allocations.   Ironically, this will only expand the gap between notional demand for gas in India and available supply; continue curtailed and unreliable electric power; and maintain coal as the dominant and most polluting fuel.  The timing of elections for the Union Parliament—May 2014, the month after the natural gas price rises—makes these issues even touchier.

India has taken an important step to bring its domestic producer prices of natural gas closer to world levels.  The next important step, admittedly a much more difficult one, is to increase the natural gas price for domestic consumers.

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.

2013 Oil Market Outlook

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From Jan. 2012 oil outlook: “…Barring a major issue with Iran, which could send prices to $150 and above, prices should ratchet up slightly to track between $85 and $120 per barrel (WTI), averaging $105-110.”  Clearly too bearish--average actual WTI 2012 was about $94, with a weekly average range of $80 to $108.

 

  

For 2013, What the ‘pros” say:

USDOE.  EIA STEO Jan. 2013:  Brent and WTI crude oil spot prices to average $105 and $89.5 per barrel, respectively, in 2013. The projected WTI discount to Brent crude oil, which averaged $23 per barrel in November 2012, falls to an average of $11 per barrel by the fourth quarter of 2013.

Reuters’ annual survey of 26 analysts showed an average forecast of $108 for Brent in 2013, down from $112 in 2012, and WTI at $94.  Four put 2013 Brent above $115 in 2013, including Goldman Sachs, who calls for Brent at $130 and WTI $126, as capacity on the Seaway pipeline hits 400,000 b/d.

Upside Factors

Middle East

Iran.  Nuclear program--US, Europe sanctions; Iranian interference with Straits of Hormuz; this year Iran’s program could reach the point of triggering Israeli a/o U.S. military response.

Iraq, Syria and Egypt all placing strains on relations among ME countries and between them and the U.S.  Pipeline sabotage plagues Yemeni production and Syrian production unlikely to stabilize soon.

Global demand. The IEA sees continued sluggish demand in 2013, rising .865 mmb/d to 90.5.  Demand up .85 mmb/d in 2012 (vice 1.3 projected).

   Turnaround in economic growth rate could boost oil demand in China, the world’s 2d largest consumer.  India, Russia, Saudi Arabia and Brazil follow Japan in oil consumption and will see 2013 oil demand grow 2.5 to 4.5%, the IEA forecasts, as Japan’s demand slumps more than 3%. 

     The U.S. remains by far the world’s largest oil user at >18 mmb/d. 2013 oil demand growth >0.5%, mostly on freight shipments and industrial use.

Dollar. A declining U.S. dollar in 2013 will tend to push up oil prices. 

   Both U.S. economic growth and the dollar’s value are tied to resolution of long-term U.S. debt issues, but with opposite effects.

Downside Factors

Europe.  Demand in 2012 contracted sharply, -6.0% in 3Q12.   In 2013, European oil demand will decline less rapidly, weighted to the first half. The IEA also foresees North Sea oil output declining some 0.18 mmb/d.

MENA.  Increasing production by Libya and Iraq would depress prices, but Saudi will offset.  In Africa, a border security zone agreement between Sudan and South Sudan continues to stall export resumption.    Iran returns…?  Iran could be an outlier on the downside:  if the June presidential elections in Iran bring it back to the negotiating table with the EU and US, both could reduce sanctions, thus putting up to 1mmb/d of Iranian oil back on the global market.

North America.  The IEA expects a robust jump of 0.35 mmb/d in Canadian oil production, based on increased output from oil and tar sands.  Higher production in the U.S., mostly from tight oil and shale oil formations, will add 0.5-0.9 mmb/d, dropping U.S. liquid fuel imports to less than 40% of consumption for the first time in more than two decades.  Put simply, the US and Canada are likely to increase oil production in 2013 more than the total rise in global oil demand.

My Call

Once again, the outlier is Middle East politics.  Based on market fundamentals, oil prices should be less volatile in 2013.  WTI should trade in a narrower range of $80 to $100 per barrel, rising throughout the year, with an average a bit above $90.  Brent ends year at about $115.

©  Robert S. Price Jr., International Risk Strategies, Tampa, FL Jan. 2013 (Originally presented to the Longboat Key Economic Roundtable.)

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.)

Shale Gas Opportunities for US Independents in China?

Toshi Yoshida, corporate and energy partner at the law firm of Mayer Brown LLP, recently told E&P Online that China's shale gas development holds significant opportunity for U.S. independents who have extensive experience in developing America's shale gas resources. Read here.
I would caution that there are significant risks in such ventures: First, energy is a "strategic sector" in China so that foreign participation is curtailed. Note that so far no foreign companies have been allowed to bid on shale gas lease auctions in China, even as minority partners to Chinese firms. There have been suggestions that this might change, but still with foreign companies as minority partners. Second, Chinese hypersensitivity in this sector was amply demonstrated by the imprisonment of U.S. geologist Xue Feng for espionage for acquiring Chinese geophysical data that anywhere else would be considered purely commercial. Third, China's new regulations have increased pressure on foreign firms to provide Chinese partners with proprietary technology as a requirement of market entry; and China's long-standing failure to protect intellectual property is well documented. Finally, as the recent Yahoo-Alibaba/Alipay case demonstrated, dealings with a Chinese partner may be less than transparent and foreign partners cannot expect protection under the Chinese legal system. So I would strongly suggest that U.S. independents carefully weigh the considerable risks against any possible rewards before investing their capital (financial or intellectual) in China. [Disclosure: I own stock in Chesapeake Energy and Devon Energy.]

Interior Cancels Exxon Lease

Further to my previous post, the U.S. Interior Dept. finally decided to enforce their own rules over using leases and cancelled an Exxon Mobil lease that the company now is suing to get back, after revealing that it may contain huge resources. See Bloomberg article here.