Japan Restarts Nukes, Resells LNG

As LNG Industry noted in a March 21 article, Japan's electric utilities are restarting nuclear reactors, following extensive technical and legal issues after the 2011 Fukushima disaster.   This will reduce their need for the coal, oil and liquefied natural gas supplies they substituted for idled nuclear power plants.  Kansai Electric Power Co. offered a contracted cargo from Australia Pacific LNG after the March 14 restart of its Ohi No. 3 nuclear reactor.  With several more reactors in Japan expected to resume service this year, the Asian price premium for LNG will erode as more contracted supplies are offered onto the spot LNG market.

India Shale Gas: Bring It on Home to Me

This year Indian firms and the government have switched their shale gas focus from abroad to home.  As one Indian firm sold some overseas assets, the government of India moved to make exploration and production of domestic shale gas and coalbed methane (CBM) more attractive.

North American Ventures

Over the last five years, Indian oil and gas companies, both private and state-owned, actively sought shares in North American shale gas plays.  The overseas investments served two purposes:  to gain experience with and access to cutting-edge shale gas exploration and development technology that they could use in India, and to line up potential LNG imports from the U.S. and Canada.

Mukesh Ambani’s Reliance Industries Ltd. (RIL) kicked off aggressive acquisition by Indian firms of U.S. shale gas assets in 2010.  In April of that year, RIL purchased a 40% stake in Atlas Energy’s Marcellus shale tracts in Pennsylvania, New York, etc. for $1.7 billion and followed in June with a $1.4 billion acquisition of 45% of Pioneer Natural Resources’ Eagle Ford, Texas, shale gas acreage.  In October, RIL spent nearly $400 million for a 60% share of Carrizo Oil & Gas’ Marcellus shale gas tracts.  A year later, state-owned Gas Authority of India Ltd. (GAIL) spent $95 million for a 20% share of Carrizo Oil & Gas’s Eagle Ford holdings.   State-owned upstream Oil India Ltd. combined with state-owned refiner India Oil Corp. in October 2012 for a 30% share of Houston-based Carrizo’s Niobrara shale gas in Colorado for $85 million.  Just a year ago, Indian Oil Co. took a 10% stake in British Columbia Montney shale assets owned by Malaysia’s Petronas.  In exchange, the Indian refiner gained guarantees of 1.2 million tons of liquefied natural gas for 20 years from Petronas’ B.C. LNG project.  The deal was valued at $1.1 billion.

In the face of sharply declining oil and gas prices over the past year, RIL and Pioneer Natural Resources last month announced the sale of Eagle Ford Midstream to Enterprise Products Partners for $2.15 billion.  The midstream operation comprises 10 gathering plants and about 460 miles of pipelines.  Since October 2014, Indian press reports have suggested that RIL, which has invested $3.9 billion in Eagle Ford exploration and infrastructure, seeks a buyer for its share of the project.  The continued fall in oil and gas prices since then, although recovered somewhat from lows earlier this year, have depressed the value of RIL’s asset.

Domestic Assets

India’s Cambay, Krishna-Godavari, Cauvery and Damodar Valley shale gas basins hold less than 100 trillion cubic feet of technically recoverable gas reserves according to a May 2013 study done for the U.S. Energy Information Administration.  By comparison, the same study ranked China first with 1115 tcf, the U.S. fourth with 665, and Brazil tenth with 245.  Still, that compares well with India’s 47 tcf of proved reserves of conventional natural gas, two-thirds of which are located offshore.

State-owned Oil and Natural Gas Commission (ONGC) began exploration of the Damodar Valley basin for shale gas several years ago, as it already had coalbed methane (CBM) operations there. ONGC and Gujarat State Petroleum Corp. both have drilled wells in the Cambay shale for oil and gas. ONGC also plans exploration of the Krishna-Godavari, Cauvery and Assam-Arakan basins and in 2012 signed an agreement with ConocoPhillips for joint exploration and development of shale gas in India and abroad.

Although there is adequate water for hydraulic fracturing in the Damodar basin, concerns about water constraints have delayed formation of national government policies for shale gas exploration and development.  In 2013, The Energy and Resources Institute (teri) of India, an international-renowned think tank, challenged the formation of government shale gas policy with a commentary “India: Water or Shale Gas?”

The impetus for greater shale oil and gas exploration in India remains strong.  Coal accounts for 45% of India’s primary energy supplies and 80% of electric power fuel inputs, with all of the attendant environmental degredation.  India relies on imports for one-quarter of its coal, 80% of its crude oil (partially offset by large oil product exports), and almost one-third of its natural gas.  If India’s domestic shale gas resources can be effectively tapped, this would provide significant environmental, economic and energy security benefits to the county.

Regulatory Changes

With these benefits in mind, in late June 2015, India’s Ministry of Petroleum and Natural Gas indicated that it was considering two changes to current policy to encourage shale gas and CBM exploration and development under the New Exploration Licensing Policy (NELP). 

The first change would permit companies to develop shale gas and CBM in oil and gas blocks for which they currently hold permits for oil or gas.  Current policy limits permits to either oil or gas.  A senior MPNG official observed that such expansion “…would come with a rider that all investment in the new exploration activity would be ring-fenced…” so that costs for shale gas exploration could not be combined with existing operations for cost recovery.  The present production sharing contract (PSC) terms allow companies to recover costs before paying the government a share of production revenue.

The second improvement would remove the current restrictions on blocks to either oil or gas, to allow exploration and production of any hydrocarbons found.  An official at state-owned Oil and Natural Gas Corp. noted that sometimes “…during exploration we find other natural resources than what we were actually looking for.  But the PSC doesn’t allow us to extract other resources.”

Further, over the last two years, India has moved toward more market-based pricing for natural gas, which would provide greater incentives for gas exploration and development.

On September 2, the Indian cabinet approved the auction of 69 marginal field currently owned by state companies ONGC and Oil India, shifting to a revenue sharing contract from the current profit sharing model.  A uniform license covering all hydrocarbons including shale gas, shale oil and CBM will apply to the auctioned fields.  The partially explored areas reportedly contain 89 million tons of oil and gas equivalent reserves and include onshore, shallow offshore and deep offshore tracts.

The extraordinary power of farmers and other land-holders to delay or eliminate industrial development in India remains a concern that was only heightened by Prime Minister Narendra Modi’s recent reversal on an executive order easing federal acquisition of land for infrastructure and industry and his decision to drop efforts to amend India’s tough land-acquisition law in Parliament.  Both steps appeared motivated by upcoming elections in the Bihar, an agrarian state, but could have fateful impacts on shale gas development.

ONGC efforts in the Cauvery Basin in Tamil Nadu State illustrate the tensions.  Farmers, environmental activists and political parties have demonstrated against ONGC’s development of shale gas reserves in Cauvery.  ONGC Director of Exploration A.K. Dwivedi was forced this month to explain that the company was not exploring for shale gas or CBM in the area, but only conducting research into the potential for shale gas.  ONCG still needs clearance from India’s federal Environment Ministry before doing any drilling in Cauvery, and even then would need state-level clearances.  Currently 31 wells in Tamil Nadu produce oil and some 110 million cubic feet per day of natural gas.

Conclusion

Lower gas prices in North America make Indian shale gas operations overseas less appealing, while shale gas developed in India will compete with much more expensive imported LNG.  Combined with a potentially more attractive regulatory regime, shale gas exploration and development in India could finally be reaching its launch.  The federal (Union) government in India will be key:  it needs to develop and execute national policies for exploration of shale oil and gas in India.  Further, as overseer of the state-owned hydrocarbons companies that dominate the Indian oil and gas sector, it must require more efficient and diligent efforts by ONGC, GAIL and others to define and develop national shale gas resources.

Iran Nuclear Deal: Implications for LNG

The nuclear deal Iran signed with the Permanent Members of the United Nations Security Council, including the United States, and Germany this month clearly could deepen a global oil glut, but what about the global gas market?

Iran has said it hopes to quickly double its oil exports from current levels to 2.3 million barrels per day.  U.N. sanctions increasingly starved Iran’s oil industry of capital, technology and export markets.  The lifting of sanctions could mean that foreign firms previously engaged in Iran’s oil sector could return.  Several of these firms reportedly have held discussions with Iranian oil officials over recent months.

Past LNG Plans

The sanctions stifled not only Iran’s oil industry, but also its gas development plans.  According to BP’s 2015 Statistical Review of World Energy, Iran holds the world’s largest proved natural gas reserves at 1201 trillion cubic feet, beating out the Russian Federation with 1153 tcf and more than triple the U.S. reserves of 345 tcf.   But Iranian production last year was 16.7 billion cubic feet per day compared with America’s 70.5 bcf/d and Russia’s 56 bcf/d.

In terms of liquefied natural gas (LNG), Qatar is the world’s largest exporter, using production from its offshore North Dome Field to sell 2.6 tcf in 2014.  The extension of that field in the Persian Gulf is what Iran calls the South Pars gas field.  Iran developed plans for a number of LNG export projects to exploit South Pars.  In Dec. 2007, Iran LNG Company Managing Director Ali Kheir-Andish told a Tehran International Oil & Gas Conference that his country would produce 22 million metric tons (1.1 tcf) in 2015, 44 MMT (2.2 tcf) in 2018 and about 88 MMT (4.3 tcf) in 2022, with first deliveries in 2010.

In fact, facing the grip of escalating sanctions, in 2010 Iran suspended development of all of its LNG projects:  Iran LNG (10.8 MMT or 525 bcf), Pars LNG (10 MMT or 485 bcf, previously involving France’s Total SA and then China National Petroleum Corp.), Persian LNG (16.2 MMT or 787 bcf, previously with Royal Dutch Shell and Spain’s Repsol), North Pars LNG (20 MMT or 970 bcf, with China National Offshore Oil Corp.) and Golshan LNG (10 MMT or 485 bcf, with Malaysia’s SKS Group).

Future Prospects

A number of factors mitigate against a rapid return to Iranian LNG development plans:

--Iran will focus on oil development and export as a quicker road to resuming hydrocarbon exports with a higher return.  In addition, some gas fields, including South Pars blocks 11, 13 and 14 were converted from LNG projects to inject gas into oil fields for enhanced oil recovery.

--Terms for foreign firms.  Iran already has hinted that it realizes it must offer better terms to attract foreign firms back to oil exploration and development in place of the prior buy-back contracts with short cost recovery times.  The same applies to gas development. 

--Domestic demand.   In addition to increased gas demand from the oil industry for enhanced recovery, domestic demand is artificially high due to highly subsidized gas pricing.  In 2011, then President Mahmoud Ahmadinejad raised prices some 10-fold from 40 cents per MMBtu. At the time, LNG fetched more than $12/MMBtu in Asia and $8/MMBtu in Europe.  Domestic natural gas prices still lag global LNG prices.

--Changes in markets.  Outside of the U.S., most LNG export contracts are priced with an indexation to global crude oil prices.  The drop in oil prices from more than $100 to less than $60 per barrel already will hurt Iran in terms of the revenue from stored crude and oil production over the next few years.  For LNG projects with price tags of $5 billion apiece and up, the margins on LNG, which has dropped in Asian spot markets from more than $12/MMBtu to less than $7/MMBtu, may be too thin.  In addition, since Iran started LNG planning 15 years ago, a huge growth in LNG supply projects planned and under construction in Australia and North America means that Iran will face a much more competitive market.

Conclusion

The world’s largest proved gas reserves make monetizing them an Iranian imperative.  Still, as Iran emerges from the sanctions regimes, it must prioritize spending and rank the best export earning alternatives.  This implies that oil exploration, development, production, refining and export will take the top spot in hydrocarbon sector spending in the short- to mid-term. 

LNG development in Iran can use the start from the 2001-2010 period in terms of project siting; allocation of specific field reserves to specific LNG projects; and discussions with foreign firms on financing, technology, project management, and marketing.  Nonetheless, Iran is unlikely to join the ranks of major LNG exporters for another decade.

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.

Iran Triggers MENA Nuclear Programs

The revelation a decade ago of Iran’s extensive nuclear program (uranium enrichment) led not only to the contretemps with Europe and the United States about whether the Iranian nuclear program was purely for peaceful purposes, but also triggered strategic anxiety among its Arab neighbors.  This strategic unease among Arab nations in the Middle East and North Africa (MENA) in turn led to several of Iran’s neighbors moving toward their own nuclear programs and also has created an opening for Russia to expand its influence in the region through assisting countries develop nuclear power, as it did with Iran.

At present, Iran is the only MENA country with an operating nuclear power plant:  The Bushehr 1, 1000-MWe VVER reactor built by Russia’s Atomstroyexport, after several delays, finally started full commercial operation last September.  In February 2014 the Atomic Energy Organization of Iran (AEOI) announced that construction by Atomstroyexport of a similar unit—Bushehr 2—would begin this spring.  In addition, Iran operates uranium mining, milling, conversion and enrichment facilities and a heavy water production plant. A heavy water research reactor is under construction at Arak.

Research Reactors

A number of other MENA countries have had long-standing nuclear programs, generally operating one or more very small research reactors to provide nuclear training and medical radioactive isotopes.  Algeria commissioned a 1-MW Argentine unit in 1989 and a Chinese 15MW research reactor in 1992.  Egypt started up a USSR-supplied Egypt with a 2-MW in 1961.  A number of scholar’s believe that Egypt’s Atomic Energy Establishment (AEE), during the regime of President Gen. Gamal Nasser, developed technology and training in nuclear weapons.  Egypt did not bring its USSR reactor under International Atomic Energy Agency (IAEA) safeguards until the 1980s.

History has shown such research reactors can be less benign.  Israel bombed Iraq’s French-built Osirak 40-MW research reactor in 1981, just prior to first fuel loading, out of concern that Iraq planned to use the reactor for nuclear weapons’ fuel.  In 1991, the U.S. bombed a Russian reactor at the same site in the opening of the Desert Storm operation.  This despite Iraq’s having been a non-nuclear weapon state (NNWS) party to the Treaty on the Nonproliferation of Nuclear Weapons (NPT) since 1969. 

Also, in September 2007, Israel bombed and destroyed what Israeli and U.S. officials claimed was a Syrian plutonium production reactor.  Syria denied the claim, but failed to provide full IAEA access to the bombing site.  In May 2011, the IAEA said “It is very likely that the building…was a nuclear reactor which should have been declared to the Agency.”  Syria had signed the NPT in 1968 and ratified it a year later.  Syria also operates a 30KW Chinese-built miniature neutron source reactor, which went critical in 1996.

Israel itself maintains a policy of opacity regarding its nuclear program.  It is a party to neither the NPT nor the Missile Technology Control Regime.  It has signed, but not ratified, the CTBT.  Its nuclear program is centered at the Negev Nuclear Research Center, where a French plutonium production reactor reached criticality some 50 years ago.  While Israel does not acknowledge its nuclear weapons program, the Nuclear Threat Initiative notes that Israel is “believed to have produced enough weapons-grade plutonium for 100 to 200 nuclear warheads.” (http://www.nti.org/country-profiles/israel/)  Israel has no nuclear electric power generation reactors.

New Nuclear Power Programs

As mentioned above, the realization that Iran was covertly pursuing a nuclear program potentially capable of giving it a nuclear weapons capability, sharply aggravated existing geopolitical, religious and other tensions with Iran’s Arab neighbors.  The response, in part, focused on other countries pursuing nuclear power programs.

Algeria.  Between 2007 and 2010, Algeria signed nuclear cooperation agreements with Russia, the U.S., France, Argentina and South Africa.  Algeria told the IAEA in 2012 that it planned to have a nuclear power plant in operation by 2022, with a second by 2027.  In May 2013, Algerian Energy and Mines Minister Youcef Yousfi moved the target to 2025, while also establishing a Nuclear Engineering Institute to train Algerian personnel.  The country also is considering nuclear desalination.  Algeria has ratified the NPT and has had a full-scope safeguards agreement with the IAEA in place since 1995.  Algeria also is a party to the Treaty of Pelindaba (African Nuclear-Weapon-Free Zone).

Egypt.  Egyptian President Gamel Adbel Nasser created the Atomic Energy Commission in 1955.  Although Nassar was thought to have considered a nuclear weapons program, Egypt signed the NPT in 1968 and ratified it in 1981, followed in 1982 by a comprehensive safeguards agreement with the IAEA.  Egypt’s Inshas Nuclear Research Center outside Cairo has a USSR 2-MW research reactor, 22-MW Argentine light water research reactor, and fuel and waste facilities.  In 2006, the Mubarak government planned a program of 10 nuclear power reactors, which was supported by Mubarak’s successor Mohammed Morsi.  Any such program will have to await the view of the newly elected Egyptian president and an evaluation of whether the country, with its myriad economic challenges, can support an expensive nuclear power construction effort.

Iraq.  The United Nations Security Council in 2010, recognizing Iraq’s post-Saddam Hussein adherence to its nuclear nonproliferation commitments, lifted sanctions against a peaceful nuclear program.  Iraqi government officials reportedly contacted French nuclear industry officials about rebuilding one of the reactors bombed in 1991.  Iraq ratified the CTBT in Sept. 2013.  While some Iraqi government officials have stated support for a nuclear power program, no specific plans have been advanced as the country focuses on rehabilitating and expanding its oil and gas production and export capability.

Jordan.  A country that imports more than 95 percent of its energy, but has significant uranium resources, Jordan’s Committee for Nuclear Strategy has set out a program for nuclear to provide 30 percent of Jordan’s energy needs by 2030, plus potential power exports.  After a design and siting process involving seven offers from four reactor vendors, the Jordan Atomic Energy Commission (JAEC) in 2010 short-listed reactors from France’s Areva, Atomic Energy of Canada Ltd., and Russia’s Atomstroyexport.  In October 2013, JAEC selected Atomstroyexport to supply two 1000-MW AES-92 reactors, while Rusatom Overseas will operate the plant.  Russia will contribute at least 49 percent of the $10 billion project tab.  The first plant is targeted for operation in 2021, with the second in 2025.  Siting still is unresolved.  A 5-MW research reactor is being built by a South Korean consortium at the Jordan University for Science and Technology north of Amman, with low-enriched uranium to be supplied by Areva.

Kuwait.  Kuwait’s National Nuclear Energy Committee and Rosatom signed nuclear energy for peaceful uses memorandum of understanding and cooperation in 2010.  On March 27, 2014, Rosatom Deputy Director for International Activities Nikolai Spassky met in Moscow with Kuwait’s Ambassador Abdulaziz al-Adwani to offer assistance in the areas of national nuclear legislation, creation of supervisory and regulatory bodies, as well as construction of a nuclear research center and a nuclear power plant, when Kuwait reaches that point. [Itar-TASS]  Kuwait has signed (1968) and ratified (1989) the NPT and supports a Middle East Nuclear-Weapon-Free Zone (NWFZ).

Libya.  The USSR supplied Libya with a 10-MW IRT-1 research reactor in the 1980s.  Libya ratified the NPT in 1975, but pursued a clandestine nuclear weapons program with technology from the Pakistani AQ Khan network.  The renunciation of all Weapons of Mass Destruction (WMD) programs by Col. Muammar Qadhafi in 2003 ended Libya’s nuclear weapons program.  The following year Libya signed the Additional Protocol, to provide IAEA oversight of the dismantling of the program.  Prior to the overthrow of Qadhafi, the regime actively sought outside help for nuclear technology related to seawater desalination.

Saudi Arabia.  Following a 2006 decision by the Gulf Cooperation Council to study peaceful uses of nuclear energy, in 2010 a royal Saudi degree stated that “…atomic energy is essential to meet the Kingdom’s growing requirements for energy…“ and the King Abdullah City for Nuclear and Renewable Energy (KA-CARE) commissioned a series of studies that, inter alia, short listed three potential sites for nuclear power plants:  Jubail on the Gulf, and Tabuk and Jizan on the Red Sea.  The Kingdom plans construction of 16 nuclear power plants over the next 20 years, costing more than $80 billion.  It expects the first reactor to commence operations in 2022.  GE Hitachi Nuclear Energy, Toshiba/Westinghouse, and Areva all have expressed interest in supplying nuclear technology.  Saudi Arabia has signed nuclear cooperation agreements with France, Argentina, South Korea and China, and is negotiating with Russia, the Czech Republic, the U.K. and the U.S.  Saudi Arabia is a NNWS party to the NPT and has a Comprehensive Safeguards Agreement with the IAEA.  Riyadh supports a Middle East Nuclear-Weapon-Free-Zone.

Turkey.  Turkey is not an Arab country, but shares a 499-kilometer (310 mile) border with Iran.  Turkey has explored nuclear power since the 1950s, but only in 1996 tendered for a 2000 MW plant at Akkuyu on the Mediterranean coast near Mersin.  Westinghouse with Mitsubishi, Atomic Energy of Canada Ltd., and France’s Framatome with Germany’s Siemens all submitted bids, but after years of delay in April 2000 Turkey abandoned the effort due to economics.  Turkey re-tendered in March 2008 and accepted the only bid, which came from Atomstroyexport, for four 1200 MW VVER reactors.  The Russians will finance the build, own and operate facility, and Rosatom expects to retain at least 51 percent, while Turkish entities can purchase part of the $20 billion project.  Construction permits are expected this year, with the plants coming online annually starting around 2020

Last year, Turkey accepted a proposal from a consortium led by Mitsubishi Heavy Industries and Areva, with Itochu, for four 1200 MW Atmea1 nuclear reactors to be built at Sinop on the Black Sea.  France’s GdF Suez will be the operator.  The Turkish Atomic Energy Authority anticipates construction to start on the first Atmea1 reactor in 2017, with operation beginning 2023.  ENEC contracted with Uranium One (Canada), Rio Tinto (UK), Areva and Techsnabexport (Tenex—Russia) for uranium concentrates supply; with Areva, Tenex and Converdyn (U.S) for conversion services; and with Areva, Tenex and the European Urenco for enrichment. 

United Arab Emirates (UAE).  Another member of the 2006 Gulf Cooperation Council nuclear energy studies decision, the U.A.E. has moved most quickly.  After the publication in 2008 of a comprehensive nuclear policy document, The Emirates Nuclear Energy Corp. (ENEC) was established to evaluate and implement U.A.E. nuclear power plans.  In 2009, it short-listed consortia from France and Korea, as well as GE-Hitachi, finally selecting Korea for four reactors.  Korea Electric Power Co. (KEPCO), with Samsung, Hydundai and Doosan will construct four Westinghouse APR-1400 reactors, for some $20 billion, at Barakah on the Gulf coast.  Construction commenced on unit 1 in July 2012 and unit 2 in May 2013; unit 3 is expected to start build this year.  Operation of the four units is projected for 2017, 2018, 2019 and 2020.

The U.A.E. is a NPT signatory and ratified a safeguards agreement with the IAEA in 2003, and signed the Additional Protocol in 2009.  In 2009 the U.A.E. also concluded a “Section 123” nuclear cooperation agreement with the U.S. foregoing nuclear fuel enrichment and reprocessing.

Conclusion. 

Many countries in the Middle East and North Africa can justify nuclear programs for desalination and electric power by either their lack of energy resources or by their need to maintain hydrocarbon production for export and to minimize global climate impacts of rapidly growing hydrocarbon combustion.  Nonetheless, concern about Iran’s ambitious atomic energy program clearly motivated many to move beyond mere consideration of nuclear power to actively pursuing it. 

Jordan, Turkey and the United Arab Emirates all have awarded contracts for construction of nuclear electric power plants.   Algeria and Saudi Arabia have announced plans for significant nuclear power sector development, but have not moved to specific plans for plants.  Egypt, Iraq and Libya all have broached nuclear power development, but have much more pressing economic, social and political problems to resolve.  Kuwait has begun preparing for a possible nuclear energy sector.

The expanding interest by MENA countries in nuclear power has provided a double benefit for Russia.  First, it has moved quickly to expand its influence and intelligence gathering in the region by signing nuclear cooperation agreements with any and all comers.  Second, it sees the Middle East as critical to maintaining viability of the Russian nuclear technology, engineering and construction industry as domestic energy growth plateaus.  It already has contracts worth tens of billions of dollars to supply nuclear reactors to Jordan and Turkey.  It no doubt will try to use the nuclear research reactors the USSR built in Egypt, Iraq, Libya and Syria as further leverage.

So far, no other countries in the region appear interested in developing nuclear weapons programs.  Many have emphatically rejected their own nuclear weapons programs, as well as calling for Nuclear-Weapons-Free Zones in Africa and in the Middle East.  But the seeds are sown and will require increased U.S. vigilance. 

Iranian LNG for Europe?

    As Russian troops stormed the Crimea, reminding Europe once again of the perils of undue dependence on Russian gas, the permanent members of the United Nations Security Council and Germany (P5+1) resumed discussions with Iran about an agreement that could lift sanctions on Iran selling oil and gas to Europe. 

     The key issue is Iran’s nuclear development program and its potential for military uses.  But the quid pro quo would be lifting sanctions imposed on Iran’s exports of oil, much of which went to Europe, and European firms’ assistance to Iran in developing its oil and gas resources.  While an agreement could restore Iranian oil imports already this year, Russia’s belligerence raises the question of whether Europe should look more toward Iran in the future for gas supplies as well.

    Iran edges out Russia with the globe’s largest proved natural gas reserves at 1187.3 trillion cubic feet (tcf) or 18 percent of the world total vs. 1162.5 tcf or 17.6 percent.  Qatar, with whom Iran shares the largest offshore gas field, ranks third with reserves of 885.1 tcf.  By comparison, the U.S. holds 300 tcf and the countries of the European Union 61.7 tfc (BP Statistical Review of the World 2013).

     Ironically, Iran had signed agreements in 1975 with Gaz de France, Germany’s Ruhrgas AG and Austria’s OMV to supply them with gas via an exchange agreement with the Soviet Union.  Iran already supplied some southern Caucasus republics of the USSR via the Iran Gas Trunkline (IGAT I).  Iran planned to construct a second pipeline, IGAT II, to supply gas to the Soviet Union, which, under a swap agreement, would provide gas to Ruhrgas, GdF and OMV via an existing Soviet pipeline running through Czechoslovakia.  The Iranian Revolution in 1979 halted IGAT II construction, which never resumed. 

     In 2008, Iran sought foreign funding for IGAT 9, a 1800 km (1125-mile) natural gas pipeline to connect Iran’s South Pars field with European customers via Turkey.  Increasing sanctions put this project on ice.  South Pars is the Iranian portion of the gas field called North Field by Qatar.  Combined reserves are estimated at 50 trillion cubic metres (1767 tcf) of gas and some 50 billion barrels of condensates.

     Around the turn of the century, Iran’s focus for monetizing the South Pars field was a series of liquefied natural gas export projects:  Iran LNG, Pars LNG (with Total S.A. and Petronas) and Persian LNG, as well as an LNG project based on the Lavan gas field.  In late 2007, an Iranian gas official told an international conference that Iran would produce 22 MMT of LNG (1 tcf natural gas) in 2015, 44 MMT (2.1 tcf) in 2018 and about 88 MMT (4.2 tcf) in 2022.  Three years later, following the fourth round of sanctions imposed by the U.S. and E.U., National Iranian Oil Co. Managing Director Ahmed Ghalebani and Deputy Oil Minister Mohsen Khojastemehr announced the suspension of all LNG projects and the redirection of gas projection toward domestic use, including reinjection into Iranian oil fields.

Since the Nov. 2013 interim agreement between the P5+1 and Iran, the subject of Iran’s LNG efforts has resurfaced. 

     On the margins of the December meeting of the Organization of Petroleum Exporting Countries in Vienna, Qatar’s energy minister said they had offered Iran assistance on developing the field they jointly own and that communications links and teams had been established.  While sanctions halted Iran’s exploitation of South Pars, Qatar’s North Field gas catapulted the small country to the top of the LNG exporters, with an export capacity of 77 MMT/Y (3.7 tcf).  In 2005, Doha imposed a moratorium on new North Field development to permit further analysis of optimal exploitation of the field.  Some believe its offer to Iran is to assure that the Iranians do not develop their side in a way that compromises long-term returns on the overall deposit.  In any event, with Qatar using Western companies and technologies, there is a limit to what they can share before sanctions on Iran are eased.

In March 11, 2014, Iran signed an agreement, during Iranian President Hassan Rouhani’s visit to Muscat, to export 10 bcm (350 bcf) of gas annually to Oman via a $1 billion subsea pipeline.  The 25-year deal was valued at some $60 billion, although a final price for the North Pars field gas has not been fixed.  A few days later, The Tehran Times quoted National Iranian Gas Exports Co. Managing Director Alireza Kameli as considering using the pipeline to participate in the Oman LNG plant, which currently serves Asian customers.  Kameli said it would take two and one-half years to construct the subsea pipeline.

     Section 12 of South Pars is expected to start production this year.  Development of sections 12, 15, 16, 17 and 18 have been given priority by Oil Minister Bijan Namdar Zanganeh.  While expeditious field development, and especially LNG facilities, likely would require foreign technology and capital, many foreign firms were involved prior to sanctions:  Total, Italy’s Eni and Snamprogetti, Royal Dutch Shell, OMV of Austria, Norway’s Statoil, Spain’s Repsol, Germany’s Linde, Korea’s Hyundai and Daelim, Malaysia’s Petronas and SKS Group, China National Petroleum Corp., China National Offshore Oil Corp. and the overseas arm of India’s Oil and Natural Gas Corp.  In addition, prior to sanctions, discussions to import Iranian gas reportedly were entered into by Switzerland’s Elektrizitaets Gesselschaft Laufenburg, Thailand’s PTT, Germany’s E.on, and Poland’s PGNiG.

     Even if sanctions are lifted, Iran’s natural gas priorities will remain meeting domestic demand and expanding pipeline gas exports to Turkey, Iraq and Pakistan.  Iran’s geographic position, however, makes LNG an attractive option to develop the world’s largest gas field.  And from the Europeans’ perspective, Russia’s reminder of its menace may make Iranian LNG a relatively attractive option for European buyers.

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

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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. 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.