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.