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.

Big Gas Find in China

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

China Shale Gas Resources Redux

-->

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

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

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

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

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

-->

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

-->

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.