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.