1. We have no alternative but to develop Shale Gas resources of the Country

2. As per earlier figures compiled in DGH the production of Conventional Gas in India is likely to decline after 2015. Therefore, Shale Gas will be the only Domestic Source of Gas availabile in India, in the near future.

3. CONVENTIONAL GAS SUPPLY IN INDIA Source: DGH Million Cubic Feet per Day (MMCF/Day) India’s conventional supplies decline after 2015 ONGC Private & JVs 2020-212019-202018-192017-182016-172015-162014-152013-142012-132011-122010-112009-102008-092007-08 Oil India

4. As per working group of Petroleum & Natural Gas (2012-17) the Domestic Gas Production during the period 2016-17 to 2021-22 will not increase significantly. The demand for gas in the country will be met by import of LNG to the tune of 101 MMSCMD i.e. 40% of then demand in 2013-14 and will increase to 163 MMSCMD i.e. 45% of then demand expected in 2016-17. Thereafter, the country may import both LNG and cross-country piped gas to the tune of 288 MMSCMD or 57% of then demand in 2017-18 to 2021-22. This is a very serious situation as during the period 2025-2030 the import of Crude Oil may reach 90% and import of Natural Gas can be over 60%.

5. Domestic Gas Price USD 4.2-6.5 MMBTU LNG Import Price USD 14-18 MMBTU Pipeline import Price - USD 12-14 MMBTU Pipeline import LNG Import Domestic Gas

6. Based on IEA’s World Energy Outlook 2009 India’s incremental Carbon Footprint between the period 2007-2030 will be 2035 MT Co2 /Annum. Incidentally, this + 153% increase over 2007 will be the highest for any major country in the world. In contrast, the figures for USA, Europeon Union and Japan are respectively -4%, -10% and - 20%. As we produce more gas in the country, the Carbon Footprint will dramatically improve.

7. PER CAPITA INCREMENTAL CARBON FOOTPRINT 2007 – 2030* (MT CO2/ ANNUM/ MILLION PEOPLE) *Based on IEA’s World Energy Outlook 2009 - Reference Scenario, which provides a baseline picture of how global energy markets would evolve if governments make no changes to their existing policies and measures Source: IEA, European Union, www.worldatlas.comwww.worldatlas.com India needs to manage its carbon footprint INCREMENTAL CARBON FOOTPRINT 2007- 2030* (MT CO2/ ANNUM) European Union Japan US Russia India China 91% 153% 22% -4% -20% -10% US India Russia China Japan Increase over 2007, % European Union

8. As per IEA’s World Energy Outlook 2009, India’s Oil & Gas import by 2030 would be over 300 billion USD in 2009 terms. In addition, about 70 billion USD may be used to import LNG and piped gas from abroad. India will be only major country in the world investing 6.5% of its GDP on Oil & Gas imports. Figures for China, Japan and European Union the other major importing regions would be respectively only 3.5%, 3% and 2.5%.

9. Percentage of GDP EXPENDITURE ON NET O&G IMPORTS* AS A % OF GDP

10. EXPENDITURE* ON NET O&G IMPORTS US$ Billion ?

11. Indian economy and foreign exchange reserves cannot sustain the projected, future energy imports. Therefore, early development of Domestic Shale Gas/Oil is essential.

12. What is shale gas development? It requires large dispersed and dynamic above ground activity Exploration Development Production Stratigraphic imagingShale characterizationA land seismic truckCore logging Multi truck and frac equipmentMulti horizontal wells & PAD drilling Surface facilitiesWaste processingPipeline transportation Large land requirement

13. Basic technology for shale gas development Source: Horizontal Wells and Gas Shales (The Oil Drum, 2009); Horizontal Well technology (Dr. S.D. Joshi), EIA Shale Gas approach Multi stage fraccing:  5-20 fraccs per well  Typical use 4 Mn Gallons water/well  Typical proppant 1000- 3000 metric tonnes

14. Unlocking the potential of Shale Gas in India

15. Cambay Basin Gondwana Basin Assam-Arakan Basin Krishna- Godavari Basin Cauvery Basin Vindhyan Basin Bengal Basin Rajasthan Basin

16. Shale Gas Resource of India by ARI, 2011

17. Indicative resources of Non Conventional Natural Gases as broadly estimated by the Author Cam- bay KGCauver y Assam - Arakan Vindhy- an Gond- wana Indicative resource. Risked Recoverable (Tcf) Total 45 Tight Sand 40 85 49 9999 10 10 (?) Not Known20 CBM 30 50 Grand Total say 200 Tcf

19. Generalised Stratigraphy of Cambay Basin

20. Organic Content of Cambay Shale

21. Source Oilex Ltd Tight sand reservoirs in Cambay Basin

22. CAMBAY PROJECT- HYDROCARBONS-IN-PLACE IN TIGHT SANDSTONE NSAI’s Assessment of Hydrocabons In-Place ZoneDiscovered In-Place Volume Estimate Oil MMbblGas BCF X Y Total-Gross 667 654 965 660 1,633 1314 ZoneUndiscovered In-Place Volume Estimate Oil MMbblGas BCF Z 180-200 200-300 300-400 Total-Gross 2693 2705 2424 2406 3791 4195 2684 3339 11592 12645 Total Estimate about 14 Tcf

23. Damodar Valley Basin and Prospectivity of Shale Gas

24. Regional Stratigraphic Column of the Damodar Valley Basins

25. Shale Gas Resource Estimation of Raniganj Area Two wells drilled by ONGC as R&D for shale gas in Raniganj area. Based on the core and log data integration, best estimate risked GIIP of 48 tcf has been made covering an area of 879 sq. km. Source ONGC

27. Krishna-Godavari Basin

28. Source DGH/ONGC

29. Ariyalur-Pondicherry sub basin Kumbhkonam-Madnam-Portonovo High Tanjore-Tranquebar sub basin Pattukottai-Mannargudi-Karaikal High Nagapattinam sub basin Vedarniyam High Pattukuttai-Manargudi high Ramnad-Palk Bay sub basin Mandapam Ridge Gulf of Mannar sub basin Vedarniyam – Tiruchirapally terrace Source DGH/ONGC Cauvery Basin

33. Source DGH/ONGC/OIL

37. Source Oil & Maritine Journal by Dr. V.K. Rao

39. DRAFT POLICY ANNOUNCED BY GOVT. FOR SHALE GAS / OIL IN INDIA THROUGH OPEN INTERNATIONAL COMPETITIVE BIDDING (ICB) PROCESS SUCCESSFUL BIDDERS TO SIGN CONTRACT WITH THE GOVT. BASED ON THE MODEL CONTRACT IN CASE SHALE GAS BLOCK FALLS WITHIN AN EXISTING OIL & GAS / CBM BLOCK THEN RIGHT OF FIRST REFUSAL OFFERED TO THE EXISTING CONTRACTOR TO MATCH OFFER OF SELECTED BIDDER. IN CASE THEY REFUSE, THEN ENTER INTO MODEL CO-DEVELOPMENT / OPERATING AGREEMENT FOR SIMULTANEOUS EXPLORATION AND PRODUCTION.

40. GOVT. WILL ENSURE ALL STATUTORY, REGULATORY AND SECURITY CLEARANCES ARE OBTAINED BEFORE BIDDING EXPLORATION WILL BE AN ACCORDANCE WITH THE LAW OF THE LAND, INCLUDING THE WATER ACT 1974, AIR ACT, 1981 AND UNDER ENVIRONMENT PROTECTION MEASURES PROVISION FOR OPERATING COMMITTEE AND SEPARATE STEERING COMMITTEE SHALE GAS IS PRODUCED OVER LONGER TIME SO MINING LEASE (ML) MAY BE GIVEN FOR 30 YEARS. WITH PROVISION FOR AUTOMATIC EXTENSION, IF NECESSARY. THE SELECTED BIDS WILL BE FIRST APPROVED BY AN EMPOWERED COMMITTEE OF SECRETARIES. THEREAFTER, FINAL APPROVAL BY CCEA. PROVISION FOR ADDRESSING WATER MANAGEMENT ISSUES AND OTHER ENVIRONMENTAL ISSUES.

41. FISCAL REGIME CONTRACTOR WILL PAY ROYALTY TO STATE GOVERNMENT. CONTRACTOR TO BID PRODUCTION LEVEL PAYMENT (PLP) ON A SLIDING SCALE BASED ON INCREMENTAL PRODUCTION. COST RECOVERY WILL NOT BE ADMISSIBLE. COMMERCIAL DISCOVERY BONUS - USD 0.3 MILLION NO CESS PAYABLE ON SHALE OIL TO PAY APPLICABLE INCOME TAX AS PER INCOME TAX ACT 1961. THE GAS PRICING MECHANISM WILL BE UNDER BROAD DIRECTIONS OF GOVERNMENT POLICIES.

42. Suggestions on Draft Policy to attract Technology & Investment

43. Suggestion 1 Draft Policy states pricing of gas will be within the framework of the Govt. Policies on Marketing and Pricing of Gas. This will be the main stumbling point in the shale gas policy. Because Shale gas wells are drilled deeper, drilled horizontally with multi stage fraccing, they need huge quantities of water and proppants, therefore, they cost 2-3 times more than conventional wells. Without market driven price many wells will not get drilled as per the experience of USA.

44. Experience of USA – maximum number of rigs operate and maximum wells get drilled when shale gas price is high.

45. Suggestion 2 In the draft policy no income tax or fiscal incentive provided. It is suggested that at least in the first round of Shale Gas to attract Companies with requisite experience, technology and financial strength some incentives may be considered. Reasons 1.Interest of companies is fading in India. Example NELP Rounds from I to IX

46. Exploration Blocks awarded in NELP Rounds NELP Rounds

47. Reasons (Contd.) 2.Very high cost of Shale Gas development (2- 3 times more than conventional hydrocarbons). 3.Lack of infrastructures available in the country for shale gas. Very limited pipeline network. 4.Lack of sufficient sub-surface data which will discourage private companies specially foreign companies from investing due to conceived high geological risk. 5.Limited unconventional E&P experience in the country. 6.Very poor land and fresh water availability being densely populated country.

48. Reasons (Contd.) 7.Shale Gas production from very tight shales is a highly complex and technically challenging process. It will be necessary to provide incentives to attract experienced oil companies with technologies from abroad and also to encourage Indian companies to invest money in this new kind of use of technology, in a country where commercial presence of shale gas is not yet established. 8.According to EIA publications, April 2011 there are 32 countries having 48 major Shale Gas Basins in the world. Thus, India has to compete with many countries to attract suitable Companies which can bring technology, capital and management capabilities.

49. * Only Rajasthan basin estimated Source: EIA, April 2011 India is competing with other countries to attract companies with shale gas experience that will bring Technology, Capital & Management capabilities EIA estimates 6622 TCF recoverable in the assessed basins. US: 862 TCF India: 63* TCF 48 MAJOR SHALE GAS BASINS IN 32 COUNTRIES

50. Reasons (Contd.) 9.When NELP and CBM Rounds introduced for the first time, the Government provided 7 year tax holiday to attract companies to bid in India. Now that even more complex and technology intensive Shale Gas Policy is being announced it may be necessary to again consider 7 years tax holiday. 10. If above is not feasible then a case should be build up for atleast 4 – 5 years tax holiday. Shale gas wells decline very fast. To maintain production at reasonable level for sale to industry, wells have to be drilled every 2 – 3 years It is estimated that in 4 – 5 years only around 20% gas may get produced out of entire life of field on which tax holiday will apply. This model can be developed by DGH. The Govt. will still earn full tax on remaining 80% of gas. The Govt. is getting many other revenues from shale gas block as royalty, central / state taxes and PLP etc.

51. This will provide enormous incentive to drill as many wells as possible in the first 4-5 years and sell gas to consumers as early as possible. This is exactly what country needs i.e. earliest possible gas production. The remaining 60% wells will get drilled later to maintain the required production profile for sale of gas.

52. Suggestion 3 “ 3.4 of draft shale gas policy states that areas previously allotted and where development / production phase has started shall be excluded from offer for shale gas / oil exploration.” Such areas in Cambay, KG, Cauvery, Damodar & Assam- Arakan Basins hold the best shale gas/ oil potential of the country. Thus, 60-70% of expected resources will not get developed.

53. Some options for considerations – (a)When such blocks are offered and if the existing operator of an oil & gas Block is the best bidder he will automatically get the Block. If he is not the best bidder then option is to give him a chance to match the best bid. This could be unfair to the new bidder. It may be better if the block is awarded to the best bidder but original operator of Oil & Gas Block is given an option to farm in upto 30% in the operations of the new bidder, on payment basis. (b)Ministry by transparent bidding process may allow current lease holders of oil & gas blocks to download part of their equity to companies with shale gas experience and technology.

54. Suggestion 4 In draft policy contract duration is 32 (thirty two) years and divided into two phases- Phase I and Phase – II Division in Phase-I & Phase-II may not be adequate. For example in CBM Contracts there is minimum provision of 3 Phases and past 14 years of experience of CBM operations in India shows that 3 phases are required. Following phases and time frame may be considered: Phase-I (5 years) – Exploration Phase with provision for Exit at its end, if required. Phase-II (minimum 3 years) – This can be called Drilling of Pilot Wells Phase. Also includes Techno economic feasibility, Market Survey and Commitments. With an exit clause at its end Phase-III (25 years) – Development & Production Phase

55. Suggestion 5 Bidding Parameters in draft policy Technical Qualifying Criteria– 3 years experience in oil & gas / CBM/ shale gas / oil. Weightage for Minimum Work Program – 40% Weightage for Production Linked Payments – 60% This will not give desired results based on the experience of pre-NELP and NELP Rounds in the last 20 years. What could be considered– % Weightage Preferable mode Minimum requirement MWP4545 PLP4045 Technical Capability1510

56. Sl. No.Sub-criteria% Weight- age 1.(a) Oil & Gas Recoverable Reserves (O+OEG)* in MMBoe for the previous 5 years 1 (b) Shale Gas / Oil reserves in BCM/MMBoe for the previous 5 years 1 2(a) Annual production of Oil & Gas (O+OEG)* in MMBoe for the previous 5 years 1 (b) Annual Production of Shale Gas/Oil in BCM/ MMBoe for the previous 5 years 1 3 (a) Acreage holding (in Sq. kms.) Oil/Gas Block1 (b)Shale Gas / Oil Block1

57. Sl. No.Sub-criteria% Weight- age 4 (a) Bidder’s experience as an operator in Exploration and production of oil and gas for last 5 years 1 (b) Exploration and production of Shale Gas / Oil for last 5 years 1 5 Experience of working in India in Oil and gas sector for last 5 years 1 6Gas & Crude Oil transportation, storage, distribution experience. Gas utilization industry experience (e.g. like Fertilizer, Petrochemicals, Power, Steel etc.) 1