User Guide for India s 2047 Energy Calculator Oil & Gas Sector

Transcription

1 User Guide for India s 2047 Energy Calculator Oil & Gas Sector 1

2 Table of Contents I. Introduction:.3 II. Overview of the Oil & Gas Sector:.10 III. Overview of the structure of the Oil Sector worksheets: 15 III a. Assumptions sheet:.. 15 III b. III c. III d. IV. Calculation sheets:..16 Basic or Fixed Assumptions:.17 General Assumptions: 18 Trajectories for oil:..20 V. Overview of the structure of the Natural Gas Production worksheet:...27 V a. V b. VI. VII. VIII. IX. Basic or Fixed Assumptions:..27 General Assumptions:.28 Trajectories for Gas Supply: 30 Costing:..37 Conclusion: Notes.44 X. Bibliography 45 2

3 I. Introduction: This document provides detailed information on the working of oil & gas sector in India Energy Security Scenarios (IESS) 2047 Version 2.0. It is an established fact that India is a large importer of oil and gas, and this scenario is not expected to change in the near future. As the aim of the IESS, 2047 V 2.0 is to offer implications of energy related policies on our energy security in the medium to long term, the likely scenarios of oil/gas imports assume importance. Against this background, the projections of domestic oil and gas production have a significant role. It is difficult to project likely oil/gas production as exploration results are probabilistic, especially as India is grossly under-explored. India has an estimated sedimentary area of 3.14 million sq. km comprising 26 sedimentary basins, out of which, 1.30 million sq. km area is in deepwater and 1.84 million sq. km area is in onland and shallow offshore. As on 31 st March, 2014, out of total area, 48% has been appraised, 4% area falls under no go areas and remaining 48% is still to be appraised (Appraisal of a sedimentary basin has been defined as the status of knowledge building efforts for evaluating hydrocarbon prospectivity of the basin through Geological studies, Geophysical surveys and exploratory drilling) (DGH). The conventional hydrocarbon prognosticated resources in 15 sedimentary basins along with deep water areas of the country are of the order of 28.1 Billion Tons of Oil and Oil Equivalent of Gas (Directorate General of Hydrocarbons DGH). As on in-place hydrocarbon volume of 10,947 MMT of Oil and Oil Equivalent Gas could be established through exploration by ONGC, OIL and Private/JV companies. So, approximately 17 Billion Tons i.e. 61 % of resources (oil and oil equivalent of gas) are under yet to be established category. The historical growth rate (CAGR) of initial in place hydrocarbon volume (from till ) is about 2.55%. In the present exercise, an effort has been made to project the likely discovery of in place hydrocarbons on the basis of historical trends. While a more exact approach would be to estimate prospectivity on a basin-wise basis, but the ambition of the present study is not to get into a technical analysis, but concentrate on policy levers. The exploratory effort is likely only to increase as the Government is keen to reduce oil/gas import dependence (presently 80% for oil and 27% for gas), with greater likelihood of establishing more finds. However, as has been witnessed in the past, India has failed to monetize its discoveries. There is a wide gulf between the in-place hydrocarbons established on yearly basis as reported by the DGH, and the proved reserves as indicated by British Petroleum (BP) Statistics. The latter are a sub-set of the former, but the falling percentage of the latter is an area of attention. The instant analysis develops scenarios of oil and gas production by enhancing the pace of conversion of discoveries into producing fields, and raising the recovery factors (R/F). The Government has taken up an exercise to revise the prognosticated (likely) resources in the Indian sedimentary basins on the basis of the Exploration & Production (E&P) effort that has taken place in the country, especially after the launch of New Exploration Licensing Policy 3

4 (NELP) in While the above exercise may yield results in near future, an analysis to estimate the likely oil/gas production from the Indian sedimentary basins, must be undertaken to factor in the policy inputs in the petroleum sector right away. Similar exercises have been undertaken by other agencies such as IHS and Kelkar Committee (by using Rystaad data) in the recent years. It is quite clear even without getting into the veracity of the reported numbers/sources, that India s oil production has been stagnant and even falling in the case of gas. Therefore, the immediate challenge, at least in the short run seems to be on monetizing the discoveries, while on-going exploratory efforts may be intensified. The present exercise takes a deep dive into the current discoveries and approved production plans as ascertained from DGH, and also from the National Oil Companies (NOCs) to arrive at some estimates of likely production in the years to come. On the above basis, a medium term projection of production is also offered. The projections of oil/gas production of India are being proposed in the absence of strong geological data. In the absence of the latter, our approach is based on the contractual/prevalent regime in exploration. E&P operators report discoveries on the basis of their seismic/drilling activity. Then, as per the NELP Production Sharing Contracts (PSCs) they go on to appraise discoveries and propose a Development Plan for a size of reserve, for which a production profile is approved. Even the NOCs follow a near-similar process in their nominated acreages. In the IESS, 2047 V 2.0 we assume the volume of oil/gas that is likely to be discovered, based on the CAGR of discovered resources in the past. This leads to initial-inplace reserves (IIP). The IESS projects the likely production on the basis of four scenarios of conversion of initial-in-place hydrocarbons into ultimate reserves. Naturally, if the reserve levels are higher, then the production will also be commensurately higher. As we move from low levels of reserve conversion to higher levels, the oil/gas production is estimated to rise. Therefore, in this analysis, presuming that exploratory efforts continue un-abated (they may intensify due to Government policy), the analysis reveals that it is the conversion to proved reserves that holds the key to raising oil and gas production. It has been seen that in India, while the operators have reported a large number of discoveries, only a handful have been converted into producing properties. Hence, the problem seems to be in monetizing discoveries and not finding hydrocarbons. It is recognized that not all discoveries are commercial. It is for the Government to spell out as to whether its policy is to encourage domestic self-sufficiency even if the domestic production comes at higher rates than what is prevailing in the international markets or get the best commercial deal. As the present tool is one of energy security, we do not take the price arbitrage into account, and merely highlight the scope of raising oil/gas production from the Indian sedimentary basins. The scope of the present exercise is merely to seek policy areas for action. This leads us to develop 4 scenarios or Levels - (L-1: Least Effort; L-2; Determined Effort; L-3: Aggressive Effort, and L-4: Heroic Effort) likely percentages of the discovered resource being produced 4

5 over an assumed number of production years based on recovery factors. If the regime could be geared towards incentivizing operators, or facilitating oil/gas production, India could have a healthy hydrocarbons regime. Therefore, in a nutshell, the present exercise offers an insight into the problems faced by the E&P sector in their inability to convert discoveries into production, and the likely upsides to crude/gas production by putting in place suitable policies to enhance recoveries. The present document explains the working of the domestic oil and gas production scenarios in the instant IESS tool, and helps the user make choices on determination of different crude oil & natural gas production trajectories until the year The document highlights the data sources that have been consulted in this exercise, such as the Petroleum Exploration and Production Activity Reports of Directorate General of Hydrocarbons (DGH) India, International Energy Agency (IEA s) World Energy Outlook, Petroleum & Natural Gas Statistics of Ministry of Petroleum & Natural Gas, oil & gas journals and various articles available on the internet websites. The Twelfth Plan Document ( ) of Planning Commission has formed the basis for various assumptions with regard to policy related matters and data inputs. This document also recognises the inputs provided by stakeholders like DGH, BP India, Cairn, ONGC, OIL, Suntera Energy Services, Association of Oil & Gas Operators, etc. On the demand side, the IESS, 2047 V2.0 helps generate the demand for oil/gas in the Indian economy from all consuming sectors by the user making choices of demand sector technologies (some technologies substitute oil with other fuels) and level of energy efficiency. On the basis of these choices, total demand for oil/gas is generated. The algorithm in the tool first deploys domestic oil and gas production in meeting the demand. The balance demand is then sourced by the Excel model from imports, which would be separately shown as numbers/percentage of the supply being imported. It is obvious that the level of petroleum imports would be dependent both on demand and supply scenarios. While some studies (earlier referred) do project oil/gas production, there are few which estimate demand scenarios as the latter is fraught with uncertainty on level of economic activity, efficiency and fuel switching. This is precisely the information which IESS, 2047 provides create import scenarios for demand and supply combinations. It helps the policy maker, academician and ordinary citizen aware of the steps that need to be taken to bring import levels down and enhance India s energy security. The likely oil and gas demand would be 587 MMT and 308 BCM in 2047 considering Level 2 (Determined Effort) which is the default scenario, respectively. On the other hand the likely production of oil/gas has been estimated to be 59 MMT and 127 BCM in 2047 considering level 2, respectively. Level 2 envisages moderate improvement from the present, and results in robust increase in demand, with only moderate increase in domestic oil/gas supply. Resultantly, when taking into account the likely demand for petroleum products as envisaged by the Calculator in IESS, the oil and gas import shares (against consumption) could be between 88% and 60% in 2047 considering level 2 or Determined effort, respectively. 5

6 While generating numbers for natural gas production - conventional gas resource, gas generated from Underground coal gasification (UCG) and non-conventional resources like Shale gas, CBM - have also been taken into account. The UCG and Shale gas numbers have been generated based on activities undertaken by the line departments and various research papers available in the public domain. The production from these sources - UCG, Shale and gas hydrates have been assumed to kick-in at different points of time. Underground Coal Gasification (UCG): It has been recognized that in-situ gasification of coal/lignite deposits from deep and/or unmine-able or non-mined coal seams for production of synthetic gas (syngas) for power generation, synthetic liquid fuels, natural gas or chemicals are promising technologies as they combine mining, exploitation and gasification. The main motivation for moving towards UCG as the future coal utilizing technique is to overcome environmental curbs, and other advantages over the conventional mining process. Some of these benefits include increased worker safety, no surface disposal of ash and coal tailings, low dust and noise pollution, low water consumption, larger coal resource exploitation and low methane emission to atmosphere. The main gases produced are carbon dioxide, methane, hydrogen and carbon monoxide. These gases can be processed to remove CO2 content thereby providing a source of clean energy with minimal greenhouse gas emissions. UCG has the potential to eliminate the environmental hazards associated with ash, with open pit mining and with greenhouse gas emissions if it is combined with utilization of CO2 that is produced during the process. As India has vast deposits of low-quality coal, and also at deeper levels, the above technologies can be useful, and may be deployed in the future. In the last few years there has been significant renewed interest in UCG as the technology has moved forward considerably. China has about 30 projects in different phases of preparation that use underground coal gasification. India plans to use underground gasification to access an estimated 350 billion tonnes of coal. In 2007 India compiled a 93-page status report on underground coal gasification that highlighted interest from many of the country's biggest companies. South African companies Sasol and Eskom both have UCG pilot facilities that have been operating for some time, giving valuable information and data. In Australia, Linc Energy has the Chinchilla site, which first started operating in Carbon Energy has completed a successful 100 day commercial scale study in Bloodwood Creek in Demonstration projects and studies are also currently under way in a number of countries, including the USA, Western and Eastern Europe, Japan, Indonesia, Vietnam, India, Australia and China, with work being carried out by both industry and research establishments. Cougar Energy and Linc Energy have conducted pilot projects in Australia based on UCG technology provided by Ergo Exergy. Yerostigaz, a subsidiary of Linc Energy, produces about 1 million cubic metres (35 million cubic feet) of syngas per day in Angren, Uzbekistan. The 6

7 syngas so produced is used as fuel in the Angren Power Station. [22] In South Africa, Eskom (with Ergo Exergy as technology provider) is operating a demonstration plant in preparation for supplying commercial quantities of syngas for commercial production of electricity. ENN has also operated a successful pilot project in China. In addition, there are companies developing projects in Australia, UK, Hungary, Pakistan, Poland, Bulgaria, Canada, US, Chile, China, Indonesia, India, South Africa, Botswana, and other countries. According to the Zeus Development Corporation, more than 60 projects are in development around the world. Table 1: Use of UCG sourced gas in different uses Source: Zeus Development Corporation The table 1 above shows how the UCG is used by different countries for diverse uses. India has billion tons of coal resources and billion tons of lignite resources. Underground Coal Gasification (UCG) can be used to extract the deep and un-minable coal and lignite resources in India. A total of billion tons coal resources and billion tons lignite resources are confined to depths greater than 300 m. India has more than 35% of coal resources locked at depths higher than 300 m which are potentially exploitable by UCG. As a result of exploration carried out up to the maximum depth of 1200 m by the GSI, CMPDI, SCCL and MECL etc, a cumulative total of Billion tons of Geological Resources of Coal and BT of lignite have so far been estimated in the country as on Out of the above 7

8 estimates, 6 billion Tons of lignite and 45 billion tons of coal, totaling 51 billion tons only is extractable. Remaining 35 billion of lignite and 240 billion of coal is still un-extractable. Therefore, it is sensible to find ways and means to exploit these unrecoverable Coal and Lignite reserves of billion tones to meet the ever increasing energy demand of the country. In this endeavor a good part of the un-mineable Coal and Lignite deposits can be extracted by using underground coal gasification (UCG). Research papers say that one ton of coal has potential to generate approx m 3 of syn gas. If we consider only 10% of un-extractable coal and lignite reserves as amenable for UCG i.e BT, a total trillion m 3 (68950 BCM) UCG syngas potential of calorific value 3-5 MJ / m 3 will be available. Shale Gas/Shale Oil Resources: It is estimated that a number of onland sedimentary areas in Gangetic plain, Gujarat, Rajasthan, Andhra Pradesh & Assam in India, including the hydrocarbons bearing basins Cambay, Cauvery, Krishna Godavari, Assam-Arakan & Damodar (Gondwana) have large shale deposits. There have been few efforts by the Government to conduct surveys and estimate the full potential reserves of shale oil and shale gas in the country. ONGC did drill some exploratory wells specifically for shale quantification through Schlumberger in the Damodar Valley basin. Even the Ministry of Coal has approved research projects for shale gas characterization. Other agencies have also estimated the shale gas/oil resource potential in selected sedimentary basins/ sub-basins in India: i. M/s Schlumberger : 300 to 2100 TCF, ii. Energy Information Administration (EIA), USA 2013: 584 TCF of shale gas resource and 87 billion Barrels of shale oil resource in 4 basins (Cambay Onland, Damodar, Krishna Godavari Onland & Cauvery Onland), iii. ONGC: TCF of shale gas resource in 5 basins (Cambay Onland, Ganga Valley, Assam & Assam Arakan, Krishna Godavari Onland & Cauvery Onland), iv. Central Mine Planning and Design Institute (CMPDI): 45 TCF of shale gas resource in 6 sub basins (Jharia Bokaro, North Karanpura, South Karanpura, Raniganj & Sohagpur), v. United States Geological Survey (USGS) in January 2012 has also estimated technically recoverable shale gas resources of 6.1 TCF in 3 basins (Cambay Onland, Krishna Godavari Onland & Cauvery Onland). vi. USGS in Apr 14 has also estimated 62 million barrels of shale oil in Cambay basin and more than 3.7 TCF of gas in tight sandstone gas reservoirs in Cambay & Krishna Godavari. The Government has issued Policy Guidelines for Exploration and Exploitation of Shale Gas and Oil by National Oil Companies under Nomination regime on 14th October, Under this Policy, the right to explore and exploit Shale Gas & Oil will lie with the NOCs holding Petroleum Exploration License (PEL)/Petroleum Mining Lease (PML) granted under the nomination regime. It may be pointed out that in the extant petroleum exploration contractual regimes, the exploration phase is over for most contractors and the companies are not authorized to begin their exploration for shale oil/gas. Currently, there is no commercial production of shale gas/shale oil in the country. 8

9 Coal Bed Methane (CBM): CBM is a Natural Gas produced from Coal Beds in Coal bearing areas. In order to harness CBM potential in the country, CBM Policy was formulated in The Government of India has so far awarded 33 CBM blocks under 4 rounds of CBM bidding & nomination basis, in the states of Jharkhand, West Bengal, Chhattisgarh, Madhya Pradesh, Maharashtra, Rajasthan, Gujarat, Andhra Pradesh, Tamil Nadu, Odisha and Assam. Out of total available coal bearing areas for CBM exploration of 26,000 sq.km, exploration has been initiated in 66% area i.e. 17,200 sq.km. The estimated prognosticated Coal Bed Methane (CBM) resource in the country is about 92 Trillion Cubic Feet (TCF). The 33 CBM blocks awarded for exploration & production of CBM gas have a prognosticated CBM resource of about 63 Trillion Cubic Feet (TCF). Reserves have been established in 8 CBM blocks which are in production/development phase. The total established in-place reserves in these 8 blocks are 9.9 TCF ( BCM). Gas Hydrates: The presence of gas hydrate was established in the year 2006 in Krishna Godavari, Mahanadi and Andaman deep waters in numerous complex geologic settings. In accordance with the roadmap for the National Gas Hydrate Programme (NGHP), India has already acquired core samples under NGHP-01 and NGHP Expedition-02. Depending on the results of NGHP Expedition-02, a plan will be made for suitable site for carrying out pilot production testing. Earlier studies have prognosticated gas hydrate resources of 1894 TCM for India, and USDOE (Feb 2012) published that around 933 TCF is the concentration of gas hydrate in sands within the gas hydrate stability zone. 9

10 II. Overview of the Oil & Gas Sector: Managing the petroleum and natural gas sector of India envisages critical challenges as identified in the Twelfth Plan. The demand for petroleum products is expected to expand while the scope for increasing domestic production is limited. Currently, the oil/gas prices are subdued, but decline in exploration/production globally in the light of low prices/over supply may lead to a reversal in the trend. In the medium to long term, oil prices in world markets are expected to be volatile but generally high. The oil and gas import bill is likely to increase in the future from the present level of around 6-7 per cent of GDP. The New Exploration Licensing Policy (NELP) programme is a major initiative aimed at attracting private investment into oil and natural gas upstream sector. There have been nine rounds of bidding, starting with a first in 1999, and a total investment of US$ billion has been made by various operators in E&P sector till under the PSC regime. The Government is likely to announce a new bidding round under NELP which may also see revamped fiscal terms. The volatility in oil and gas prices is likely to continue in the world markets and our dependence on imports for both oil and gas is also likely to increase. In the past, while India has been able to absorb the shocks of high oil prices in its economy, the same has not been the case with LNG. The above is largely due to sensitive demand to prices in downstream sectors such as urea and power. Consequently, a large gas based power generation capacity remained stranded for the last several years, until the Government came out with a policy to shield these power producers from the international price of gas. If India has to increase the share of gas in its primary energy mix, and also absorb global oil prices, it must align domestic oil and gas price to market price and send the right signals to consumers and producers. Gas currently comprises merely 8% of the primary energy mix against nearly 24% globally. NELP provides the contractors freedom to price the gas at marketdetermined prices for gas produced from these blocks, after obtaining price approvals from the Government. As majority of new gas prospects are in deep water, investments, technology and pricing of gas for developing these fields would be important factors to incentivize gas supplies from domestic fields. The scenarios do not detail the economic policy framework necessary to achieve highest envisaged levels of production, but there is a brief description of the same. The present exercise merely discusses the likely production from the prognosticated hydrocarbon reserves at the present level of exploration activity. It also factors in the pace of converting the finds into production, which has a poor track record for discoveries so far. Therefore, it may be useful for the policy makers to identify measures to enhance the recovery factor from the hydrocarbon resources being established under exploration activities. Today the average oil recovery rate in the world is approximately 35% (compared to 20% in 1980) against a technical limit estimated at approximately 60%. The recovery factor varies from an average of 10% for extra-heavy crude to values which rarely exceed 45-50% 10

11 in the most advanced fields in the North Sea. The increase in the average recovery rate of even just one percentage point can lead to the addition of 35 to 55 billion barrels of reserves, equivalent to one or two years of world oil production. The recovery factor (R/F) of both oil and gas taken together for private and joint venture (JV) companies in India is higher than that of public sector companies like ONGC and OIL (Oil India Limited). While the recovery factor is 41.2% for private and JV companies, it is 36.7% for OIL and 35.2% for ONGC. The average oil and gas recovery factor in India works out to 36.5%. For some countries like Norway, the recovery factor for oil and gas is as high as 44%. In other countries like Iran and USA, the recovery factor is 35% and 32% respectively. Individually, the average natural gas recovery in India is 50.8%, while for oil it is 28%. As far as crude oil recovery is concerned, the PSUs fare better than their private sector counterparts. While the R/F for OIL and ONGC is 29.6% and 28.3% respectively, the private and JV companies stand at 23.7%. In the natural gas segment, the R/F of OIL is 53.9% followed by private and JV companies at 53% while that of ONGC stands at 49.3%. R/F s are largely dependent on geology, but it has also been seen in some cases, that in the same basin the above are at variance from ONGC to OIL. This is typically seen in the North east. In the light of complete exploration, a doubt lingers whether full evaluation of the reserves has taken place or not. Until this happens, the issue of poor R/F will remain alive. Even though domestic production of energy resources is projected to increase, the import dependence is expected to maintain high levels. Import of crude oil is currently about 80% per cent of total crude demand in the country MMT of crude oil was imported in which increased our oil import bill by 9.27% (from INR 7846 Billion to 8648 Billion) in comparison with the imports in The amount of crude oil imported in was MMT and the bill came down in to INR 6873 Billion due to softening of crude price. The gas supply from indigenous fields was 52.3 BCM in the year (the highest ever) has shown declining trend and in the year , the supply was about BCM. The import of gas as LNG in was of the order of MMT (approximately BCM) and has not grown at the expected rate to meet the demand of gas of the power and other sectors. It is a separate policy dialogue as to why India did not go in for LNG imports in a major way to generate power and urea both of which are in short supply. The ongoing efforts to explore oil and gas have been satisfactory so far as establishment of new hydrocarbons resources goes on. It may be noted that Indian oil companies have consistently been reporting reserve replacement ratio of more than 1. The discovered resources have been defined as initial oil in place which include proved, probable and possible reserves and contingent resources.. The growth in initial-in- place reserves combined for both oil & gas from till has been at CAGR of 2.55%. During , the split between oil and gas has been in the ratio of 63.58% and 36.42% respectively and keeping the past trend of rising share of gas finds into consideration, the likely split between oil and gas has been extrapolated to be 40% and 60%, respectively in 11

12 2047. While this is a simplistic assumption, it meets the requirement of the present analysis which is merely a scenario based exercise using Excel model and not a geological exercise. It is definitely an indicator that India has to intensify its exploratory efforts, to establish the reserves and devise suitable policy framework for converting the discoveries into production. The estimate made by the Directorate General of Hydrocarbon (DGH) of oil and gas potential in 15 sedimentary basins is about 28 billion tons which may increase upon thorough exploration of these 15 basins and the remaining 11 basins. Out of this, billion tons of initial in place (IIP) reserves (O+OEG) have been established as of The share of oil IIP is 6.96 billion tons (63.4 %) and that of gas is 3.98 billion tons (36.6 %). Government of India has signed contracts for 29 discovered fields, 28 exploration blocks under pre-nelp regime and 254 blocks under NELP regime with National Oil Companies and private (Both Indian and foreign)/ Joint Venture companies. At present, out of 311 exploration blocks/fields awarded so far under various bidding rounds (Discovered Field, Pre-NELP & NELP), 178 blocks/fields are operational. DGH indicates, that so far a total of 200 hydrocarbon discoveries (100 oil and 100 gas) have been made under the Pre-NELP & NELP regime in 54 blocks/fields. Out of total awarded blocks of 288 under 9 rounds of NELP bidding, 130 blocks have been relinquished and 151 is operational. The analysis of India s exploratory successes and production trends offer an interesting revelation. (The tables below highlight the Initial in Place (IIP) reserves numbers (DGH) (Table2), proved reserves numbers indicated by BP (Table 3) and crude oil production numbers for the period 2004 to 2012 (DGH). While we have been reporting discovery of new resources, our production has been stagnant. There is definitely a time lag between discovery and production, but in India s case, the discoveries seem to be getting monetized only partially. It is purported that the production levels are being maintained by exploiting new discoveries in existing acreages by IOR and EOR. The situation remains ever confusing. At the same time, both ONGC and OIL have been reporting healthy new finds thereby achieving Reserve-Replacement-Ratio (RRR) of 1 and above. Similarly, under NELP, even private sector (public, too) have reported multiple oil and gas discoveries. But, only 4-5 discoveries have been brought under production in spite of having initiated exploration under NELP more than 15 years back. Should these discoveries be monetized, a vast scope appears for improving production. But, the growth in production of oil and gas is near static or on decline. Herein lies the clue for policymakers to focus on the efforts needed to convert growth in reserves into production. The new discoveries add volumes to IIP but the production has been stagnant. R/F would have risen if higher production could come from existing resources. In our case, we are merely able to maintain R/F, but not raise the percentage of exploitation of reserves. 12

13 Table2: Fixed Assumption of Establishment of Oil and Gas In-Place Year IIP Oil (MMT) IIP Gas (MMT) Total IIP (oil & Oil Equivalent of Gas) (MMT) Growth rate 2.55% Source: DGH The above Table 2 gives us the historical initial in place reserves numbers for oil, gas and oil+ oil equivalent of gas (DGH) till and the corresponding projected figures till calculated by taking a CAGR of 2.55%. This table indicates the underlying assumption based on which the entire production profile of oil and gas has been worked out. 13

14 Table 3: Growth of Proved Reserves and Production of crude oil Year Proved Reserves (MMT) Production (MMT) Source: Proved Reserves (BP Statistics) and Production (DGH) The information in Table 3 shows the static proved reserves and production over the years. When compared with the growth in OIP and GIP in the previous table, the asymmetry becomes evident. The in-place reserves are rising but the proven reserves and production is static. The analysis indicates that with the likely growth in initial in place (IIP) reserves, if India were to make heroic efforts or induct technology and encourage policy environment, we could ramp up our proven reserves and hence, oil production from the present 38 MMT level to a much higher level in the year Similarly gas production could go up phenomenally. 14

15 III. Overview of the structure of the Oil Sector worksheets: III a. Assumptions sheet: This section helps the user understand how the scenarios of oil/gas production have been developed. The assumptions sheet is the principal driving sheet for the Calculator. We derive the ultimate reserves from the OIP (oil in place), which would be the total volume of oil that may be produced in India. Now we need to determine the annual production from the above reserves. The combined growth in IIP for oil and 2.55% (historical growth rate upto 2047) over the base year is a common assumption number across the 4 scenarios in the tool till It is only the level of our ability to raise the recovery factor that is different under the four scenarios. The recovery factor across the L-1, L-2, L-3 and L-4 have been assumed as 28%, 30%, 35% and 40% for crude oil and 55%, 60%, 70% and 80% for natural gas, respectively. The above assumptions are based on the technical feasibility of extracting oil & gas as the developed hydrocarbon regimes are already achieving the proposed recovery factor. Applying the above recovery factors for oil and gas on initial in place reserves i.e. 28% in L1 to 40% in L4 and 55% in L1 to 80% in L4 respectively, we get the ultimate reserves which we consider as technically recoverable reserves, or the total volumes that India may be able to produce. In IESS 2047 Version 2.0, the user is offered the choice to play upon merely the R/F lever. Now we have to make assumptions regarding the likely production of oil and gas in the years to come from the four different scenarios of Ultimate reserves. It has been historically established that the production of oil in different years has been a fixed percentage (or marginally falling) of the Ultimate reserves as per DGH data. The above percentage is 2.3 for oil, a factor which tells us about the production rate from the ultimate reserves. We could assume the same exploitation rate (2.3%) for different Ultimate reserves to derive a uniform rate of production. Simultaneously, we need to ensure that the annual production rate assumed for a level, should not surpass the Ultimate reserve by The above assumption regarding the production rate for a volume of Ultimate reserve is an approximation of what may be the annual production. Table 4: Maximum annual production of crude oil under different scenarios (in 2047). Levels Oil in Place (MMT) Recovery Factor Ultimate Reserves (that can be recovered Technically) (MMT) Maximum Annual Production (MMT) (2.3% of Ultimate Reserves) % % % % Source: Calculations as per IESS analysis 15

16 The above table 4 illustrates the maximum production that can be sustained in the year 2047 on the basis of the calculations explained earlier. The Table 5 gives us maximum production of natural gas that can be sustained in 2047 on the same analogy as in oil, but with a different factor. While, the replacement factor for crude oil which is taken as (2.3%), in case of natural gas, this factor is taken as (1.5%) based on the historical trend which may or may not improve depending upon the environment, regulatory regime and investments made in the E&P sector. Table 5: Maximum annual production of natural gas under different scenarios (in 2047). Levels Gas in Place (MMT) Recovery Factor Ultimate Reserves (that can be recovered Technically) (MMT) Maximum Annual Production (MMT) (1.5% of ultimate reserves) % % % % Source: Calculations as per IESS analysis Note: The gas in place reserves, ultimate reserves and the maximum production numbers in Table 5 includes only conventional natural gas, and unconventional sources of natural gas like shale gas, CBM, UCG and gas hydrates have not been included due to lack of data availability as their reserves have not been established with high certainty, and the geological surveys done by different organizations report different numbers. III b. Calculation sheets: Four categories (choices) appear in the Tool as options or line items for the user to choose from. They are the assumptions regarding India s ability to achieve higher levels of production from the discovered resources. In other words, the user can choose one out of the four offered levels of oil/gas production, depending upon his judgment of the likely scenario. Each option will contain production scenarios from low level to the highest achievable level, for the operator to choose. Level-1 projects a pessimistic scene or Least Effort Scenario wherein there is no improvement in recovery factors, and no new fields come into production barring the ones for which Final Investment Decision (FID) have been taken. Hence, discoveries will happen (or 16

17 may even stop) but there will be poor success in converting them into production. The recovery factor has been assumed almost constant i.e. 28% for oil and 55% for gas. Level-2 assumes present policies to improve as per on-going efforts, which confirms to the present initiatives taken, and also takes into account some technological improvements. Hence, it is called the Determined Effort scenario. It would be simplistic to say that Level 2 is BAU, as it also assumes continuing efforts to improve the policy space for improvement in oil and gas discoveries and production. This level experience minor improvement in recovery factor i.e. 30% for oil and 60% for gas. Level-3 is more optimistic and is the Aggressive Effort scenario, and considers government policy intervention towards a better future with enhanced production and lower oil/gas imports. This level experience increase in recovery factor i.e. 35% for oil and 70% for gas. Level-4 is the most optimistic or the Heroic Effort scenario; it is an ideal situation that is drawn from whatever is physically possible as perceived today. This level experience increase in recovery factor i.e. 40% for oil and 80% for gas. III c. Basic or Fixed Assumptions: Production profile has been classified into three source categories i.e. ONGC (including its private share), OIL and PVT/JVCs. This is useful as the first 2 operate largely under the nomination regime, while the third is under the PSC regime. It is the nomination regime which is responsible for the bulk of the present production. The situation may change in the future, but as of now NOCs seem to be having promising future in their nominated acreages. Keeping in mind the combined historical growth rate of 2.55% of initial in-place reserves of oil and gas, the future projection of IIP has been done till By observing the changing mix of oil and gas discoveries, the future discoveries remain in favour of gas, it is expected that the share of oil reserves in 2047 would be 9.5 billion tons (40%) and that of gas billion tons (60%). This assumption would be common across the 4 scenarios. Further, the unexplored areas of the balance 11 sedimentary basins would also contribute to the resources. (India has 26 sedimentary basins). As the scenario building exercise is working only on the prognosticated reserves of 15 basins, establishing billion tons of reserves by 2047 is assumed to be a realistic phenomenon, yet leaving scope for further reserve establishment within the 15 basins, as well as the balance unexplored 11 basins. 17

18 Table 6: Projected Oil and Gas in Place Reserves on the basis of historical trends Year OIP (MMT) GIP(MMT) % Share OIP % Share GIP Source: Calculations as per IESS analysis The Table 6 above offers the assumed levels of oil and gas establishment under this exercise upto the year III d. General Assumptions: Future acreages would be awarded under Open Acreage Licensing Policy (OALP), which is under active consideration of Government given the fact that the National Data Repository (NDR) is under preparation. This may boost the share of supply from private/jvcs. With a strong base in India, ONGC would hold majority of acreages in future. The Government also aims to monetize the marginal fields of NOCs under revenue sharing arrangement which will reduce Government-contractor interface and help in bringing these resources into production. 18

19 Historical trends of crude oil production have been taken into consideration while estimating the production trajectories in case of ONGC, OIL and PVT/JVs across the four scenarios. ONGC s JV share is included in the production profile of ONGC. It has been assumed that volatility of oil prices and domestic self-sufficiency considerations will drive Improved Oil Recovery (IOR) and Enhanced oil Recovery (EOR) investments to continue in future. This is likely to boost the recovery factor from the present lows of near 28% in many prolific fields, including the Mumbai High to 40% in Heroic Effort scenario (L-4). The present drop in oil prices has come as a setback to some projects. But, the assured Indian oil/gas market and the likely generally upward trend of oil/gas prices will encourage oil/gas investments. The likely growth in IIP as per the historical trend, would still leave a balance of oil and gas reserves as per the prognosticated reserves in The production level will continue even beyond 2047 with government initiatives and OALP. It is assumed that shale gas production would prolong the productive life of Indian sedimentary basins, and even underground coal gasification (UCG) would help monetize coal deposits that are otherwise uneconomical to mine (owing to depth of deposits or poor grades), or even for environmental reasons. Surveys would be conducted for remaining unexplored area and this would allow companies to focus on attractive acreages. The proposed high recovery factor of 40% in L-4 is achievable for India, rather it is very conservative estimate keeping in view already achieved recovery factor of more than 45% for oil in North Sea fields and in the USA. Achieving recovery factor (R/F) of 40% would require huge investments, technology collaborations, and better policy framework. We may intend to improve recovery factor yet further, by making investment, better deployment of technologies and better policy framework. It is assumed that an enabling policy framework will be devised, however, what that framework would be, is beyond the scope of this exercise. Therefore, under different scenarios, it would be the R/F which would make a difference to the availability of domestic oil and gas supply with the highest R/F in the Level-4. The availability of new technologies for hydrocarbons E&P along with large scale implementation of the existing ones represents an essential condition to provide the world with the energy supply it needs as well as to give the companies who hold such technologies, a competitive lever to increase their chances to gain access to resources not presently available. 19

20 IV. Trajectories for oil: Level-1 (Least effort scenario) It projects a pessimistic scene wherein there is no improvement in recovery factors, and no new fields come into production barring the ones for which Final Investment Decision (FID) has been taken. This is a hypothetical construct to establish the lower extremity of the production band under the modeling exercise. ONGC attained peak production of 31.6 million tons in the year Thereafter, a continuous decline in production was observed till when actual production was 26.3 million tons. A low CAGR in production of crude of 1.17% was observed from to (Tenth Plan). Thereafter, the production from ONGC has been on a continuous decline at the rate of 0.67% till (end of 11th Plan). ONGC has provided its likely production profile upto 2022 and OIL up to These numbers have been adopted in this exercise. PVT/JV numbers have been provided by DGH up to 2022 and are taken as it is. For the following period various growth rates have been considered based on historical trend accounting from 2022 onwards. ONGC: (-0.5%) OIL: (1.4%) PSC Regime: (1%) Most of the fields are under natural decline viz. Ravva, Panna-Mukta. A sharp decline is projected from CAIRN s Rajasthan fields from 7.5 million tons per annum in to 2.8 million tons in (As per DGH estimates, most of the fields would be under sharp decline from the year to ). This discounts the discoveries under consideration/evaluation at various levels as they are not firm as yet. The production in 2047 would become 34.5 MMT. Beyond 2021, it is likely that discoveries for which DOCs have been submitted and are under various stages of development, are likely to produce. 20

21 Figure1: Exploitation of Oil in Place Reserves under Level 1 (Least effort) Cumulative reserve exploitation in L Cumulative Production (MMT) Ultimate Reserves (MMT) Oil in place (MMT) The figure 1 above indicates the projected initial oil in place reserves of about 9505 MMT in In Level 1, the Ultimate reserves (which can be technically extracted) have been calculated by applying a R/F of 28% to initial oil in place reserves, and is around 2661 MMT. The Cumulative production from the beginning, i.e to 2047 would be about MMT. This would leave a Balance recoverable reserve (BRR) of about 313 MMT. Level-1 assumes no improvement in present recovery factor of 28%. Hence, from the above graph, we find that reserves are not fully brought into production, thus a narrow band is found between cumulative production and ultimate reserves. The crude oil production in 2047 would be 34.5 MMT. Level-2 (Determined effort scenario): This is the normal/present scenario where the Government continues to make efforts to improve the oil/gas production landscape. New policies to help monetize discoveries continue to be launched but there is no dramatic change in the policy framework. A number of IOR/EOR schemes are underway. ONGC which is the major producer in the country has a number of EOR/IOR schemes in 15 ageing fields which account for 80% of its production. This would enhance its production. 21

22 ONGC would also monetise the reserves in its marginal fields (source: ONGC). Cluster approach for development of small discoveries has been assumed. This is also rendered possible by approval of the proposal of NOCs to exempt their production from these fields from contributing to under-recoveries of the downstream companies, thereby increasing their viability. In the case of OIL, a slightly better CAGR is taken as compared to the Level 1 (1.4%). A growth rate of 1.7% has been considered for future projections with a view that OIL will enhance its R/F in the future. Additional NELP discoveries which are under various stages of DOC approvals, FDP approval/ appraisal have been considered. 35 discoveries which are under various stages of approvals of DOCs/ FDP /IDP have been considered for production, out of which several fields may start production after 2021 onwards. Keeping above factor into consideration following growth in production has been considered: ONGC: ( 1% from 2017 onwards) OIL: ( 1.7% from 2017 onwards) PSC Regime: ( 1% from 2017 onwards and 1.5% from 2022 onwards) Level 2 assumes that the recovery factor of 30% would be maintained based on the investment plan of the companies. This would increase the production to about 59MMT/year by Level-3 (Aggressive effort scenario): This is an aggressive scenario wherein new fields are envisaged to come into production. It may be noted that there are a number of oil discoveries which are awaiting appraisal and development as of now. This level envisages that a number of them are found to be commercial and they come into production. Marginal fields would supplement the production. EOR/IOR schemes would be taken up aggressively. Further, new discoveries from already awarded NELP blocks and future NELP and OALP would commence production from 2021 onwards. About 50 oil discoveries are under various stages of approvals by DGH, and may come under production. 22

23 Keeping above prospects into consideration, following growth rate has been considered: ONGC: (1.0% growth from and 1.5% from 2017 onwards) OIL: (2% from 2017 onwards) PSC Regime: (1.5% from 2017 onwards) Level 3 assumes that a recovery factor of 35% would be maintained. At this recovery factor, the production would reach 68 MMT/year by Level-4 (Heroic effort scenario): This Level envisages contribution from shale oil and tight oil and a recovery factor of 40% is assumed. This envisages the most optimistic scenario with NOCs registering a continuous growth in oil production with a lot of private companies also increasing production. However, the cumulative oil production would still be within the total ultimate recoverable reserves. The availability of new technologies for hydrocarbon exploration and development along with large scale implementation of the existing ones represents an essential condition to provide the world with the energy supply it needs as well as to give the companies who hold such technologies, a competitive lever to increase their chances to gain access to resources not presently available. The North Sea fields have the best overall record of recovery, averaging 46%. The U.S follows with 39%. Oil fields with top recovery factors are Statfjord (North Sea) and Prudhoe Bay (U.S) with 66% and 47%, respectively. Hence, in this scenario, while acknowledging the role of different geologies and economics of production, yet a higher Recovery factor actor of about 40% has been considered to be attainable by India with streamlining the investments and better regulatory regime. This level assumes the following growth rates:- ONGC: (1.5% growth from and 2% from 2022 onwards) OIL: (2.5% from 2017 onwards) PSC Regime: ( 2% from 2017 onwards) The above scenario includes the best technological alliance of NOCs with major players, better recovery factors, deep-water exploitation of reserves and no rig unavailability problems for deep-water development,. In-house Capabilities have been assumed to be developed as an enabling factor. 23

24 Assuming a recovery factor of 40%, the crude oil production in 2047 would rise to 78 MMT. Figure 2: Exploitation of Oil in Place Reserves under Level 4 (Heroic effort) Cumulative reserve exploitation in L Cumulative Production (MMT) Ultimate Reserves (MMT) Oil in place (MMT) The above figure 2 shows the most optimistic scenario with 40% recovery factor with the ultimate reserves (recoverable) of 3802MMT at the end of The Cumulative production from 1948 to 2047would be about 3160 MMT. This would leave balance recoverable reserves (BRR) ( ) = 642 MMT still to recover. 24

25 Table 7: Maximum annual production of crude oil under different scenarios (in 2047). Levels Conventional Oil in Place (MMT) Recovery Factor Ultimate Reserves (that can be recovered Technically) (MMT) Maximum Annual Production (MMT) (2.3% of ultimate reserves) % % % % Source: Calculations as per IESS analysis The above table 7 shows us the maximum annual production that can be sustained in the year The crude oil production across different levels which is shown in table 8 below would be within in the maximum production numbers. The details of the calculation of maximum production are explained on page 15 above table 4. Crude oil production under scenarios. Year L-1 L-2 L-3 L Table 8: (MMT) different 25

26 Source: Calculations as per IESS analysis The above table 8 shows the production of crude oil in different years across the four levels/scenarios. 90 Figure 3: Crude Oil production trajectories Crude Oil Production (MMT) L-1 L-2 L-3 L-4 26

27 The above figure 3 shows the historical (actual) as well as the likely production of crude oil till 2047 across four levels/scenarios. 27

28 V. Overview of the structure of the Natural Gas Production worksheet: Va. Basic or Fixed Assumptions: Production profile has been classified into various categories i.e. ONGC (including its private/jv share), OIL and PVT/JVCs, CBM, Shale gas, Underground Coal Gasification (UCG). This is useful as the first 2 operate largely under the nomination regime, while the third is under the PSC regime. The Growth of initial in place (IIP) reserve accretion (oil + oil equivalent of gas (O+OEG) from 2004 to 2012 has been at CAGR of about 2.55%%. While making assessment for future growth in initial in place reserves estimate (O+OEG), same growth rate has been extrapolated. At this growth, the IIP reserves establishment is likely to be of the order of billion tons in 2047 out of the total prognosticated reserves of 28.1 billion tons by DGH for 15 sedimentary basins. Keeping in mind the changing mix of recent discoveries in favour of gas, it is expected that the share of oil reserves in 2047 would be 9.5 billion tons (40%) and that of gas billion tons (60%). This assumption would be common across the 4 scenarios. The scenario building exercise leaves scope for further reserve establishment within 26 sedimentary basins as till only 19% of area was moderately to well explored. As on the status reported by DGH indicates about 48% of sedimentary basins still to be appraised. The appraisal here means the status of knowledge building efforts for evaluating hydrocarbon prospectivity of the basin through Geological studies, Geophysical surveys and exploratory drilling (DGH). Further, the unexplored areas of the balance 11 sedimentary basins would also contribute to the reserves. (India has 26 sedimentary basins). As the scenario building exercise is working only on the prognosticated reserves of 15 basins, establishing billion tons of reserves by 2047, it is assumed to be a realistic phenomenon, yet leaving scope for further reserve establishment within the 15 basins, as well as the balance 11 basins. Since the major objective of the IESS, 2047 is Energy Security (defined as Import reduction); therefore, only domestic gas production levels have been generated in this exercise. Import of gas through the LNG route and transnational pipelines will be able to meet the deficit demand of the consuming sectors beyond the domestic supply volumes, and are naturally taken as imports. The likely reserve establishment for oil and gas under the above set of assumptions is the same as given in Table 2. 28

29 Vb. General Assumptions: With the government initiatives and OALP, it may be stated that surveys would be conducted for remaining sedimentary basins and unexplored areas and this would allow companies to focus on attractive acreages. To achieve recovery factor of 80% in gas fields, huge investments, technology collaborations, and better policy framework would be required. The availability of new technologies for hydrocarbon exploration and development along with large scale implementation of the existing ones represents an essential condition to provide the world with the energy supply it needs as well as to give the companies who hold such technologies, a competitive lever to increase their chances to gain access to resources not presently available. Gas prices have been revised periodically by the government until it was revised last in April, 2015 reducing the price to $4.66 per mmbtu from $5.05 per mmbtu. Though the prices are not fully aligned with the international market, there is a scope of revision which might incentivize further exploration and production of gas. There is also a likelihood of Government declaring higher prices to incentivize new production from deep waters. As regards point estimate (default) price of domestic gas from 2017, the following assumption is made, a hike of 20% in the present price of $ 4.66/mmbtu is presumed until As a part of general assumption, all prices are in real terms. However, these are merely indicative numbers, and no estimation/forecast/likely Government view of gas prices is being offered in this Tool. The past historical data of Natural Gas production in India has been kept in perspective while generating estimates for Levels 2, 3 and 4. BP statistical review numbers for yearly gas production from 1994 onwards (i.e. the year of opening up of Upstream Hydrocarbon Sector) have been considered as historical data. The Levels 2, 3 and 4 also capture production from unconventional sources. Latest technological developments have made Shale Gas development scenario a reality and it has been assumed that Level 2, 3 and 4 production scenarios will include shale gas production, albeit in differing time frames. Similarly UCG, which is yet in a pilot stage in the world, is expected to become a commercial venture in the aggressive Level-3. Even, CBM production rises in upper levels. The above situation is quite likely in a large coal endowed nation like India. 29

30 Recovery factor has also been suitably assumed across the 4 different scenarios. It assumes to establish about billion tons of Gas in Place (GIP) in The maximum production that can be sustained in different levels in the year 2047 are provided below: Table 9: Maximum annual production of natural gas under different scenarios (2047). Levels Conventional Gas in Place (MMT) Recovery Factor Ultimate Reserves (that can be recovered Technically) (MMT) Maximum Annual Production (MMT) (1.5% of ultimate reserves) % % % % Source: Calculations as per IESS analysis The table 9 above takes into account the reserves and production from conventional natural gas only, the unconventional sources of shale gas, CBM, UCG and gas hydrates are not considered due to unavailability of exact data. Also, the details of the calculation of the maximum production of natural gas are explained on page 16 above table 5. 30

31 VI. Trajectories for Gas Supply: With the growth in O+OEG reserves from 2004 to 2012 at a CAGR of 2.55%, total IIP reserves a r e projected to be billion tons in The share of oil and gas IIP would be 9.5(40%) billion tons and billion tons (60%), respectively. The Gas recovery factor is currently in the range of 55-60%. The four Levels of likely gas production leading upto 2047 are based on rising recovery factors (R/F) and production from unconventional sources of gas and UCG. The gas production in four scenarios (levels) are based on the projection of the production profiles of ONGC, OIL and PVT/JVs. Level 1 (Least Effort Scenario): Level 1 incorporates only the future production from current discoveries of conventional gas and CBM. This scenario includes existing /approved gas fields. As the first level is one of a pessimistic scenario, it does not envisage production from new fields, but includes only minor growth of gas supply. However, the other levels capture future production from new fields. It considers discoveries for which reserves that have been established and investment has been scheduled (e.g. GSPC gas discoveries in the block KG-OSN 2001/3, ONGC discoveries in block KG-DWN-98/2, Mahanadi blocks MN-DWN-98/3 and MN-OSN-2000/2, and Reliance discoveries in the blocks KG-DWN-98/3, NEC-OSN- 97/2, KG-DWN-2003/1 and CY-DWN-2001/2). Level 1 also includes production from ONGC reserves in nomination blocks. Since some of the above discoveries in deep water blocks are commercial only at higher gas price than what are currently prevalent, it has been assumed that gas prices will undergo revision periodically. Level 1 incorporates only future production from the current discoveries of conventional gas and CBM (not from new discoveries). Historical production has been taken into account. It does not include any production from shale or Underground Coal Gasification (UCG). Domestic gas supply reaches about 81.5 BCM in This Level assumes R/F of 55%. The share of PVT/JVCs in the total production in 2047 would be 19% as compared to 75% of NOC s (ONGC-63% & OIL 12%) and CBM would contribute around 6%. Level 1 is based on the long term production profiles of ONGC, OIL and PVT/JVs (Source: DGH and MoP&NG). Since, level 1 is a pessimistic scenario, production is based on current reserve estimates. Following growth rates have been assumed observing the actual growth rates attained by the above explorers (ONGC, OIL & PVT/JVs) till ONGC: 1% from 2017 and 2.3% from 2022 onwards OIL: 2.1% from 2017 and 4.3% from 2022 onwards PVT/JVs: 2.2% from 2017 and 2.25% from 2022 onwards 31

32 Level 1 assumes CBM production from existing 5 blocks for which field development plans (FDP) have been approved, reserves have been established and production profiles have been generated. These blocks are operated by GEECL, Essar, Reliance and ONGC. However, CBM production has been assumed to grow significantly as Government is keen to revive fertilizer Plants and ensures to achieve the production as targeted. The share of CBM is likely to increase in the total production of natural gas of about 5 BCM (i.e. about 7%) in However, weak infrastructure will hinder the development of CBM. Figure4: Exploitation of Gas in Place Reserves under Level 1 (Least effort) Cumulative reserve exploitation in L Cumulative Production (MMT) Ultimate Reserves (MMT) Gas in Place (MMT) The figure 4 above indicates the projected initial gas in place reserves of about MMT in In Level 1, the Ultimate reserves (which can be technically extracted) have been calculated by applying a R/F of 55% to initial gas in place reserves, and is around 7841 MMT. The Cumulative production from the beginning, i.e to 2047 would be about MMT. This would leave a Balance recoverable reserve (BRR) of about 5489 MMT leaving a large scope of improvement in domestic gas production. Level 2 (Determined effort scenario): Level 2 assumes moderate activity of CBM development. This level also assumes that there will be yet balance CBM reserves which will still be left unexplored in We are aware that the evacuation infrastructure is weak for this low pressure gas, and under this scenario continues to be so. Shale gas makes its debut at end of the13th Five Year Plan (FYP) i.e This takes into account new gas production of NOCs/Private, as new fields get appraised and go into commercial production. Level-2 assumes R/F of 60%. The domestic gas supply would reach a level of BCM in The share of PVT/JVCs in 32

33 the total production of natural gas in 2047 would be 37% as compared to 56% of NOCs (ONGC-45% & OIL 11%). The rest (7%) would be unconventional share coming from shale gas and CBM. Level 2 assumes improvement in existing policies in pipeline sector. However, shale gas makes its debut, and this level assumes future production from shale gas starting only from fag end of the 13 th Five Year Plan i.e As Level 2 contemplates current policy scenario, the recently announced shale gas policy for NOCs has been factored into this level, without much impetus for private sector play. Level 2 assumes no gas production coming from Underground Coal Gasification. The level being consistent with government Policy assumes continuation of the present gas price and utilization approval policies, which are, however, still found not found attractive by International Oil Companies (IOCs), who may aspire for international gas prices. This level takes into account new gas production of NOC s/private from discoveries which are presently under appraisal. It is assumed that many of these existing discoveries will get appraised and go into commercial production. This level takes into account the projection provided by NOCs (ONGC + OIL) and the numbers upto are based on it. The various growth rate (CAGR) assumption have been affected from 2022 onwards for: ONGC: 2.5% OIL: 5.5% PVT/JVCs: 6.5% Level 3 (Aggressive effort scenario): Level 3 is an aggressive scenario which will require additional policy inputs to spur the growth of natural gas sector. Improved data availability de-risks E&P activity. It is assumed that price/utilization approvals are no longer required as the gas market has completely evolved in India. The above two seem to be the major focus of present gas policy debates. Level 3 assumes all presently available CBM reserves will be under production by the year 2047 and the CBM production would reach to around 8 BCM in This level assumes moderately optimistic scenario for shale gas development in India. It assumes the future production from shale gas would start from i.e. just before the end of 13 th FYP. However, less than half of the shale gas resources, as assessed presently, may only be exploited by 2047 and the full story of shale gas is yet to be unfolded in this level. Level 3 also assumes gas production coming from underground coal gasification (UCG) from 2027 onwards (15 th five year plan), albeit at level of 2 BCM/annum. Although huge potential for UCG is available in the country but this still needs technological breakthrough to monetize the unextractable coal. In India un-extractable coal and lignite resources have been estimate to the tune of 275 Billion Tons. 33

34 It assumes R/F of 70% from the existing fields. Gas supply would reach about BCM by The share of PVT/JVCs in the total production in 2047 would be 32% as compared to 53% of NOCs (ONGC-43% & OIL 10%) in natural gas, and the rest 14% share would comprise of unconventional resources (shale gas, CBM and UCG). Since, Level 3 is an aggressive effort scenario, higher growth rates have been assumed. ONGC: 3.25% from 2022 onwards OIL: 6% from 2022 onwards PVT/JVs: 6.5% from 2022 onwards Level 4 (Heroic effort scenario): Level 4 is the most optimistic scenario. It assumes a highly favourable upstream regime wherein IOCs find it attractive to come to India and gas pricing/utilization provisions have been done away with and free market pricing has set in. This level raise gas production with highest recovery factors and from deep waters too., This level opens up market for Power and Fertilizer sectors to address issue of accessibility and the stranded power capacity would revive, thereby increasing its PLF. The above two ambitions have already been adopted by the Government for speedy fruition. It assumes an aggressive conventional gas scenario and CBM exploitation, a moderate shale gas production and commencement of UCG from 15th FYP but maximum supply from UCG is about 9 BCM/ annum in the year Even the un-assessed 11 sedimentary basins may come under production in the later decades. This scenario finds support from a carbon reduction drive of the Government, too. India holds 933 TCF of gas hydrate reserves (source: DGH) however, no commercial production has been established yet. Recently, Japan has unveiled first gas hydrate production in March, 2013 on a pilot scale. Therefore, level 4 assumes that a technological breakthrough of gas hydrate takes place and production starts from 2032 onwards. Japan, as mentioned above, has indicated 20% to 26% recovery factor in the R&D stage. India estimates 933 TCF of gas hydrates. Taking 10% recovery factor, we may consider the resources of about 93 TCF (a total of about 2630 BCM) of gas from gas hydrates, but there is no assurance of commercial establishment of production from gas hydrates. Level-4 assumes R/F of 80% which would safely sustain production level of about 224 BCM/year in the year The share of PVT/JVCs in the total natural gas production in 2047 would be 33% as compared to 52% of NOCs (ONGC-41% & OIL 11%) and the unconventional share would be about 15% comprising shale gas, CBM, UCG and gas hydrates. The following growth rates have been assumed in level 4: ONGC: 3.5% from 2017 onwards and 4% from 2022 onwards OIL: 4.25% from 2017 onwards and 6.5% from 2022 onwards 34

35 PVT/JVs: 6.25% from 2017 onwards and 7.5% from 2022 onwards Figure 5: Exploitation of Gas in Place Reserves under Level 4 (Heroic effort) Cumulative reserve exploitation in L Cumulative Production (MMT) Ultimate Reserves (MMT) Gas in Place (MMT) The above figure 5 shows the most optimistic scenario with 80% recovery factor with the ultimate reserves (recoverable) of 11405MMT at the end of The Cumulative production from 1948 to 2047would be about 3729 MMT. This would leave balance recoverable reserves (BRR) of ( ) = 7676 MMT still to be recovered. 35

36 Table 10: Natural Gas production from conventional and unconventional sources (BCM) in different years across four levels. Year L-1 L-2 L-3 L Source: Calculations as per IESS analysis The Table 10 above shows the gas production in different timeframes under the four scenarios. The contribution of gas from different sources may be seen in the Excel sheet (XV.a) which can be downloaded from the IESS 2047 Version 2.0 website. It is clear that India has the opportunity to increase its gas production (from the same level of reserves) by more than 2.5 times from 2012 to 2047 if Level 2 is considered and the gas production would increase 3.5 times by 2047, by improving R/F if level 3 is taken into account. Conversely, the country could end up with poor exploration of its potential if the right mix of technology and policy environment is not available. This exercise helps to place the perspective of domestic oil and gas production in the overall energy scenarios of the country, to make an estimation of future level of imports to meet the demand of oil and gas under different scenarios, and create scenarios as to how much gas in the form of LNG or through trans-national pipelines would be imported. 36

37 Figure 6: Gas Production trajectories under different levels Natural Gas Production (BCM) L1 L2 L3 L4 The above figure 6 depicts the historical (actual) as well as the likely natural gas production till 2047 of India in year 2047 under different Levels. 37

38 VII. Costing: In the IESS V 2.0 a new feature of cost implications has been added. This will help users of the Tool to evaluate different pathways not only on the basis of parameters of implications on imports and emissions but cost as well. Therefore, we have included our cost projections in the sector Excel sheets as well. In order to estimate cost of petroleum products and gas, we need to start with the price of crude and natural gas paid to the upstream/oil and gas producer. Thereafter, the cost of processing/transporting crude and in the case of natural gas, merely cost of transportation has to be accounted for. As regards imported gas, we have to estimate the cost of handling/tolling at the LNG terminals. The following discussion explains as to how the cost estimates have been derived. It may be added that as there is large uncertainty around prices in the next 3 decades or more, the IESS offers three estimates of prices, allowing the user the choice of adopting the cost as may be preferred. Looking to the recent drastic drop in the prices of crude and gas, there is a large uncertainty around such an exercise. However, when the total cost of a pathway has been derived, the user can undertake sensitivity analysis on oil/gas costs to derive the big picture on the arbitrage involved in moving away from fossil fuels or continuing with it. For an import dependent country like India, it is important to err on the side of higher prices as we need to strategise means of protecting our public finances, which are affected significantly when crude prices rise. The volatility of oil and gas prices is expected to remain high in the long term, however, the present prices are experiencing a declining trend. High Import dependence of Crude Oil (80%) and Natural Gas (27%) has become a financial drain on the FE reserves of the country. Since, it is difficult to project the oil and gas prices, a range of prices is considered, namely- high, point and low cost scenarios, which will try to capture the likely prices in future. While doing the cost analysis, various taxes levied by the Government have not been taken into account as in India different State Governments have different tax structures, so, only the economic cost is being considered. There is no surety of changes in tax structure either. As a major chunk of our crude oil requirement is being imported, imported and domestic crude oil prices have been considered identical. The above is as per the extant Government policy, too. The crude prices have been derived from the International Energy Agency s (IEA) World Energy Outlook (WEO) which describes three policy scenarios i.e. Current, New and 450 Policy scenario giving three different prices of crude oil. The current policy scenario is taken as the high cost estimate, new policy scenario as the point cost or default estimate and 450 scenario as the low cost estimate to arrive at the prices. The cost algorithm in the IESS sums up the cost of the pathway for the period The baseline crude price is for the year 2012, and has been taken from the earlier version of IESS, which took the crude price from the information contained in WEO However, as regards the future oil price projections, we have relied on the latest WEO edition, i.e, WEO As the WEO is released towards year-end, we are presently using older numbers (2014 version), and could update the same when 2015 edition is released. 38

39 The pricing of Natural Gas around the world have been governed by regional markets - Asian market is governed by JCC crude Index price of Japan, European market by UK National Balancing Point and USA by Henry Hub prices. Gas pricing has been an issue of debate in our country. While the price of domestic natural gas has not been market driven, but the prices for both PVT/JVCs and NOC gas is expected to be same in the near future. As regards influence of international gas prices, it is considered that the country s gas market will evolve beyond 2022 in the Level 3 and 4. In Level 1 and 2, we presume that gas markets have not developed, and there is poor production of gas which results in continued government oversight of pricing and utilization of gas. Although it may be very difficult to deregulate the gas prices immediately, but to send the right signal and show the clear picture to customers/producers, it is desirable to eventually deregulate the gas prices as has been done for petrol and diesel prices. In our analysis, the domestic and imported gas prices vary till 2022 after which they become alike as explained above. The 2012 domestic gas price is taken from the Ministry of Petroleum and Natural Gas (MoPNG) website. The Point Estimate for 2017 domestic price is calculated by moderately increasing the prevailing domestic gas price of $4.66/mmbtu by 20%. The low estimate for 2017 domestic price is computed by increasing the domestic gas price of $4.27/mmbtu (as it prevailed in 2012) by 20%. The high estimate for 2017 domestic price is calculated by increasing the price in proportion with low and point estimates. Apart from the fuel costs, the infrastructure cost of refineries, pipelines and LNG import terminals have also been taken into consideration. This is essential to derive the cost of refined products. While the price of crude/gas can be derived on the basis of international prices, but this is not the case for products. It may be noted that these costs (of infrastructure) have been taken as uniform costs over the life of the assets. The high and low estimate for capital cost of refineries is taken as Rs 25 billion/mtoe and Rs 20 billion/mtoe respectively which is derived by consultation with Engineers India Limited (EIL). The asset life of a refinery is taken as 60 years. So, the cost of refinery can be spread over 60 years which comes out to be Rs 417 million/mtoe/year as high estimate and Rs 333 million/mtoe/year as low estimate. The point estimate for capital cost of refinery is taken as the average of high and low cost estimates. The high, point and low estimates for operating cost of 1 Mtoe refinery excluding fuel costs is taken as 4.4% of the high, point and low estimates of capital cost respectively. The high and low estimate of the total cost of pumping and transporting 1 Mtoe of crude oil through pipeline is taken as INR 1400 and 1200 per Km per 1000 tons, respectively which is derived after detailed consultation with Indian Oil Corporation Limited (IOCL). It is assumed that petroleum products travel an average of 600 kms in India and life of a pipeline is 40 years. Also, it is assumed that the capital and operating cost of pumping and transporting 1 Mtoe of crude would be 95% and 5% of the total cost. Therefore, the capital cost of transporting 1 Mtoe crude oil through pipelines can be calculated which comes out be Rs 798 million/mtoe as high estimate and Rs 684 million/mtoe as low estimate. The point estimate for capital and operating cost is taken as the average of high and low cost estimates. 39

40 The high, point and low estimate of capital cost for import docking of 1 Mtoe of crude oil through pipeline is taken as Rs 190 million/mtoe derived after consulting with industry. The operating cost of the same is taken as 5% of the capital cost corresponding to the high, point and low cost estimates. The high and low estimate of the total cost of transporting gas through pipeline is taken as $1/mmbtu and $0.4/mmbtu respectively while the point estimate is taken as the average of the high and low cost estimates. The capital and operating costs have been taken as 95% and 5% of the total costs incurred. So, the high and low estimate of capital cost of transporting 1 Mtoe of gas through pipeline would come around to be Rs 1810 million/mtoe and Rs 724 million/mtoe respectively. The point estimate of capital and operating cost is taken as the average of high and low cost estimates. The above cost estimates have been taken after consultation with Petronet. The high, point and low estimate of the total cost of 1 Mtoe LNG import terminal in India is taken as INR 45/mmbtu after consultion with LNG terminal operators. The capital and operating cost is taken as 95% and 5% of the total cost incurred for 1 Mtoe import terminal. Therefore, the unit levelized capital cost of 1 Mtoe LNG import terminal would come around to be 1697 million/mtoe and operating cost would be 89 million/mtoe LNG. There are three scenarios of cost estimation of crude oil, natural gas and infrastructure (refineries, pipelines, import terminals etc.) i.e. high, point and low, so many combinations can be made to calculate the final cost of crude oil and natural gas that has to be paid. But, the Tables 11 and 12 below show the cost calculation done by taking the point cost (default) estimates into consideration. 40

41 Table 11: Total cost of crude oil incurred (excluding taxes) in INR/bbl and INR/litre (in real 2012 prices) Crude Oil Price (INR/bbl) Capital cost of refining crude oil (INR/bbl) Operating cost of refining crude oil (INR/bbl) Capital cost of pipeline (INR/bbl) Operating cost of pipeline (INR/bbl) Capital cost of import dockingcrude oil (INR/bbl) Operating cost of import docking- crude oil (INR/bbl) Total cost of Crude Oil (INR/bbl) Total Cost of Crude Oil (INR/litre) Source: Calculations as per IESS analysis 41

42 Table12: Total cost of natural gas incurred (excluding taxes) in INR/mmbtu (in real 2012 prices) Natural Gas Price (INR/mmbtu) Capital cost of pipeline (INR/mmbtu) Operating cost of pipeline (INR/mmbtu) Capital cost of LNG import terminal (INR/mmbtu) Opearting cost of LNG import terminal (INR/mmbtu) Total cost of Natural Gas (INR/mmbtu) Source: Calculations as per IESS analysis 42

43 VIII. Conclusion: The above exercise leads us to conclude that there is a large prospect of oil and gas reserve establishment in India. The DGH data regarding growth in Oil-in-Place and Gas-in-Place Reserves as indicated in Table 2 gives us the above assurance. We are also aware that only 15 basins out of 26 basins have so far been evaluated to some degree of confidence yielding a likely prognosticated reserve of 28 billion tons of oil and gas. The IESS analysis is an overall energy tool which relies on existing information regarding resources availability. It does not undertake independent assessment of resource availability, but merely the policy and technology levers that may influence demand and supply of energy. Hence, if we were to rely on the available resource quantification, and develop likely levels of oil and gas supply, it can lead to policy interventions to achieve the maximum potential. In the case of oil, we can see in Table 7 that the technically recoverable reserves in Level 4 (Heroic case) are higher over the default case by over 40%. Similarly in Table 9 we can see that in gas, the same difference is also little under 40%. As regards production rate from the Ultimate Reserves, the historical relationship between Ultimate reserves and production, separately for oil and gas is assumed. It is merely ensured that at the assumed rate, the total production should not exceed the ultimate reserve levels by It is granted that oil and gas discoveries and production do not follow a uniform trend, but the discovered resource has to be brought above the ground sooner or later. The instant exercise merely gives the volume involved. As regards the other sources of hydrocarbons, particularly shale reserves, CBM and UCG, again the IESS identifies their potential on the basis of available information of reserves. Again this helps in understanding the significance of these fuel types, and the effort needed to bring them into production. As regards import dependence, as the Tool is unique in its useful of generating demand sector wise demand for oil and gas, the urgency to raise domestic production in the light of domestic production is generated by this tool. This may also propose action on demand side to take steps to develop substitutes or make fuel switches. Therefore, this exercise from the supply end is useful to match demand projections at different points of time. The costing exercise is merely to offer numbers to create import bills, cost of pathways and relative cost of energy in calorific terms. As economic costs are taken, we assume international cost of crude and make assumptions about cost of gas. Looking to the present dramatic drop in oil and gas prices, it is difficult to make credible assumptions on future prices. Therefore, reliance is being placed on projections of other agencies such as EIA and IEA. The Energy Information Administration (EIA) has projected the oil and gas consumption in India to grow at a CAGR of 3.5% and 4.6% respectively. The IESS model projects the oil and gas consumption at a CAGR of about 3.6% and 3.8% respectively. As regards domestic production, the Kelkar Committee has estimated that the potential to enhance domestic oil and gas production between BAU scenario and concerted efforts by 2030 is in the realm of a factor of 2.5 Therefore, there is indeed a big opportunity of improving the performance of this sector by stepping up efforts. 43

44 In the end, it can be said that oil and gas exploration business is probabilistic in nature, and works on the basis of qualified assessments. India is yet to explore more than half of its sedimentary basins, or even acquire basic data to be able to offer it to E&P companies. Various studies have conjectured the likely resource availability on extrapolation method, but not on a dis-aggregated basis as has been done in IESS. Similarly, on the demand side numbers have been projected on projecting historical growth rates. In IESS, the bottom-up exercise offers leads on demand and supply side interventions. In the oil and gas sector, the analysis of in-place reserves and proved reserves highlights the difficulty being faced on converting finds into production. The link between in-place reserves and proved reserves is more direct as compared to, proved reserves into production. However, the size of the prize is essential to be estimated which is done by estimating likely production should the in-place reserves by converted into proved reserves. 44

45 IX. Notes: 1. Initial in Place (IIP) Reserves- It is the quantity of petroleum that is estimated, as of given date, to be contained in known accumulations prior to production. Therefore, IIP Reserves = (Proved + Probable + Possible) Reserves + Contingent Reserves 2. Proved Reserves- There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. 3. Probable Reserves- There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. 4. Possible Reserves- There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. 5. Contingent Resources- It is the quantity of petroleum estimated, as of given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to economical or technological constraints. 45

46 X. Bibliography: 1. 12th Five Year Plan ( ), Planning Commission, Government of India. 2. Exploration and Production Activity Reports Director General of Hydrocarbons 3. Petroleum & Natural Gas Statistics, Ministry of Petroleum & Natural Gas. 4. BP Statistics- June Petroleum Resources Management System. 6. World Energy Outlook. 7. ONGC Perspective Planning UK2050PathwaysCalculator: /primary_energy_chart 9. China2050PathwaysCalculator: /primary_energy_chart 10. SPE journals on Exploration and Production. 11. Articles related to Gas Hydrates from the websites, internet news, etc df %20The%20Next%20Revolution.pdf 15. Oil & Gas Journals: 41/exploration-development/global-oil-reserves-1-recovery-factors-leavevast-target-for-eor-technologies.html 16. Annual Activity Reports of Directorate General of Hydrocarbon, India. 17. file:///c:/users/ac/downloads/coal%20%20gasification%20(1).pdf 46