A Primer on India Ep Valuations

Please refer to important disclosures at the end of this report

Exploration & Production

A primer on India E&P valuations Theme report: Comparison of valuation methodologies for E&P assets

Equity Research January 11, 2010

Oil&Gas and Petrochemicals

Amit Mishra, CFA [email protected] +91 22 6637 7274 Gagan Dixit [email protected] +91 22 6637 7480

We present a primer on the India exploration & production (E&P) space, comprising the most apt valuation methodologies. Owing to different tax structure of E&P firms globally, valuing them on earnings and reserves multiples delivers erroneous results. Moreover, since most Indian firms are in the early stages of exploration & appraisal (ex ONGC and Oil India-OIL), we expect significant earnings volatility for these companies going forward.

We illustrate that DCF and EV/reserves are the most prudent methodologies for valuing an E&P firm in India. We also draw on the pitfalls in the EV/reserves-based methodology that are mainly owing to time taken by a firm to bring reserves to production. Further, we have valued India’s key E&P blocks, including Reliance Industries’ (RIL) KG D6 (only gas reserves), MN-D4, KG-D3, KG-D9 & NEC-25 blocks, Cairn India’s MBA Field (Rajasthan) and Gujarat State Petronet Corporation’s (GSPC) Deen Dayal block (KG Basin). Additionally, we have expounded relative valuations (both, adjusted for time difference as well as current) of these blocks.

Not logical to ascribe earnings and cashflow multiples, in our view. Though the market may value E&P firms based on earnings- & cashflow-based multiples, we do not believe it is prudent to use a multiple-based approach as earnings and cash are volatile owing to investment multiple (IM)-based profit-sharing and production declines.

DCF, EV/reserves – Best valuation methodologies for E&P. Although DCF is the best method for valuing an E&P block in India, it is time consuming, and projections are difficult and may be erroneous, especially if the production schedule is not known. On the other hand, EV/reserves (adjusted for time difference) is the most precise method to value an E&P firm in India.

RIL – Key promising eastern offshore blocks MN-D4, KG-D3, KG-D9 and NEC-25 deserve lower value at present versus its KG-D6 block owing to: i) time-value of money till commencement of production from these blocks; KG-D6 production has already commenced, ii) significant development capex requirements of the blocks that would further lower value; on the other hand, most KG-D6 capex is already complete.

Comparative valuations of India’s key offshore blocks KG-D6 KG-D3 MN-D4 KG-D9 NEC-25 GSPC DDCommencement of production FY10 FY16 FY16 FY16 FY13 FY13Peak production (mmscmd) 120 79 125 90 71 84Gross recoverable reserves (tcf) 13.8 9.5 15.0 10.8 8.5 10.0NAV at FY10 end (US$ mn) 12,290 674 1,568 1,095 2,557 2,723NAV/recoverable reserves at FY10 end (US$/mcf)

0.89 0.07 0.10 0.10 0.30 0.27

NAV at production start (US$ mn) 11,107 8,034 13,152 9,687 7,463 8,253NAV/recoverable reserves at production start (US$/mcf)

0.81 0.85 0.88 0.90 0.88 0.83

Source: I-Sec Research

INDIA

E&P Primer, January 11, 2010 ICICI Securities

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TABLE OF CONTENTS

India E&P valuations .......................................................................................................3 DCF – Judicious valuation methodology.........................................................................3 EV/reserves – Works best for quick estimates ...............................................................3 DCF offers more advantages vis-à-vis other methodologies..........................................3

Applying EV/reserves- & DCF-based methodologies for valuing India E&P.............4 EV/reserves.....................................................................................................................4 Standardised measure of discounted cashflows ............................................................5

India E&P versus US peers – Not an apples-to-apples comparison ..........................8 E&P investor guide – Key parameters to track...........................................................11

Reserve Replacement Ratio (RRR)..............................................................................11 Finding & Development (F&D) cost ..............................................................................11 Production and Lifting costs..........................................................................................11 Exploration, Development plans ...................................................................................11

Key parameters impacting E&P valuation...................................................................12 Oil & gas pricing ............................................................................................................12 Taxes & royalties...........................................................................................................12 Profit sharing .................................................................................................................12 Reserves mix ................................................................................................................12 Quality of reserves ........................................................................................................12 Location of reserves......................................................................................................12

India Upstream ...............................................................................................................13 Policies..........................................................................................................................14

Valuation of some of India’s key upstream blocks ....................................................17 KG-D6 ...........................................................................................................................18 KG-D3 ...........................................................................................................................19 MN-D4...........................................................................................................................20 KG-D9 ...........................................................................................................................21 NEC-25 .........................................................................................................................22 GSPC’s Deen-Dayal block............................................................................................23 Cairn’s Rajasthan block (RJ-ON-90/1)..........................................................................24

Annexure 1: Oil and Gas E&P basics ..........................................................................25 Answers to elementary questions .................................................................................25 E&P business – Various stages....................................................................................28 Understanding the definition & classification of ‘reserves’............................................33

Annexure 2: Key exploration risks...............................................................................37 Annexure 3: Oil & gas properties vital for valuation..................................................38 Annexure 4: Domestic oil & gas pricing......................................................................39 Annexure 5: Glossary & abbreviations of key terms .................................................42 Annexure 6: Index of Tables and Charts .....................................................................50


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India E&P valuations Earnings of any E&P firm are inclined to be volatile owing to dry well write-offs and other one-offs in its P&L statement. Moreover, earnings usually decline with time on account of natural production decline in oil/gas fields, unless new fields/wells are brought under production. Particularly in India, investment multiple (IM)-linked profit sharing results in highly volatile earnings, making valuation of assets difficult.

We have explored various methods used for valuing an E&P firm and presented relative shortcomings of these methodologies.

DCF – Judicious valuation methodology We believe the most prudent method for valuing an E&P firm in India is the detailed DCF model, which captures all nuances of variations in commodity prices, production declines, IM-related profit sharing as well as variable royalty & tax structure. However, key lacuna is lack of data availability for making detailed assumptions of production and forecasting commodity prices accurately.

EV/reserves – Works best for quick estimates The EV/reserves methodology is fairly simple and widely used for quickly valuing E&P firms for reference, if detailed information about E&P assets is unavailable for DCF-based analysis. EV/reserves-based value needs to be adjusted for time-value-of-money, development capex requirements and some premium (or discount) for favourable (or unfavourable) royalties, taxes and IM.

DCF offers more advantages vis-à-vis other methodologies Except DCF, no methodology is able to capture significant earnings variability over time due to changing government sharing on account of complex IM calculations (Table 1).

Table 1: Advantages & disadvantages of various valuation methodologies Methodology Advantages Disadvantages

Ideal for valuing Indian E&P as it incorporates complex IM-linked government profit sharing, which is not captured by other valuation methodologies

Often, data non-availability for detailed DCF analysis is key drawback

Captures impact of all company-specific & other variables Quick valuation is not possible

DCF

Provides implied P/E, P/FCF, EV/EBITDA, EV/reserves After DCF, the best for valuing E&P firms for quick reference

Does not capture commodity price or other variables changes impact on complex IM calculations, and subsequent impact on value

Data availability is generally not an issue EV/reserves

Quick approach to value company reserves

Quick to apply Does not incorporate valuation impact of IM calculations, taxes/royalties benefits, production & cost profile etc P/E

Does not factor earnings difference due to leverage & exploration expenses

Quick to apply Not able to incorporate valuation impact from key variables such as IM calculations, taxes/royalties benefits, production & cost profile etc EV/EBITDAX Better than P/E as it accounts earnings difference due

to leverage & exploration expenses This method could incorrectly give similar values for similar earnings assets despite significant difference in quantity of reserves

EV/FCF Quick to apply Does not incorporate valuation impact from IM calculations, taxes/royalties benefits, production & cost profile etc

Better than P/E as it accounts earnings difference due to leverage & exploration expenses

This method could incorrectly give similar values for similar earnings assets despite significant difference in quantity of reserves

Note: EBITDAX – EBITDA before exploration expense; Source: I-Sec Research


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Applying EV/reserves- & DCF-based methodologies for valuing India E&P

EV/reserves

In this method, key variables for valuing an E&P firm in India are: i) reserve type (oil, gas) ii) quality of reserve (calorific content of gas; API of crude) iii) capex requirement iv) profit sharing formula v) time taken for commencement of commercial production vi) risk to reserves accretion.

Methodology Guidelines to value an E&P firm are:

Step 1: Calculate a benchmark EV/reserves multiple for oil, gas reserves – EV/reserves for gas would be lower owing to regulated pricing.

Step 2: Of this EV/reserves multiple, some premium/discount should be ascribed, based on quality of reserves, capex requirements and profit-sharing formula.

For example, blocks with higher government sharing for IM deserve discount on their EV/reserves multiples versus KG-D6, owing to lower cashflows to E&P firms. Similarly, EV/reserves multiple of blocks with higher per-unit capex requirements should be lower vis-à-vis KG-D6. Likewise, higher quality reserves (i.e., higher calorific content of gas, higher API of crude) merit a higher EV/reserves multiple owing to better per-unit sales price that would lead to higher cash margins.

Step 3: Forecast the possible recoverable reserves in the block (adjusted for the risk to recovery, if any) and multiply this number with the aforementioned EV/reserves multiple to attain EV of the block in the year of commencement of production.

Step 4: The aforementioned EV of the block (at commencement of production) should be adjusted for capex requirements and time-value-of-money till production commencement for obtaining the block’s present value. Hence, this EV should be discounted to the present date, and the NPV of capex in the interim should be deducted.

Illustration: EV/reserves – Rough valuation for new discovery Hypothetical event. Company A discovered 1,000mmbl estimated recoverable crude reserves in an eastern offshore block. Production from this block will commence after five years of development from discovery. The discovery requires US$4,000mn capex to develop.

Assumptions • Ascribe average EV/bl of crude weighted US E&P firm – US$16/bl

• 20% discount to EV/bl owing to risks involved

• Discount rate – 12.5%

• Working interest of Company A – 25%


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Valuation We value the discovery at US$1,221mn for Company A (Table 2).

Table 2: Quick EV/reserves estimates for a discovery Comments Gross recoverable reserves (mmbl) 1,000 Risk (%) 20 Risk adjusted recoverable reserves (mmbl) 800 EV/bl valuation multiple of similar oil weighted US E&P firms (US$/bl) 16

EV of discovery post development (US$ mn) 12,800 EV/bl * (Risk adjusted recoverable reserves)

Less: Development capex (US$ mn) 4,000 EV of discovery pre development (US$ mn) 8,800 Time required to develop discovery (years) 5 Present value of discovery (US$ mn) 4,883 12.5% discount rate Discovery value to 25% Company A share (US$ mn) 1,221


Standardised measure of discounted cashflows

We are introducing one of the most stringent techniques of E&P firms’ proved reserves valuation called the standardised measure of discounted cashflow (SMODCF)-based DCF. SMODCF-based DCF uses audited SMODCF data available in a company’s annual filings. SMODCF data consists of cumulative future cashflow from year-end proved reserves. It is provided by US- & Europe-based E&P firms as per GAAP and the Society of Petroleum Engineers (SPE) respectively.

FY08-09 SMODCF data provided by ONGC (Chart 1) provides future – undiscounted & discounted (at 10%) – cumulative cash inflow/outflow from revenues, capex, operating expenses and taxes.


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Chart 1: ONGC SMODCF data from its FY09 annual report

Source: ONGC Annual Report

Methodology We have given a step-by-step approach to decode the SMODCF data into a DCF-based value of proved reserves.

Step 1: Replicate SMODCF data cashflow profiles. First, we create future undiscounted cashflow profiles from proved reserves, such that cumulative future cashflows match with SMODCF data (revenue profile, cost profile, tax profile and future capex). Various stages of creating cashflow profiles are:

• Create future production & revenue profiles through life of proved reserves, such that cumulative undiscounted & discounted (at 10%) future revenues match with those in SMODCF data, which assumes constant current year-end realised oil&gas prices, as per reporting guidelines. Incorporate company guidance and assumptions on annual production, assuming realistic natural decline rate and new production in any year owing to prior development capex.

• Create future cost profiles, assuming unit production costs and their annual cost escalation. Future cost profiles should be such that cumulative future undiscounted & discounted operating cash outflow matches with that of SMODCF data.

• Create required future capex profiles, such that cumulative undiscounted capex cash outflow matches with that of SMODCF data. Use company guidance (for next 2-3-year development capex) and then assume annual percentage decline in capex going forward.


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• Consider appropriate future cash tax rate, such that cumulative undiscounted & discounted future tax cash outflow matches with that of SMODCF data. Incorporate any tax benefits from available information.

• Prepare FCF (post capex) profiles, based on aforementioned future cashflow profiles of revenues, operating expenses, capex and taxes – FCF post capex stands for revenues less operating expenses, capex & cash taxes.

• Finally, calculate DCF value at 10% discount rate from FCF post capex profile, which should tally with that of SMODCF’s ‘net future earnings from proved reserves’.

Step 2: Exchange SMODCF data assumptions with your assumptions, as mentioned below:

• Exchange constant year-end oil & gas price assumptions with expected future oil & gas prices

• Incorporate delay in production, if any

• Incorporate risk to proved reserves recovery, if any, by reducing future production via appropriate discount

• Calculate SMODCF-based DCF value at our discount rate ascribed to the company instead of SMODCF’s 10% discount rate


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India E&P versus US peers – Not an apples-to-apples comparison There are differences in the underlying value of Indian private E&P and US E&P peers owing to policy differences for new discoveries under the New Exploration Licensing Policy (NELP) which are:

• Seven-year tax holiday on crude oil production and lower royalties benefits in initial years in India

• Minimal or nil government sharing till 100% cost recovery that increases in later years of production

The aforementioned factors would result in higher India E&P earnings in the initial years of production. On the other hand, in later years, India E&P earnings are lower than US peers’ on account of higher government sharing and royalties & tax payments, assuming similar crude prices, production profile, operating costs and capex.

Illustration We have attempted to illustrate impact of policies on value of Indian E&P companies versus US peers, with similar assumptions for both, except their respective policies. The illustration will clarify to the investor that pure comparison between Indian and US peers based on reserves can be misleading.

Table 3: Assumptions for Indian and US E&P firm Common assumptions for both US and Indian E&P firm Discovery size or recoverable reserves (mmbl) 98.6 Crude prices (US$/bl) 85 Development capex (US$ mn) 1,000 Yearly maintenance capex (US$ mn) 10 Operating costs (US$/bl) 15 Discount rate to value future cashflows (%) 10 Assumptions specific to US E&P firm Tax rate (%) 30 Royalties (%) 12.5 Assumptions specific to Indian E&P firm Tax rate (%) Nil for initial 7 years and then at 30% Royalties (%) 5% for initial 7 years and then at 10% IM for government sharing for Indian E&P (%) 0.0 0 0.5 0 1.0 20 1.5 40 2.0 60 2.5 80 3.0 and above 80

Source: I-Sec Research Table 4 shows the cashflow as well as earnings profiles of a US E&P firm from the aforementioned discovery.


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Table 4: Assumption – US E&P firm cashflow profile (US$ mn) Year 0 1 2 3 4 5 6 7 8 9 10Daily oil production (bpd) 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000Yearly oil production (mmbl) 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86Crude prices (US$/bl) 85 85 85 85 85 85 85 85 85 85 Revenue 838 838 838 838 838 838 838 838 838 838Less: Operating expenses 148 148 148 148 148 148 148 148 148 148DD&A 120 120 120 120 120 120 120 120 120 120Royalties 105 105 105 105 105 105 105 105 105 105Taxes 140 140 140 140 140 140 140 140 140 140 Net Income 326 326 326 326 326 326 326 326 326 326 Capex 1,000 10 10 10 10 10 10 10 10 10 10FCFF (1,000) 436 436 436 436 436 436 436 436 436 436EV 2,677


Table 5 shows the cashflow as well as earnings profiles of an India E&P firm from the aforementioned discovery.

Table 5: Example of Indian E&P firm cash-flow profile (US$ mn) Year 0 1 2 3 4 5 6 7 8 9 10Daily oil production (bpd) 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000 27,000Yearly oil production (mmbl) 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86 9.86Crude prices (US$/bl) 85 85 85 85 85 85 85 85 85 85 Revenue 838 838 838 838 838 838 838 838 838 838Less: Operating expenses 148 148 148 148 148 148 148 148 148 148DD&A 120 120 120 120 120 120 120 120 120 120Government share - - - 91 181 181 272 255 255 339Royalties 42 42 42 42 42 42 42 84 84 84Taxes - - - - - - - 69 69 44 Net Income 528 528 528 437 347 347 256 162 162 103 Capex 1,000 10 10 10 10 10 10 10 10 10 10Cost recovery multiple 0.4 0.9 1.3 1.7 1.9 2.1 2.3 2.4 2.6 2.6Govt share (%) 0 0 0 20 40 40 60 60 60 80Govt share - - - 91 181 181 272 255 255 339 FCFF (1,000) 638 638 638 547 457 457 366 272 272 213EV 3,014


India E&P earnings in initial years of production varies significantly from later years, which entail higher royalties, taxes and government sharing (Chart 2). As P/E-based India E&P valuations give ambiguous results owing to volatility in earnings, this methodology fails in the India E&P context.


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Chart 2: Earnings trend of India and US E&P

0

100

200

300

400

500

600

1 2 3 4 5 6 7 8 9 10Years

(US$

mn)

US E&P India E&P



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E&P investor guide – Key parameters to track

Reserve Replacement Ratio (RRR)

RRR = {(Reserve additions) + (Improved recovery) + (Revisions)}/ (Production)

The RRR measures the amount of proved reserves additions by the company during the year relative to the amount of oil & gas produced during the year. RRR around 1 signifies that the company is able to maintain its reserve base despite its current production, and implies that company would be able to maintain its current production level. RRR, in conjunction with Finding & Development (F&D) costs captures the operating performance of the company.

ONGC’s RRR calculations on 3P instead of 1P reserves lead to inflated RRR ONGC calculates RRR using 3P reserves (Proved + Probable + Possible) which is not a good indicator of reserve replacement ability because 3P reserves include less certain probable & possible reserves, while reserves reduced through production were highly certain proved reserves, resulting in inflated RRR value.

Finding & Development (F&D) cost

F&D costs = {Exploration cost + Development cost + Unproved asset purchase costs}/{Reserve additions through discoveries, revisions and improved recovery}

F&D costs indicate the costs incurred by a firm to find, and then develop the reserves for production. F&D costs are capitalised by the firm and flow through income statement as DD&A expense.

Production and Lifting costs

One should keep track of the production and lifting costs for a firm, which signify the cost of production from a developed field. These costs along with F&D costs would constitute all the operating cost for the field.

Exploration, Development plans

Exploratory drilling could result in major upgrades to a company’s reserve or may result in significant write-offs for the company. Hence, a closer look must be kept at the firm’s exploration plans to keep track of its long-term potential.

Once proven, development of the fields would result in them coming onto production and hence additional cash flows for the company. Closer scrutiny of development plans provides better visibility on future cashflows for the company.


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Key parameters impacting E&P valuation

Oil & gas pricing

Oil & gas prices are factors that affect E&P firms’ profitability the most. However, in the Indian context, since gas prices are regulated, global fluctuations in gas prices do not impact Indian firms’ profitability.

Taxes & royalties

Indian government levies cess and royalty on crude oil and natural gas production on all domestic fields. Royalty varies on crude oil or natural gas production as well as offshore and onshore production. Moreover, Indian government provides lower royalty rates in the first seven years of production from any field. Cess is uniform across the years. Moreover, the government also provides 7-year tax holiday on oil production from NELP blocks.

Profit sharing

Indian government has mandated profit sharing on all the NELP blocks and the effective sharing depends on the IM for the particular field. The IM in any year is the ratio of cumulative net cash income of the oil company to cumulative investments by the oil company. With changes in IM, effective profit sharing with the government also keeps on changing, leading to significant volatility in the firm’s earnings. Profit sharing ratio as well as the movement of IM has to be closely tracked in order to forecast company earnings.

Reserves mix

Due to market pricing for crude and regulated pricing for gas as well as differences in taxation for Oil & Gas, oil reserves are far more valuable vis-à-vis gas reserves. Moreover, similar reserves on land would command some premium to reserves offshore due to lower cost of extraction for onshore reserves.

Quality of reserves

Quality of oil/gas reserves is also very important and could potentially impact valuations. Calorific content of gas, C2-C3 concentration could impact valuations for the gas reserves, while API content, sulphur content & viscosity of oil could impact valuations for oil reserves.

Location of reserves

Location of the reserves and the nearest connectivity to the existing transportation network could impact development cost for the new discovery and could materially impact valuations of the field. Also, offshore discoveries take longer to develop implying lower valuations vis-à-vis onshore discoveries.


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India Upstream India’s sedimentary basins are spread across 3.14mnkm2, consisting of 1.79mnkm2 of onshore & shallow-water regions and 1.35mn mnkm2 of deep-water area. So far, 26 sedimentary basins are recognised by the Directorate General of Hydrocarbons-DGH (Chart 3).

Chart 3: India sedimentary basins

Source: DGH India’s upstream future prospects would be more gas-weighted instead of crude oil-weighted on the back of significant discoveries during this decade in the eastern offshore region. Accordingly, the Indian gas market is set to see 3x increase in domestic gas supplies from KG-D6 and NEC-25 blocks as well as GSPC and ONGC offshore blocks. Numerous domestic offshore blocks in KG Basin (D3, D4 & D9) and Mahanadi Basin (D4) would offer further upside to domestic gas production going forward. We estimate domestic gas supplies to see 11.8% CAGR through FY10-14E to 224mmscmd from 144mmscmd.

In contrast to natural gas, except Cairn’s Rajasthan discovery, India has not witnessed many crude oil discoveries of recent. Hence, we expect India to continue its dependence on crude import (~two-third of demand).


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Policies India’s upstream activities were highly regulated in the past and primarily dependant on two national oil companies (NOCs) – Oil India (OIL) and ONGC. Accordingly, the domestic upstream sector witnessed low level of investment as upstream exploration activities are very risky & capital intensive in nature; also, only two NOCs’ investment was not sufficient for India’s vast exploration acreage. Given the increased dependence on imported crude oil, the Government of India (GoI) has initiated reforms on the domestic E&P front, to reduce crude import dependence via deregulations and encouraging private/foreign participation and subsequently offered many small/medium-size fields to private players during the pre-NELP rounds.

To accelerate domestic E&P activities, GoI initiated NELP in 1997, which entails more incentives to attract private/foreign participation in domestic E&P.

Pre NELP To attract private/foreign investments in domestic E&P business, especially exploratory acreage/marginal fields, GoI has initiated many steps since 1993. Oil & gas blocks awarded since 1993, but before introduction of clearly-defined NELP (during 1997-98), come under the purview of pre NELP.

As per the DGH, GoI has signed production sharing contracts (PSCs) for 28 exploration blocks during the pre-NELP rounds; of these, 16 are already operational.

Salient features • Tax incentives on revenue from commercial discovery on exploratory acreage

• NOCs’ option to take participation interest (PI) on the block, which varies within the 0-40% range (depending on the block’s terms & conditions). Various marginal fields were developed accordingly – e.g., ONGC has 40% PI in joint ventures (JVs) with Panna-Mukta-Tapti and Ravva.

• NOCs’ carried-out interest. An NOC has 30% working interest since signing of a contract subsequent to exploration activities, post which, it has option to take this 30% interest in the project in case of commercial discovery and, accordingly, divide the capex and returns (except additional royalty burden of private-partner share) on its respective interest – For example, ONGC has exercised this option on Cairn’s Rajasthan discovery.

• Royalty benefits. Companies were exempted from royalty payments to GoI, with their respective royalties to be borne by NOCs (ONGC/OIL).

However, there were many a lacunae on various fronts in the pre-NELP rounds that were ironed-out in later NELP policies. Some missing incentives during pre-NELP rounds were:

• No particular enticement for the high-risk, deep-water exploration

• Non-level playing field for NOCs as they bear the private partner’s share of royalty payments


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NELP In 1997-98, the government formulated NELP for attracting foreign/private capital to expedite domestic exploration activities, especially in deep-water/ultra deep-water areas. NELP not only provides a level-playing field for awarding exploration acreage, but also offers competitive contract & fiscal terms.

So far, there have been seven rounds of bidding with 210 blocks awarded under NELP I-VII rounds, and another 36 blocks were bid by various operators under the recently concluded NELP VIII round (Table 6).

Table 6: NELP awards – An overview

Total (nos) Onshore Shallow

waterDeep water

Proposed capex

(US$ mn)*

Incurredcapex

(US$ mn)^

Acreage (’000km2)

NELP I 24 1 16 7 1,151 5,610 194.7NELP II 23 7 8 8 776 442 263.1NELP III 23 8 6 9 1,039 768 204.6NELP IV 20 10 10 1,135 684 192.8NELP V 20 12 2 6 917 398 115.2NELP VI 55 25 6 24 3,317 87 306.2NELP VII 45 26 7 12 NA NA NANELP VIII # 36 15 13 8 NA NA NATotal 246 104 58 84

* Exploration capex; ^ Exploration and development capex; # Provisional results for NELP-VIII Round based on data provided by bidders Source: Infraline, I-Sec Research NELP has been instrumental in promoting E&P activities in India over the past few years. It has undergone seven rounds of bidding, including the recently concluded NELP VIII (final awards for which are still pending). The overall awarded area for NELP IV & V was substantial at 353,500km2 spread over 40 blocks; NELP VI with 352,200km2 was spread over 55 blocks and NELP VII had 57 blocks. The aggressive programme has attracted the attention of global majors and is of strategic significance to India’s oil security as imports form 70% of the domestic demand at present. India, currently, has 5.7bnboe oil and 37.9tcf gas reserves, but this is based on just 20% exploration of the country’s overall potential of sedimentary basins, which is pegged at 3.14mnkm2. Also, the gas discovery (P1 reserves of 5tcf recently upgraded to 11tcf) made by RIL in its KG D-6 block (awarded in NELP I) is one of the largest, world-class gas reserve finds, while discoveries by ONGC and GSPC in the east coast are also expected to be of large size – this has enhanced domestic and global interests in NELP.

Salient features • Income tax breaks for seven years for crude oil production

• Foreign participation allowed up to 100%

• Cost recovery for up to 100%

• No customs duty on imports for equipment used in E&P

• Maximum exploration period of seven years (eight for deepwater) to be completed in three phases. Each phase comprises three years at the most (four years for phase I in case of deepwater)


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• Maximum development and production period of 20 years for oil and 30 for gas, which can be extended by another five years after mutual agreement between the Government and the company

• Work commitment. The E&P firm has to provide a minimum exploration work obligation for each phase while bidding. It may commit to just seismic operations in the first phase. Any work in excess of the minimum commitment in any phase may be carried forward to the subsequent phase and be offset against the minimum work committed for such a phase.

• Royalty for onshore is 12.5% for oil & 10% for gas, while 10% for both oil & gas in shallow offshore (less than 400isobath). For deepwater assets, it stands at 5% for both oil and gas for the first seven years, and at 10% thereafter.

• Relinquishment. The E&P company has to relinquish 25% of the exploratory acreage if it graduates to the second phase of exploration. The relinquishment is a further 25% if it proceeds to the third phase. In the production phase, the company has to relinquish all properties, which do not contain hydrocarbons.

• Production sharing. The percentage of annual production of petroleum expected to be allocated for recovery of costs should be indicated by the company in the bid. The sharing of profit petroleum shall be bid upon based on a sliding scale tied to pre-tax multiples of investment recovered and shall be specified in the contract.


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Valuation of some of India’s key upstream blocks Table 7: Common assumptions for key offshore blocks’ valuations

Gas price realisation (US$/mmbtu) 4.2 Marketing margins (US$/mmbtu) 0.15 Unit operating costs (US$/mmbtu) 1.0 Exchange rate (Rs/US$) 45 Cost of equity (%) 12.5


Table 8: India’s key promising gas offshore blocks – A comparison KG-D6 KG-D3 MN-D4 KG-D9 NEC-25 GSPC DD* Total development capex (US$ mn) 12,021 8,195 12,750 9,360 7,526 8,580 Total exploration capex (US$ mn) 671 643 725 662 360 360 Total recoverable reserves (tcf) 13.8 9.5 15.0 10.8 8.5 10.0 Development capex/recoverable reserves (US$/mcf) 0.87 0.86 0.85 0.87 0.89 0.86 Exploratory capex/recoverable reserves (US$/mcf) 0.05 0.07 0.05 0.06 0.04 0.04 Total capex/recoverable reserves (US$/mcf) 0.92 0.93 0.90 0.93 0.93 0.89 Commencement of production FY10 FY16 FY16 FY16 FY13 FY13 Peak production (mmscmd) 120 79 125 90 71 84 NAV at FY10 end (US$ mn) 12,290 674 1,568 1,095 2,557 2,723 NAV/recoverable reserves at FY10 end (US$/mcf) 0.89 0.07 0.10 0.10 0.30 0.27 NAV at production start (US$ mn) 11,107 8,034 13,152 9,687 7,463 8,253 NAV/recoverable reserves at production start (US$/mcf) 0.81 0.85 0.88 0.90 0.88 0.83

* Deen Dayal block Source: I-Sec Research

Table 9: Key offshore blocks’ revenue-share terms with GoI, as per IM Investment multiple (IM) KG-D6 KG-D3 MN-D4 KG-D9 NEC-25 GSPC DD 0 10 16 10 10 10 20 1.0 10 16 10 10 10 20 1.5 16 16 10 10 10 25 2.0 22 28 19 16 16 30 2.5 28 40 70 25 25 30 3.0 70 76 76 34 34 35 3.5 70 76 85 85 85 40 4.0 and above 70 85 85 85 85 40 % of revenue used to recover costs 90 90 80 90 90 100


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KG-D6

Valuation As per our estimates, NAV of KG-D6 block gas reserves stands at Rs553bn (US$12.3bn), assuming that gross recoverable gas reserves from the block are 13.8tcf with commencement of production FY10 onward.

Background The offshore KG-D6 block, known for the largest domestic gas find, is spread across 7,645km2 lying approximately 20km offshore of the east coast of India. RIL is the operator and has 90% working interest, with Niko Resources having the remaining interest in the block. Production from the block’s MA oil discovery commenced in September ’08, and from Dhirubhai 1 & 3 gas discoveries in April ’09. Phase I field development plan includes drilling and completion of 17 wells, construction of an offshore platform and onshore gas plant facilities.

As per Niko, a development plan has been submitted for nine additional natural gas discoveries, which are adjacent to the existing Dhirubhai 1 & 3 gas fields. It is proposed that these satellite discoveries be tied to Dhirubhai 1 & 3 facilities. Capex requirements and commercial production commencement time will be finalised after approval of the development plan.

Table 10: KG D6 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Production (mmscmd) 45 75 105 120 120 120 120 120 90 80 50 25 15 Sales 97 158 226 234 234 234 234 234 166 144 76 34 20 Less: Royalty 5 8 11 11 11 11 11 23 16 14 7 3 2 Production costs 25 39 55 62 62 62 62 62 47 42 26 13 8 Government share 1 2 3 9 22 24 25 40 28 23 11 4 2 Depletion 16 27 38 44 44 44 44 44 33 29 18 9 5 Interest paid/(earned) 9 16 14 10 5 (2) (8) (13) (17) (21) (24) (25) (27)Tax 1 2 3 3 3 3 3 27 21 19 13 10 10 PAT 39 64 103 95 87 91 97 52 40 37 25 20 20 Capex profile Exploratory 6 6 6 0 0 0 0 0 0 0 0 0 0 Development 79 47 48 46 3 4 0 0 0 0 0 0 0 During production 2 2 2 2 2 2 2 2 2 2 2 2 2 Capex during the year 87 56 56 47 5 5 3 3 3 3 3 3 3 FCFF (22) 52 100 102 131 122 124 64 43 36 16 5 2 NAV 553 521 533 480 392 299 194 140 102 69 56 52 53


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KG-D3

Valuation We estimate end-FY10 NAV of KG-D3 block gas reserves at Rs30bn (US$674mn), assuming gross recoverable gas reserves from the block at 9.5tcf, with commencement of production from FY16E.

Background The D3 block is spread across 3,288km2 with 400-2,100-metre water depth and is located ~45km off the East coast. RIL has 90% stake in the block, with the remaining stake held by Hardy Oil. There have been two successful gas discoveries in the block. RIL conducted a 3-D survey in H1CY09 and plans to drill one exploration well in H2CY09 and two in CY10.

Table 11: KG D3 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Production (mmscmd) 0.0 0.0 0.0 0.0 0.0 0.0 25.4 50.8 63.5 79.4 79.4 79.4 79.4 79.4 79.4 55.6 33.3 16.7 8.3 4.2 2.1 1.0 Sales 0 0 0 0 0 0 65 131 163 204 204 204 204 204 204 143 86 43 21 11 5 3 Less: Royalty 0 0 0 0 0 0 3 7 8 10 10 10 10 20 20 14 9 4 2 1 1 0 Production costs 0 0 0 0 0 0 15 30 38 47 47 47 47 47 47 33 20 10 5 2 1 1 Government share 0 0 0 0 0 0 1 2 3 3 11 23 23 22 38 26 16 11 5 2 1 0 Depletion 0 0 0 0 0 0 15 30 37 46 46 46 46 46 46 32 19 10 5 2 1 1 Interest cost 0 0 0 0 0 0 25 36 41 39 28 15 4 0 0 0 0 0 0 0 0 0 Tax 0 0 0 0 0 0 1 5 6 10 10 11 12 23 18 13 8 3 1 1 1 0 PAT 0 0 0 0 0 0 5 22 31 49 51 52 61 45 35 24 15 5 3 2 1 1 Capex profile Exploratory 4 4 4 4 4 4 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Development 0 0 0 55 92 92 55 55 18 0 0 0 0 0 0 0 0 0 0 0 0 0 During production 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Yearly capex 4 4 4 59 96 96 61 57 20 1 1 1 1 1 1 1 1 1 1 1 1 1 FCFF (4) (4) (4) (62) (104) (112) (41) (5) 48 94 96 97 106 90 80 55 33 14 6 3 1 (0) NAV 30 39 48 118 234 362 438 483 477 426 373 316 242 170 102 52 22 9 3 1 (0) 0


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MN-D4

Valuation We estimate end-FY10 NAV of MN-D4 block gas reserves at Rs71bn (US$1,568mn), assuming gross recoverable gas reserves of 15tcf from the block, with commencement of production from FY16E.

Background Deep-water MN-D4 block, spread across 17,050km2, is located in the Mahanadi Basin. RIL is the operator of the block (85% interest) with Niko Resources having 15% interest. As per Niko, it expects exploration potential in MN-D4 to exceed the potential of the D6 block, which is understood to contain ~25tcf recoverable gas. The company plans to drill three wells in the block starting FY10.

Table 12: MN D4 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Production (mmscmd) 0 0 0 0 0 0 40 80 100 125 125 125 125 125 125 88 53 26 13 7 3 2 Sales 0 0 0 0 0 0 103 206 258 322 322 322 322 322 322 226 135 68 34 17 8 4 Royalty 0 0 0 0 0 0 5 10 13 16 16 16 16 32 32 23 14 7 3 2 1 0 Production costs 0 0 0 0 0 0 24 47 59 74 74 74 74 74 74 52 31 16 8 4 2 1 Government share 0 0 0 0 0 0 2 4 5 6 6 20 23 21 41 28 62 30 14 6 2 1 Depletion 0 0 0 0 0 0 23 45 57 71 71 71 71 71 71 49 30 15 7 4 2 1 Interest cost 0 0 0 0 0 0 40 55 64 60 44 23 7 0 0 0 0 0 0 0 0 0 Tax 0 0 0 0 0 0 2 7 10 16 19 20 22 42 36 25 (0) 0 0 0 0 0 PAT 0 0 0 0 0 0 8 36 50 79 92 98 109 82 69 48 (1) 0 1 1 1 1 Capex profile Exploratory 5 5 5 5 5 5 5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Development 0 0 0 86 143 143 86 86 29 0 0 0 0 0 0 0 0 0 0 0 0 0 During production 0 0 0 0 0 0 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Yearly capex 5 5 5 91 148 148 93 88 31 2 2 2 2 2 2 2 2 2 2 2 2 2 FCFF (5) (5) (5) (94) (160) (172) (62) (7) 76 147 160 166 178 150 138 96 27 13 6 2 1 (0) NAV 71 85 100 210 391 592 712 785 779 701 612 509 380 258 136 45 20 8 3 0 (0) 0


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KG-D9

Valuation We estimate end-FY10 NAV of KG-D9 block gas reserves at Rs49bn (US$1,095mn), assuming gross recoverable gas reserves of 10.8tcf from the block, with commencement of production from FY16E.

Background RIL is the operator of the block (with 90% interest), which is spread over 11,605km2 in the Bay of Bengal with water depth in the 2,300-3,100-metre range. One exploratory well was drilled in CY09 that was dry. Three more exploration wells are planned to be drilled by end-CY10.

Table 13: KG D9 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Production (mmscmd) 0 0 0 0 0 0 29 58 72 90 90 90 90 90 90 63 38 19 9 5 2 1 Sales 0 0 0 0 0 0 74 149 186 232 232 232 232 232 232 163 98 49 24 12 6 3 Less: Royalty 0 0 0 0 0 0 4 7 9 12 12 12 12 23 23 16 10 5 2 1 1 0 Production costs 0 0 0 0 0 0 17 34 43 53 53 53 53 53 53 37 22 11 6 3 1 1 Government share 0 0 0 0 0 0 1 1 2 2 8 17 17 15 25 17 16 8 4 2 1 0 Depletion 0 0 0 0 0 0 17 34 42 52 52 52 52 52 52 37 22 11 6 3 1 1 Interest cost 0 0 0 0 0 0 29 41 47 44 33 17 5 0 0 0 0 0 0 0 0 0 Tax 0 0 0 0 0 0 1 5 7 12 13 14 16 30 27 19 9 5 2 1 1 0 PAT 0 0 0 0 0 0 6 26 36 57 62 67 77 58 52 36 18 9 5 2 1 1 Capex profile Exploratory 4 4 4 4 4 4 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Development 0 0 0 63 105 105 63 63 21 0 0 0 0 0 0 0 0 0 0 0 0 0 During production 0 0 0 0 0 0 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Yearly capex 4 4 4 67 110 110 69 65 23 2 2 2 2 2 2 2 2 2 2 2 2 2 FCFF (4) (4) (4) (70) (119) (127) (46) (5) 55 107 113 118 128 109 103 71 39 19 9 4 1 (0)NAV 49 60 73 154 288 436 526 580 576 521 462 392 302 218 129 65 30 13 5 1 (0) 0 Source: I-Sec Research

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NEC-25

Valuation We estimate end-FY10 NAV of NEC-25 block gas reserves at Rs115bn (US$2,557mn) assuming gross recoverable gas reserves of 8.5tcf from the block with commencement of production from FY13E.

Background Shallow water NEC-25 block is located in the Mahanadi Basin in East India. RIL is the operator of the block (90% interest) with Niko Resources having 10% interest. According to Gaffney, Cline & Associates, the project comprises six gas discoveries in the block in the Orissa coast, which has in-place gas reserves of more than 8.3tcf. Recently, as per media, RIL received the Petroleum Ministry's approval to develop NEC-25 at US$2bn. Eight significant gas discoveries have been made in the block and the approval will cover the development of six; twelve development wells would be drilled in the six discoveries. The RIL-Niko consortium plans to drill 15 more exploration wells.

Table 14: NEC 25 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Production (mmscmd) 0 0 0 23 45 57 71 71 71 71 71 71 50 30 15 7 4 2 1 Sales 0 0 0 58 117 146 183 183 183 183 183 183 128 77 38 19 10 5 2 Less: Royalty 0 0 0 3 6 7 9 9 9 9 18 18 13 8 4 2 1 0 0 Production costs 0 0 0 13 27 34 42 42 42 42 42 42 29 18 9 4 2 1 1 Government share 0 0 0 1 1 1 2 6 13 21 19 27 19 14 7 3 1 1 0 Depletion 0 0 0 14 28 35 44 44 44 44 44 44 31 18 9 5 2 1 1 Interest cost 0 0 0 23 33 38 36 26 14 4 0 0 0 0 0 0 0 0 0 Tax 0 0 0 1 4 5 9 9 10 11 20 18 12 6 3 2 1 1 0 PAT 0 0 0 3 18 26 42 46 51 52 39 34 24 13 6 3 2 1 1 Capex profile Exploratory 2 2 1 1 Development 51 85 85 51 51 17 During production 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Capex during the year 53 87 86 53 52 18 1 1 1 1 1 1 1 1 1 1 1 1 1 FCFF (55) (94) (100) (35) (5) 43 84 89 93 95 82 77 53 30 14 7 3 1 (0) NAV 115 221 336 404 446 443 398 350 293 228 164 98 50 23 10 4 1 (0) 0


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GSPC’s Deen-Dayal block

Valuation We estimate end-FY10 NAV of Deen-Dayal (DD) block gas reserves at Rs123bn (US$2,723mn), assuming gross recoverable gas reserves of 10tcf from the block, with commencement of production from FY13E.

Background Deen Dayal, a shallow water eastern offshore block, was awarded to the GSPC-led consortium during NELP-III round, wherein GSPC holds 80% stake. In the past, GSPC reported a major discovery of 20tcf in the DD block, which was later reduced by the DGH to 3.6tcf. India’s upstream regulator, DGH, has approved the commerciality of four discoveries in the block. These discoveries are expected to begin production by ’12 and would supply 8-10mmscmd gas initially. Other than commercially approved four discoveries in the block, GSPC has also discovered gas in three exploratory wells and discovered oil in one prospect.

The DD block is divided into three parts – DD West, DD East and DD North. The field development plan of the western part of the block includes development of 15 wells.

Table 15: GSPC’s Deen Dayal – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Production (mmscmd) 0 0 0 27 53 67 84 84 84 84 84 84 59 35 18 9 4 2 1 Sales 0 0 0 69 138 172 215 215 215 215 215 215 150 90 45 23 11 6 3 Less: 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Royalty 0 0 0 3 7 9 11 11 11 11 21 21 15 9 5 2 1 1 0 Production costs 0 0 0 16 32 40 49 49 49 49 49 49 35 21 10 5 3 1 1 Government share 0 0 0 0 0 0 0 29 31 38 36 43 30 18 9 4 2 1 0 Depletion 0 0 0 16 32 40 50 50 50 50 50 50 35 21 10 5 3 1 1 Interest cost 0 0 0 27 37 43 41 30 16 4 0 0 0 0 0 0 0 0 0 Tax 0 0 0 1 5 7 11 8 10 11 20 18 12 7 4 2 1 1 0 PAT 0 0 0 6 25 34 54 38 49 52 39 34 24 14 7 4 2 1 1 Capex profile Exploratory 2 2 1 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Development 58 97 97 58 58 19 0 0 0 0 0 0 0 0 0 0 0 0 0 During production 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Yearly capex 60 99 98 60 59 21 1 1 1 1 1 1 1 1 1 1 1 1 1 FCFF (62) (107) (114) (38) (3) 53 102 87 97 100 87 82 57 34 16 8 3 1 (0)NAV 123 241 371 445 488 476 415 372 314 246 179 108 57 26 11 4 1 (0) 0


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Cairn’s Rajasthan block (RJ-ON-90/1)

Valuation We estimate end-FY10 NAV of Cairn’s Rajasthan block crude reserves at Rs624bn (US$13,889mn), assuming gross recoverable crude reserves of ~1,100mmbl and 185,000bpd peak production from the block, with production already having commenced in Q2FY10.

Background Cairn India, with 70% interest, is the operator of this pre-NELP block and ONGC holds the remaining 30% interest. Cairn struck one of the largest domestic oil discoveries in recent times in Rajasthan in this block, where key fields are Mangala, Aishwariya, Saraswati & Raageshwari. Gross 2P reserves from the block are 1,079mmboe. Production commenced in Q2FY10, with peak expected production of 185,000bpd from mid ’11.

Table 16: Cairn’s RJ-ON-90/1 – Valuations (Rs bn) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Gross Production ('000bpd) 35 131 183 185 185 185 185 182 179 171 154 131 114 101 89 79 72 67 Net Cairn's Production ('000bpd) 24 91 128 130 130 130 129 128 125 119 107 91 80 71 62 55 51 47 Rajasthan P&L (net to Cairn) Sales 539 2,043 3,066 3,108 3,109 3,109 3,099 3,060 3,001 2,862 2,575 2,189 1,905 1,694 1,487 1,328 1,213 1,124 Less: Cess 24 92 131 133 133 133 133 131 128 123 110 94 82 73 64 57 52 48 Production and SG&A costs 88 246 335 339 348 378 448 506 532 531 488 415 363 328 288 259 239 225 Government share 0 0 0 0 473 467 451 649 834 786 879 747 649 575 504 450 409 378 DD&A 47 182 261 264 264 265 264 260 255 244 219 186 162 144 127 113 103 96 Interest cost 48 12 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Add: other income 28 20 36 48 55 71 82 95 109 125 156 171 185 198 209 218 227 234 Less: taxes 61 259 402 409 329 327 318 271 229 219 173 153 139 129 119 111 106 102 PAT 300 1,272 1,973 2,010 1,617 1,611 1,568 1,338 1,131 1,084 862 765 694 644 594 556 530 510 Capex profile (net to Cairn) Development capex 523 517 459 249 249 187 156 124 86 62 62 31 31 31 31 31 30 30 Pipeline capex 186 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Yearly capex 709 517 459 249 249 187 156 124 86 62 62 31 31 31 31 31 30 30 FCFF (460) 1,172 1,891 2,016 1,662 1,628 1,645 1,015 873 864 677 564 516 452 393 346 312 287 NAV 8,557 8,480 7,700 6,693 5,908 5,054 4,071 3,589 3,186 2,739 2,421 2,174 1,943 1,745 1,581 1,442 1,319 1,204


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Annexure 1: Oil and Gas E&P basics

Answers to elementary questions

Exploration & production (E&P) or the ‘upstream oil’ sector is a business where oil & gas companies are involved in finding oil and gas reserves (through acquiring land leases, surveying, prospects identification and drilling), verifying commerciality and finally setting-up necessary infrastructure to begin oil & gas production.

We have introduced the preliminary description of some elementary queries about the E&P business, for basic knowledge of the sector.

How oil & gas deposits are formed Oil and gas are formed from the decayed remains of plants and animals (organic) that lived millions years ago and accumulated under sedimentary rocks. With application of heat and pressure, this decayed matter was converted into oil and gas. As soon as a plant or animal dies, bacteria attack its remains. If oxygen is plentiful, as in soil, bacteria will consume all the organic matter. But in very fine-grained muds deposited on the sea floor, oxygen is limited and much of the organic matter escapes destruction. As these muds are buried by successive layers of sediment, rising heat ‘cooks’ the organic matter, throwing off water, carbon dioxide and hydrocarbons.

Chart 4: Petroleum and natural gas formation

Source: EIA Usually, oil & gas deposits are found in pools, where water is at the bottom and the oil and gas layers lie at the top.


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Chart 5: Oil, gas and water deposits in a reservoir

Source: OSRADP Four essential conditions for oil & gas deposits Oil and gas are found in sedimentary rocks that cover ~75% of the earth’s surface. Limestone, dolomite, sandstone, shale and siltstone are sedimentary rock surfaces where petroleum geologists search for oil and gas. It is within these layered sedimentary rocks where geologists look for combination of four essential conditions that need to be met for oil & gas possibility: i) source rock ii) migration iii) reservoir rock iv) trap.

Chart 6: Oil formation mechanism

Source: NOAA


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Source rock Petroleum source rocks are usually thick, black sea shale, where decayed organic matter was converted into petroleum millions of year ago. The source rocks are characterised by low porosity and low permeability. For crude oil generation from organic matter, temperatures and pressure must be just perfect. Temperature should be between 49ºC and 177ºC, and depths of deposits between 5,000ft and 21,000ft. A higher temperature range of the source rock results in formation of natural gas.

Migration Movement of oil & gas deposits from source rock into reservoir rock is called primary migration. Sometimes, reservoirs are filled of oil & gas that has migrated just a small distance from nearby source rocks (shale). But, huge oil & gas pools are also found hundreds of miles away from the original source rocks.

Reservoir rocks Reservoir rocks are hosts for hydrocarbons. In contrast to the source rocks, reservoir rocks have good porosity and permeability. Reservoir rocks are deposited in high-energy conditions such as waves and currents, which take away mud particles and most of the organic matter, resulting in open pores. Therefore, reservoir-quality rocks – sandstone and limestone – initially include very little organic matter. It is the migrated oil and gas that has deposited in these reservoirs.

Trap Crude oil and natural gas, once formed in the source rock, constantly look for lower pressures, leading to their upward movement through natural conduits in the earth’s layers. If no blockade intercedes, these hydrocarbons will finally leak out of the earth’s surface. However, migrating oil and gas often hits a sealing layer of rock which cannot allow passing. These seals are sedimentary rocks with very small permeability that do not allow oil and gas to migrate any farther upward. The entrapment of oil & gas due to these seals is called the ‘trap’. Folded or faulted rock layers can form structural traps, which are usually anticlines, domes or horst blocks. Stratigraphic traps form due to changes within the rock layers, as porous rocks such as reefs or river-channel sandstones are surrounded by nonporous rock. Combination traps, with both structural and stratigraphic elements, are also possible. In a trap, oil, gas & water are separated according to densities – gas rising to the top, oil in the middle and water at the bottom. Shale and thick salt layers offer excellent trap.


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E&P business – Various stages

Exploration stage Exploratory acreage purchase and signing of PSCs The exploration process starts with purchasing/acquiring rights as a lease to explore the region for oil and gas. Some of the key terms of the lease which are agreed upon with the government are:

• Minimum work programme (drilling commitments) for exploratory phases. Minimum work programme (MWP) includes capex, drilling of exploratory wells and minimum seismic surveys targeted for each phase of exploration – e.g., phase I may require 13 line km of 2D surveys & 500km2 of 3D surveys; and phase II of exploration may require 600km2 of 3D survey and drilling of three exploratory wells.

• Duration of exploration decides time-period deadline of various exploration phases, so that required MWP commitments are carried within that time-period. If the contractor (E&P company) misses these deadlines without a valid (agreed upon) contract, then penalty would be imposed in monetary terms or through additional MWP requirements.

• Criteria to declare oil & gas find as discovery involves positive results from running the required agreed-upon tests to declare results of exploratory well as discovery or not.

• Signing of production sharing contract. A production sharing contract (PSC) is signed with the government and includes agreed-upon fiscal terms such as royalty & cess payment rates and tax incentives for production from future discovery. PSCs also decide rules of revenue sharing with the government and oil company. Some indicative features of a typical PSC are:

- Recovery of costs – All payments made to the government, except income tax, are recoverable from oil & gas sales revenue. The recoverable costs include production costs, exploration costs and development costs. Unrecovered portion of these costs would be carried forward and recovered in subsequent years, while the recovered portion of these costs in any year is called cost petroleum.

(Note: Investment multiple – The profit petroleum in any year is computed as follows – oil & gas revenue less cost petroleum in any year. This profit petroleum is shared between the government and oil company on the basis of IM levels. The IM in any year is the ratio of cumulative net cash income of the oil company to cumulative investments by itself, where cumulative net cash investment includes exploratory expenses, development expenditure, operating cash expenses and statutory taxes/levies.)

Exploration & seismic studies and identification of prospects After signing of a PSC, the oil company begins the exploration process by various geophysical surveys such as gravity and magnetic surveys, seismic studies (2D, 3D) and electromagnetic surveys. From combining various surveys data, geologists attempt identifying the requirements for commercial quantities of oil & gas


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accumulation beneath the earth’s surface. These surveys help identify the four essential conditions for presence of hydrocarbons – source rock, migration, reservoir rock and trap.

Then, on the basis seismic surveys results, geophysicists identify the most promising exploratory well-drilling locations called ‘prospects’.

Drilling of exploratory wells Though interpretation of seismic studies can indicate chances of presence of hydrocarbons beneath the earth’s surface, it is not a guarantee about presence of hydrocarbons. It is the drilling of a well that finally clarifies if hydrocarbons are actually present.

For oil companies, whether a prospect merits drilling is a detailed evaluation exercise of reward and risk. Companies put in a significant amount of effort for evaluating presence of potential reserves volumes, hydrocarbons type etc. Risks such as technical, political and estimated dry well costs are also taken into account. Usually, oil companies maintain inventory of prospects ranked as per possible reserves upside versus risks involved and plan their drilling programme accordingly. But many times, oil companies drill a prospect independent of their risks owing to MWP drilling requirements within the stipulated duration to retain the lease.

Among the various identified prospects, a region where no hydrocarbons were discovered earlier is considered the most risky prospect and a well drilled in that area is called ‘wildcat well’. Since drilling a deepwater well may cost US$30-100mn, and accordingly, sometimes minimum 100mmbl of oil discovery required to justify significant drilling & development expenditures are involved. Therefore, a deepwater ‘wildcat well’ is one of the most risky prospects and oil companies reduce this risk by partnering (farm out) the prospect with other firms.

Oil companies are involved in exploratory drilling of less risky targets such as areas nearby some producing fields and undeveloped discoveries. This is so as such firms already have better subsurface knowledge of these areas, and can easily develop small discoveries without incurring significant capex due to sharing of nearby production facilities.


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Chart 7: Oil & gas exploration drilling

Source: Geology.com

Results of exploratory drilling – Discovery well or dry well An exploratory well that reveals presence of a hydrocarbon-bearing reservoir is called discovery well; the exploratory well is called a dry well if required quantities of hydrocarbons are not present.

Appraisal A discovery from a single well itself would not justify the development economics, and additional positive results from nearby appraisal wells drilling are required to asses the extent and properties of discovered field.

After appraisal of the discovery, if a field contains sufficient quantities of recoverable oil & gas reserves, then extensive development of the discovered field is initiated; otherwise, the field is left unexplored as future prospect (e.g., higher oil prices or better cost technology) would justify the field economics.

Development & production stages Development of the field Based on production & cost profile and recoverable reserves, a field development plan (FDP) is prepared, comprising of detailed plan of engineering work, drilling of development wells, setting up pipelines and installation of production & processing facilities. The aim of an FDP is to maximise returns from the field, post which development is initiated (as per FDP).

Development costs are capitalised and generally comprise over two-third of the finding & development (F&D) costs. Development expenditure depends on field location (onshore/offshore), field size, hydrocarbon properties, oil & gas mix, reservoir properties and depth of hydrocarbons:


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• Field location. Development cost of offshore fields is higher than that of onshore. Usually, drilling costs of onshore well are US$50,000/day, of shallow-water offshore wells are US$100,000-200,000/day, and of deep-water offshore wells are US$300,000-500,000/day.

• Size of discovery. Higher discovery size reduces per-barrel fixed cost (production/processing facilities) as more reserves share the common facilities.

• Hydrocarbon properties. If crude is waxy or of high pouring point (i.e., temperature at liquid converted to solid form), additional heating facilities are required on the crude off-take pipelines so that crude remains in a liquid state and flows smoothly through the pipeline. Moreover, additional wells for water/polymer injection are required for more oil recovery that increases development expenditure.

• Oil & gas mix. Development of only an oil-containing field is simple, while presence of gas complicates the development process as additional gas offtake & processing facilities are required, though presence of gas improves the oil recovery.

• Reservoir properties. The lower the permeability (ease with which fluid passes through) of reservoir, the higher the recovery of oil and gas and, hence, the lower the number of wells required to recover the reserves. Highly porous reservoir requires additional well completion costs such as more cementing of wells.

• Depth of hydrocarbons reservoir. The deeper the presence of hydrocarbons beneath the earth’s surface, the more time and material required for drilling and completion of wells.

Commencement of production, production ramp-up & peak/plateau production Production commences post completion of development activities. Production facilities are designed for plateau production rate. Plateau gas production rate is normally linked to fulfil gas sales contract. On the other hand, plateau oil production rate duration is shorter than plateau gas production rate as the target is to maximise oil production owing to oil being easily transportable & sold in spot.

Chart 8: Typical oil & gas field production profile

Source: Ecosilly


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When production is started from a field, the oil company focuses on reservoir management in order to maximise oil & gas production over the life of the reservoir. Though, 100% oil or gas recovery is not possible from the reservoir, better reservoir management leads to higher oil & gas recovery and longer reservoir life.

Additional drilling and applying EOR/IOR to arrest field production decline Production from a well exhibits the continuous decline in production rate, unless secondary or tertiary oil recovery techniques, such as enhanced oil recovery (EOR) and improved oil recovery (IOR), are applied. EOR/IOR either offsets or minimises the production rate decline for sometime, leading to broader plateau production time. But wells again start witnessing a declining production trend; therefore, additional wells are required to be drilled in order to reduce production decline at overall field level, as production from new wells would offset production decline from old wells.

Chart 9: ONGC arrests production decline through EOR/IOR campaign

Source: ONGC presentation

Oil companies take into account many alternatives to recover oil and gas from the reservoir as, in most fields, only a portion of the oil can be produced by natural reservoir pressure. Hence, an oil company may enhance recovery through techniques that maintain the reservoir’s pressure and flow. This can be done through secondary/tertiary (EOR/IOR) recovery techniques such as injection of heat, water, CO2 gas, polymers and chemicals in the reservoir. A familiar EOR technique is applied to onshore fields called ‘infill’ drilling, where the company drills a new well in between producing wells to offset production decline from old wells.

Overall production decline at field level Production decline at field level starts when there is no further scope to increase field production due to additional drilling wells as most of the recoverable reserves would be produced from the current production wells (Note: Reserves recoverable from such wells, without any significant additional capex, are called ‘proved developed producing reserves’ or PDP reserves).


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Production becomes uneconomical – Plug & abandon well and field When declining production rate from a well reaches such a low level that revenue from the well is not sufficient to recover operating expenses, then the well is plugged and abandoned after incurring site restoration expenditure as regulatory requirement. Similarly, a field is abandoned after site restoration, when production from the field does not provide economic returns and there is no further scope to economically increase production.

Understanding the definition & classification of ‘reserves’

Chart 10: Petroleum reserves classification

Source: Society of Petroleum Engineers

In the Indian perspective, understanding the definition and classification of reserves is vital as Indian E&P companies’ reserves disclosures are not comparable.

For example, ONGC discloses its ultimate reserves (also called 3P or Proved+Probable+Possible) accretion to show reserve replacement ratio (i.e., reserves added per annual production). While ONGC discloses proved reserves (1P) in its annual report, Cairn India discloses 2P reserves (Proved+Probable). Niko discloses proved and probable reserves separately in its annual filings that are mainly KG D6 reserves. If proved reserves data of Indian firms is not available, then 2P and 3P reserves of Indian firms are not comparable with developed E&P markets – e.g., US E&P firms disclose just proved reserves (1P), as per SEC requirements.

We have attempted to elucidate reserve classification, based on Society of Petroleum Engineers (SPE) classification (Chart 10). Here, reserves classification is explained on the basis of the degree of uncertainty of economical recovery as well as degree of increasing maturity that categorises initially-in-place reserves as per improvement in the economics of the field.


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In Chart 10, the horizontal axis represents the range of uncertainty in the estimated potentially recoverable volume for an accumulation, whereas the vertical axis represents the level of status/maturity of the accumulation. Many organisations choose to further sub-divide each resource category using the vertical axis to classify accumulations on the basis of commercial decisions required to move an accumulation towards production. In Chart 10, the low, best and high estimates of potentially recoverable volumes should reflect some comparability with the reserves categories of Proved, Proved+Probable and Proved+Probable+Possible respectively. While there may be a significant risk, i.e., sub-commercial or undiscovered accumulations will not achieve commercial production, it is useful to consider the range of potentially recoverable volumes independently of such a risk.

• Total petroleum initially-in-place reserve is the quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. Hence:

Total petroleum-initially-in-place = quantity of petroleum estimated, on a given date, to be contained in known accumulations + quantity already produced + estimated quantity in accumulations yet to be discovered.

In the same manner, stock tank oil initially in place (STOIIP) and gas initially in place (GIIP) are defined. Total petroleum-initially-in-place may be subdivided into discovered petroleum-initially-in-place and undiscovered petroleum-initially-in-place, with the former being limited to known accumulations:

- Discovered-initially-in-place reserve is the quantity of petroleum that is estimated, on a given date, to be contained in known accumulations + quantity already produced. Discovered petroleum-initially-in-place may be subdivided into commercial and sub-commercial categories, with the estimated potentially recoverable portion being classified as reserves and contingent resources respectively, as defined below:

• Reserves are those quantities of petroleum that are anticipated to be commercially recovered from known accumulations (discovered) from a given date. Reserves are divided into three categories – proved, probable and possible – that indicate low-to-high uncertainty of recovery. Hence, proved reserves are most valuable reserves followed by risky probable and more risky possible reserves. Investors require adjusting probable and possible value for the uncertainty risk before valuing them.

Proved reserves are those that are commercial in current economic conditions, such as prices, technology, costs environment – e.g., a well is drilled for production when reserves are commercially recoverable at current crude prices and, thus, classified as proved reserves. But after drilling the well and commencement of production, crude prices fall such that revenue from oil production will not recover past development capex, though oil production is still economically profitable after incurring operating expenses as no further development capex is required. Then, reserves will still be in the proved reserves category. Overall, it is the low reserves recovery risk and commerciality of the reserves to produce dictates whether reserves would be classified as less-risky proved reserves or high-risky probable/possible reserves. Proved reserves are classified as proved developed and proved undeveloped reserves.


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Proved undeveloped (PUD) are those that are expected to be recovered from future wells and facilities, including future EOR/IOR projects that are anticipated with a high level of certainty in reservoirs.

Proved developed (PD) are those that are expected to be recovered from existing wells and facilities. Among proved reserves, PD reserves are more valuable as against PUD as most development activities have already been completed for PD reserves. PD reserves are classified as proved developed producing (PDP) and proved developed non-producing (PDNP):

⇒ PDP are PD reserves that are expected to be recovered from currently producing wells.

⇒ PDNP are PD reserves that are expected to be recovered from: i) wells that are completed but have not started production, ii) wells that are shut for market conditions or pipeline connection work.

Probable reserves are those unproved reserves that are anticipated to be included in the proved reserves category: i) by additional drilling nearby proved reserves areas, where access to these reserves is not sufficient to classify them as proved reserves currently, ii) where studies suggest that reserves appear to be productive but lack of some required tests such as drilling does not justify them to be considered part of the less risky proved reserves category, iii) reserves that can not be accessed due to minimum well spacing requirements but can be accessed if infill wells drilling between existing producing wells is allowed, iv) reserves recovered through IOR/EOR methods that are under pilot projects, v) reserves to be recovered from additional capex, where current procedures on similar reservoirs do not provide successful results.

Possible reserves are those unproved reserves that are less likely to be recoverable than probable reserves. Possible reserves may comprise: i) reserves that possibly exist beyond probable reserves areas, ii) log/core analysis suggests likely presence of petroleum-bearing reserves, but might not produce at rates that justifies commerciality, iii) other criteria similar for probable reserves definition, but carrying additional risk such as commerciality and recoverability.

o Contingent resources are those quantities of petroleum that are estimated, on a given date, to be potentially recoverable from known accumulations (discovered), but are not currently considered to be commercially recoverable. For example, RIL’s two discoveries in KG-D3 blocks last year are currently considered contingent resources because commerciality of those discoveries is subject to further positive results owing to significant capex requirements in the offshore block.


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- Undiscovered-in-place reserve is that quantity of petroleum which is estimated, on a given date, to be present in accumulations yet to be discovered. The estimated potentially recoverable portion of undiscovered petroleum-initially-in-place is classified as prospective resources.

o Prospective resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations.

- Unrecoverable are those quantities of in-place-petroleum that are not recoverable by any means using current technology. For example, if the recovery factor of an oil field is 0.3, then 30% of the in-place hydrocarbons would be recoverable and the remaining 70% unrecoverable.


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Annexure 2: Key exploration risks The exploration stage carries higher risks such as likelihood of negligible/nil hydrocarbons presence, lower-than-expected reserves and possibility of non-commercial discovery. The risks can be broadly divided in three types and should be used to translate the unrisked reserves into expected risked reserves by ascribing the appropriate probability for these reserves (process of computing risky reserves from unrisked reserves is called reserve risking).

Risky Reserves = Unrisked Reserves x {1 – Probability (Commerciality risk)} x {1 – Probability (Geology risk)} x {1 – Probability (Wrong well drilling risk)}

Commerciality risk Commerciality risk entails that anticipated reserves from the exploratory prospect might not be commercially developed due to reasons such as dip in crude prices, lower hydrocarbons finds that would not justify development capex economics and cost escalation.

For example, despite two discoveries in KG-D3 blocks, commerciality of the block has not been established. Further positive drilling results from nearby/appraisal wells in the block are required to prove commerciality. However, post two discoveries in KG-D3 block, commerciality risk would become significantly lower.

Geology risk (on commercially proved acreage) Assuming that commerciality of the discovered reserves has been proved, it is the risk that upside of reserve accretion near commercially-proved reserves could be lower than expected due to limited information on geology beneath the earth’s surface. In other words, it is the risk that reservoir boundary could be smaller than expected earlier, leading to risk of lower reserve accretion. This risk is relevant for commercially proved blocks such as KG-D6; there are expectations of further reserve accretion near D1 & D3 gas discoveries.

Risk of drilling dry hole Wrong well drilled is called ‘dry hole’, which is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Drilling a dry hole during wildcat exploration (a region where no hydrocarbons were discovered earlier) raises concerns about the presence of sufficient in-place hydrocarbons in the acreage and, therefore, increases the ‘commerciality risk’ or lowers the ‘un-risked reserves’. Drilling a dry appraisal well near a discovery leads to lowering of reserve estimates from discovery.

‘Wrong well drilling risk’ not only reduces the risky reserves (risk adjusted un-risked reserves) that are used to value an E&P asset, but also increases F&D cost, leading to lower returns expectations from exploratory E&P asset and, subsequently, lower E&P asset value.


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Annexure 3: Oil & gas properties vital for valuation

Crude oil characteristics Light versus heavy crude Crude oil is categorised by its density and is measured as API (American Petroleum Institute) gravity in degrees. API gravity is a measure of relative density of various crude oils against water and is widely used to compare relative densities of different crude types. API gravity of fresh-water is 10, implying that water is heavier than crude.

Crude oil is classified as light, medium or heavy, according to its API gravity (Table 17). The lighter the crude oil, the higher its value as lighter variety crude gives higher yield of more valuable lighter refinery products such as gasoline.

Table 17: Crude oil category, as per API API gravity (degrees) Crude oil type Less than 10 Extra heavy oil or bitumen 10 Fresh water 10 to 22.3 Heavy crude oil 22.3 to 31.1 Medium crude oil More than 31.1 Light crude oil

Source: Wikipedia, I-Sec Research API gravity = (141.5 / specific gravity at 60°F) – (131.5)

Sweet versus sour crude Crude oil is also characterised as sweet or sour crude. Sweet crude contains less than 0.5% sulphur, while sour crude contains more than 0.5% sulphur. Sweet crude is more valuable than sour crude because it is less expensive to refine as it contains a disproportionately large amount of fractions that are used to process gasoline, kerosene, and high-quality diesel. On the other hand, sour crude requires additional crude processing facilities to remove sulphur & other impurities to produce.

Wax content in crude Viscosity (the measure of oil’s resistance to flow) of oil depends on its wax content. The higher the wax content, the higher the resistance to flow. Viscosity decreases with increase in temperature and pressure. Therefore, highly viscous oil needs extra costs on additional heating facilities during pipeline transportations so that oil can flow smoothly through pipeline. Higher wax content oil also requires additional refinery facilities investments to remove wax content from oil in order to avoid choking of refinery equipments from the oil. Hence, higher wax content oil is cheaper versus lower wax content oil.

Natural gas characteristics Sour versus sweet gas Sour natural gas is a natural gas that contains sulphur and other impurities that should be removed; sweet natural gas contains nil or minimal sulphur compounds such that no gas processing requires. Therefore, sour gas is less valuable than sweet gas.

Dry versus rich gas Dry gas or lean gas contains insufficient quantities of hydrocarbons heavier than methane to allow their extraction for more value-added products production such as LPG. Rich gas contains sufficient hydrocarbons to produce more valuable LPG. Therefore, dry gas is cheaper than rich gas on basis of equivalent volumes.


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Annexure 4: Domestic oil & gas pricing

Oil pricing Pricing of domestically-produced crude oil is benchmarked against actively-traded crude variety globally, usually by adjusting benchmark crude prices for gross product worth (GPW) differentials and crude quality premium/discount. GPW is the value of the weighted average price quotes of products such as LPG, SKO, naphtha and wax-residue, as per the percentage yields of these products from the crude.

Therefore, for a particular month, the average price to be quoted for domestically produced crude would be:

Average domestic crude price = A + B + C (1)

Where,

A = Average benchmark crude price

B = GPW differential over benchmark crude

C = +/- Quality Premium/Discount over benchmark crude

Illustration: RIL’s KG-D6 MA oil price calculation

RIL’s crude price is benchmarked to Bonny Light crude for GPW differential and 2% quality differential premium.

As an illustration, we assume that for the month under consideration, average Bonny Light prices are US$75/bl.

As per formula (1) above,

Average Bonny Light prices, A = US$75/bl

Based on this, we have calculated GPW in US$/MT of Bonny Light and KG MA oil (Table 18).

Table 18: GPW calculation of crude Weight yields (%) GPW per MT of crude (US$/MT)

Products Average

monthly price Conversion

from MT to bl Bonny

Light KG D6 Bonny

Light KG D6 LPG 600 US$/MT 1.0 0.7 1.1 3.9 6.4 Naphtha 70 US$/bl 9.0 15.1 20.9 95.0 131.9 SKO 80 US$/bl 7.9 15.2 17.3 96.0 109.6 HSD 85 US$/bl 7.5 36.6 32.5 231.6 205.5 Wax Residue 60 US$/bl 6.7 32.5 28.2 130.7 113.4 Total 100.0 100.0 557.2 566.8

Source: Infraline, I-Sec Research


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We then convert the GPW value of crude from US$/MT to US$/bl (Table 19).

Table 19: GPW conversion from US$/MT to US$/bl GPW (US$/MT) Conversion – MT to bl GPW (US$/bl) Bonny Light 557.2 7.31 76.2 KG MA oil 566.8 7.75 73.13 GPW differential (3.1)

Source: Infraline, I-Sec Research For formula (1) above,

B = US$(3.1)/bl (as per Table 18 & Table 19)

C = 2% of average Bonny Light price = 2% of 75 = US$1.5/bl

Thus, average KG MA oil price = A + B + C = 75 – 3.1 + 1.5 = US$73.4/bl

Gas pricing Currently, there are two types of gas pricing regimes in India – APM and non-APM. APM gas is produced by national oil companies (NOCs) – ONGC and OIL – from the blocks nominated to NOCs. Non-APM gas is domestically produced from private firms or private firms’ JVs with NOCs. Non-APM gas also includes gas from imported LNG. Domestically-produced, non-APM gas pricing is decided as PSC for the producing field. On the other hand, imported LNG’s long-term pricing is mainly determined from the sales & purchase contract between LNG seller (such as Qatar LNG) and LNG purchaser. However, the government has intervened in long-term LNG pricing to LNG purchasers through Petronet LNG by applying pooled LNG price (average LNG price). For Spot LNG, pricing is determined by agreed-upon terms between the seller and purchaser.

In FY09, 90mmscmd of natural gas domestically produced, of which 75% was APM gas and 25% was obtained from private/JVs. But APM gas share in domestic gas production is expected to decline in the next five years on account of ramp-up in RIL’s KG-D6 gas production as well as production from other NELP discoveries.

APM gas pricing APM gas is sold at significant discount vis-à-vis non-APM gas or free market gas. APM gas is only available to priority sectors – Power, Fertilisers, consumers under court directed order for APM gas supply, and consumers with <50,000scmd gas allocation.

The price of APM gas does not vary among states, but for North East and rest of nation customers. APM gas price also varies among sectors. The price at which NOCs sell gas to GAIL is called ‘producer price’ and price at which GAIL sells APM gas to customers is called ‘consumer price’. Difference between consumer and producer prices is used to create a gas pool account, which is used to provide costly non-APM gas to priority consumers at discounted APM price.


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Table 20: APM gas producer and consumer prices Price (Rs/mscm) Remarks Producer price Rest of nation 3,200 NorthEast 1,920 40% discount to rest of nation Consumer price to rest of nation (ex NorthEast) Power and fertiliser customers 3,200 Same as producer price Other than power and fertiliser consumers 3,840 20% higher than power and fertiliser

consumers Consumer price to North East Power and fertiliser customers 1,920 40% discount to ex NorthEast power

and fertiliser consumers Other than power and fertiliser consumers 2,304 20% higher North East power and

fertiliser consumers Source: I-Sec Research Non-APM, pre-NELP gas pricing Non-APM, pre-NELP gas is produced by private consortium or private JVs with NOCs and gas pricing is governed as per PSCs. Table 21 shows prices of various non-APM gas as per PSCs.

Table 21: Non-APM gas prices of various fields Fields, buyers Price (Rs/mmbtu) Panna Mukta GAIL 5.73 PRVUNL 4.60 Torrent 4.75 Tapti GAIL 5.57 Ravva GAIL (for associated gas) 3.50 GAIL (for non-associated satellite gas) 4.30 Hazira Multiple buyers 5.50 GSEG, FAEL, GSPC 5.00 CB OS/2 CGCL 4.60 GPEC 4.75 GSPC 5.50 Bheema CB-ONN-2000/2 5.50

Source: Industry

NELP gas pricing The price formula is approved by the government for pricing/selling RIL’s KG-D6 gas is:

Selling price (US$/mmbtu) = 2.5 + (CP-25)0.15

where CP is crude price in US$/bl, with cap of US$60/bl. Therefore, for crude prices above US$60/bl, the price formula gives gas price at US$4.2/mmbtu, which is uniform across all sectors.


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Annexure 5: Glossary & abbreviations of key terms Glossary of terms used in the Energy Information Administration (EIA) and the Directorate General of Hydrocarbons India (DGH) websites:

Acreage: An area measured in acres that is subject to ownership or control by those holding total or fractional shares of working interests. Acreage is considered developed when development has been completed. A distinction may be made between ‘gross’ acreage and ‘net’ acreage:

• Gross – All acreage covered by any working interest, regardless of the percentage of ownership in the interest.

• Net – Gross acreage adjusted to reflect the percentage of ownership in the working interest in the acreage.

API gravity: API measure of specific gravity of crude oil or condensate in degrees. An arbitrary scale expressing the gravity or density of liquid petroleum products. The measuring scale is calibrated in terms of degrees; it is calculated as follows:

Degrees API = (141.5 / specific gravity at 60°F) – (131.5)

Appraisal programme: A programme, carried out following a discovery in the contract area for the purpose of appraising discovery and delineating the petroleum reservoirs to which the discovery relates in terms of thickness and lateral extent and determining the characteristics and the quantity of recoverable petroleum within.

Appraisal well: A well drilled pursuant to an appraisal programme.

Approved work programme: A work programme that has been approved by the Management Committee pursuant to the provisions of this contract.

Arms length sales: Sales made freely in the open market, in freely convertible currencies, between willing and unrelated sellers and buyers and in which such buyers and sellers have no contractual or other relationship, directly or indirectly, or any common or joint interest as is reasonably likely to influence selling prices and shall, inter alia, exclude sales (whether direct or indirect, through brokers or otherwise) involving affiliates, sales between companies which are parties to this contract, sales between governments and government-owned entities, counter trades, restricted or distress sales, sales involving barter arrangements and generally any transactions motivated in whole or in part by considerations other than normal commercial practices.

Associated natural gas: Associated natural gas or ‘ANG’ means natural gas produced in association with crude oil either as free gas or in solution, if such crude oil can by itself be commercially produced.

Associated-dissolved natural gas: Natural gas that occurs in crude oil reservoirs either as free gas (associated) or as gas in solution with crude oil (dissolved gas).


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Barrel: A quantity or unit equal to 158.9074 litres (equivalent to 42 US gallons) liquid measure, at a temperature of 60ºF (15.56ºC) and under one atmosphere pressure (14.70 psia).

Basement: Any igneous or metamorphic rock, or rocks or any stratum of such nature, in and below which the geological structure or physical characteristics of the rock sequence do not have the properties necessary for the accumulation of petroleum in commercial quantities and which reflects the maximum depth at which any such accumulation can be reasonably expected in accordance with the knowledge generally accepted in the international petroleum industry.

Coal bed methane (CBM): Methane is generated during coal formation and is contained in the coal microstructure. Typical recovery entails pumping water out of the coal to allow the gas to escape. Methane is the principal component of natural gas. Coal bed methane can be added to natural gas pipelines without any special treatment.

Commercial production: The production of crude oil or condensate or natural gas or any combination of these from the contract area (excluding production for testing purposes) and delivery of the same at the relevant delivery point under a programme of regular production and sale.

Condensate: Condensate means those low vapour pressure hydrocarbons obtained from natural gas through condensation or extraction and refers solely to those hydrocarbons that are liquid at normal surface temperature and pressure conditions provided that in the event condensate is produced from a development area and is segregated at the delivery point or transported to the delivery point after segregation, then the provisions of this contract shall apply to such condensate as if it were crude oil.

Cost petroleum: The portion of the total value of petroleum produced & saved from the contract area which the contractor is entitled to take in a particular period, for the recovery of contract costs as provided in the PSC.

Cubic foot (cf), natural gas: The amount of natural gas contained at standard temperature and pressure (60ºF and 14.73lb/sq inch) in a cube whose edges are 1ft long.

Deepwater area: Deepwater area (for deepwater blocks/areas) means area falling beyond four hundred (400) metre isobaths, provided, however, that for the purposes of this contract, the contract area as on effective date, as described in the PSC.

Development area: The part of the contract area which encompasses one or more commercial discovery and any additional area that may be required for proper development of such commercial discovery and established as such in accordance with the provisions of the PSC.

Development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing the oil and gas. More specifically, development costs, depreciation and applicable operating costs of support equipment and facilities, and other costs of development activities, are costs incurred to:


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• gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites; clearing ground; draining; road building; and relocating public roads, gas lines, and power lines to the extent necessary in developing the proved reserves.

• drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

• acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants, and utility waste disposal systems.

• provide improved recovery systems.

Development plan: A plan submitted by the contractor for the development of a commercial discovery, which has been approved by the management committee or the government pursuant to the PSC.

Development well: A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Directional (deviated) well: A well purposely deviated from the vertical, using controlled angles to reach an objective location other than directly below the surface location. A directional well may be the original hole or a directional "sidetrack" hole that deviates from the original bore at some point below the surface. The new footage associated with directional "sidetrack" holes should not be confused with footage resulting from remedial sidetrack drilling. If there is a common bore from which two or more wells are drilled, the first complete bore from the surface to the original objective is classified and reported as a well drilled. Each of the deviations from the common bore is reported as a separate well.

Discovery: Discovery means the finding, during petroleum operations, of a deposit of petroleum not previously known to have existed, which can be recovered at the surface in a flow measurable by petroleum industry testing methods.

Discovery area: That part of the contract area about which, based upon discovery and the results obtained from a well or wells drilled in such part, the contractor is of the opinion that petroleum exists and is likely to be produced in commercial quantities.

Drilling: The act of boring a hole to: i) determine whether minerals are present in commercially recoverable quantities and ii) to accomplish production of the minerals (including drilling to inject fluids).

• Exploratory – Drilling to locate probable mineral deposits or to establish the nature of geological structures; such wells may not be capable of production if minerals are discovered.

• Developmental – Drilling to delineate the boundaries of a known mineral deposit to enhance the productive capacity of the producing mineral property.

• Directional – Drilling that is deliberately made to depart significantly from the vertical.


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Dry hole: An exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Dry natural gas: Natural gas which remains after: i) the liquefiable hydrocarbon portion has been removed from the gas stream (i.e., gas after lease, field, and/or plant separation); and ii) any volumes of non-hydrocarbon gases have been removed where they occur in sufficient quantity to render the gas unmarketable. Notably, dry natural gas is also known as consumer-grade natural gas. The parameters for measurement are cubic feet at 60ºF and 14.73lb per square inch absolute.

Equity crude oil: The proportion of production that a concession owner has the legal and contractual right to retain.

Exploration drilling: Drilling done in search of new mineral deposits, on extensions of known ore deposits, or at the location of a discovery up to the time when the company decides that sufficient ore reserves are present to justify commercial exploration. Assessment drilling is reported as exploration drilling.

Exploratory well: A hole drilled: i) to find and produce oil or gas in an area previously considered unproductive area; ii) to find a new reservoir in a known field, i.e., one previously producing oil and gas from another reservoir, or iii) to extend the limit of a known oil or gas reservoir.

Extensions, discoveries, and other additions: Additions to an enterprise's proved reserves that result from: i) extension of the proved acreage of previously discovered (old) reserves through additional drilling in periods subsequent to discovery and ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.

Flared natural gas: Gas disposed of by burning in flares usually at the production sites or at gas processing plants.

Footage drilled: Total footage for wells in various categories, as reported for any specified period, includes: i) the deepest total depth (length of well bores) of all wells drilled from the surface, ii) the total of all bypassed footage drilled in connection with reported wells, and iii) all new footage drilled for directional sidetrack wells. Footage reported for directional sidetrack wells does not include footage in the common bore that is reported as footage for the original well. In the case of old wells drilled deeper, the reported footage is that which was drilled below the total depth of the old well.

Foreign access refers to proved reserves of crude, condensate, and natural gas liquids applicable to long-term supply agreements with foreign governments or authorities in which the company or one of its affiliates acts as producer.

Geological and geophysical (G&G) costs: Costs incurred in making geological and geophysical studies, including, but not limited to, costs incurred for salaries, equipment, obtaining rights of access, and supplies for scouts, geologists, and geophysical crews.

Gross working interest ownership basis: Gross working interest ownership is the respondent's working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.


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Hydrocarbon: An organic chemical compound of hydrogen and carbon in the gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (methane, a constituent of natural gas) to the very heavy and very complex. Improved recovery: Extraction of crude oil or natural gas by any method other than those that rely primarily on natural reservoir pressure, gas lift, or a system of pumps.

Investment multiple: Investment multiple means, the ratio of accumulated net income to accumulated investment by the contractor, as determined in the PSC.

Lease operations: Any well, lease, or field operations related to the exploration for or production of natural gas prior to delivery for processing or transportation out of the field. Gas used in lease operations includes usage such as for drilling operations, heaters, dehydraters, field compressors, and net used for gas lift.

Lifting costs: The costs associated with the extraction of a mineral reserve (oil and gas) from a producing property.

Liquefied natural gas (LNG): Natural gas (primarily methane) that has been liquefied by reducing its temperature to -260ºF at atmospheric pressure.

Multiple completions well: A well equipped to produce oil and/or gas separately from more than one reservoir. Such wells contain multiple strings of tubing or other equipment that permit production from the various completions to be measured and accounted for separately. For statistical purposes, a multiple completion well is reported as one well and classified as either an oil well or a gas well. If one of the several completions in a given well is an oil completion, the well is classified as an oil well. If all of the completions in a given well are gas completions, the well is classified as a gas well.

Natural gas liquids (NGL): Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods in gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline, and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane, and isobutene).

Natural gas marketer: A company that arranges purchases and sales of natural gas. Unlike pipeline companies or local distribution companies, a marketer does not own physical assets commonly used in the supply of natural gas, such as pipelines or storage fields. A marketer may be an affiliate of another company, such as a local distribution company, natural gas pipeline, or producer, but it operates independently of other segments of the company.

New field: A field discovered during the report year.

New field discoveries: The volumes of proved reserves of crude oil, natural gas, and/or natural gas liquids discovered in new fields during the report year.

New reservoir: A reservoir discovered during the report year.


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Offshore: That geographic area that lies seaward of the coastline. In general, the coastline is the line of ordinary low water along with that portion of the coast that is in direct contact with the open sea or the line marking the seaward limit of inland water.

Permeability: The ease with which fluid flows through a porous medium.

Petroleum: A broadly defined class of liquid hydrocarbon mixtures, including crude oil, lease condensate, unfinished oils, refined products obtained from the processing of crude oil, and natural gas plant liquids. Notably, volumes of finished petroleum products include non-hydrocarbon compounds, such as additives and detergents, after they have been blended into the products.

Pipeline quality natural gas: A mixture of hydrocarbon compounds existing in the gaseous phase with sufficient energy content, generally above 900 British thermal units (btu), and a small share of impurities for transport through commercial gas pipelines and sale to end-users.

Pool: In general, a reservoir. In certain situations, a pool may consist of more than one reservoir.

Pre-discovery costs: All costs incurred in an extractive industry operation prior to the actual discovery of minerals in commercially recoverable quantities; normally includes prospecting, acquisition, and exploration costs and may include some development costs.

Primary recovery: The crude oil or natural gas recovered by any method that may be employed to produce them where the fluid enters the well bore by the action of natural reservoir pressure (energy or gravity).

Probable reserves: Estimated quantities of energy sources that, on the basis of geologic evidence that supports projections from proved reserves (see definition below), can reasonably be expected to exist and be recoverable under existing economic and operating conditions. Site information is insufficient to establish with confidence the location, quality, and grades of the energy source. Notably, this term is equivalent to ‘indicated reserves’ as defined in the resource/reserve classification contained in the US Geological Survey Circular 831, 1980. Measured and indicated reserves, when combined, constitute demonstrated reserves.

Production costs: Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. The following are examples of production costs (sometimes called lifting costs): costs of labour to operate the wells and related equipment and facilities; repair and maintenance costs; the costs of materials, supplies, and fuels consumed and services utilised in operating the wells and related equipment and facilities; the costs of property taxes and insurance applicable to proved properties and wells and related equipment and facilities; the costs of severance taxes.

Depreciation, depletion, and amortisation (DD&A) of capitalized acquisition, exploration, and development costs are not production costs, but also become part of


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the cost of oil and gas produced along with production (lifting) costs identified above. Production costs include the following subcategories of costs: well workers and maintenance; operating fluid injections and improved recovery programs; operating gas processing plants; ad-valorem taxes; production or severance taxes; other, including overhead.

Profit petroleum: Profit petroleum means, the total value of petroleum produced from the contract area in a particular period, as reduced by cost petroleum.

Proved reserves: Estimated quantities of energy sources that analysis of geologic and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions. The location, quantity, and grade of the energy source are usually considered to be well established in such reserves. Note: This term is equivalent to ‘measured reserves’ as defined in the resource/reserve classification contained in the U.S. Geological Survey Circular 831, 1980. Measured and indicated reserves, when combined, constitute demonstrated reserves.

Reserve additions: The estimated original, recoverable, saleable, and new proved reserves credited to new fields, new reservoirs, new gas purchase contracts, amendments to old gas purchase contracts, or purchase of gas reserves in-place that occurred during the year and had not been previously reported.

Reserve revisions: Changes to prior year-end proved reserves estimates, either positive or negative, resulting from new information other than an increase in proved acreage (extension). Revisions include increases of proved reserves associated with the installation of improved recovery techniques or equipment. They also include correction of prior year arithmetical or clerical errors and adjustments to prior year-end production volumes to the extent that these alter reserves estimates.

Reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

Service well: A well drilled, completed, or converted for the purpose of supporting production in an existing field. Wells of this class also are drilled or converted for the following specific purposes: gas injection (natural gas, propane, butane or fuel-gas); water injection; steam injection; air injection; salt water disposal; water supply for injection; observation; and injection for in-situ combustion.

Sidetrack drilling: This is a remedial operation that results in the creation of a new section of well bore for the purpose of: i) detouring around junk, ii) redrilling lost holes, or iii) straightening key seats and crooked holes. Directional ‘side-track’ wells do not include footage in the common bore that is reported as footage for the original well.

Stratigraphic test well: A geologically directed drilling effort to obtain information pertaining to a specific geological condition that might lead toward the discovery of an accumulation of hydrocarbons. Such wells are customarily drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.


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Undiscovered recoverable reserves (crude oil and natural gas): Those economic resources of crude oil and natural gas, yet undiscovered, that are estimated to exist in favourable geologic settings.

Wellhead: The point at which the crude (and/or natural gas) exits the ground. Following historical precedent, the volume and price for crude oil production are labelled as ‘wellhead’, even though the cost and volume are now generally measured at the lease boundary. In the context of domestic crude price data, the term ‘wellhead’ is the generic term used to reference the production site or lease property.

Wellhead price: The value at the mouth of the well. In general, the wellhead price is considered to be the sales price obtainable from a third party in an arm's length transaction. Posted prices, requested prices, or prices as defined by lease agreements, contracts, or tax regulations should be used where applicable.

Abbreviations The following are the abbreviations contained in the glossary in the Energy Information Administration (EIA) website:

bbl: barrel(s)

bbl/d: barrel(s) per day

bcf: billion cubic feet

BOE: barrels of oil equivalent

btu: British thermal unit(s)

mcf: One thousand cubic feet

mmblpd: One million barrels of oil per day

mmbtu: One million British thermal units

mmcf: One million cubic feet


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Annexure 6: Index of Tables and Charts

Tables Table 1: Advantages & disadvantages of various valuation methodologies ........................3 Table 2: Quick EV/reserves estimates for a discovery .........................................................5 Table 3: Assumptions for Indian and US E&P firm...............................................................8 Table 4: Assumption – US E&P firm cashflow profile...........................................................9 Table 5: Example of Indian E&P firm cash-flow profile.........................................................9 Table 6: NELP awards – An overview ................................................................................15 Table 7: Common assumptions for key offshore blocks’ valuations...................................17 Table 8: India’s key promising gas offshore blocks – A comparison..................................17 Table 9: Key offshore blocks’ revenue-share terms with GoI, as per IM............................17 Table 10: KG D6 – Valuations ............................................................................................18 Table 11: KG D3 – Valuations ............................................................................................19 Table 12: MN D4 – Valuations............................................................................................20 Table 13: KG D9 – Valuations ............................................................................................21 Table 14: NEC 25 – Valuations ..........................................................................................22 Table 15: GSPC’s Deen Dayal – Valuations ......................................................................23 Table 16: Cairn’s RJ-ON-90/1 – Valuations........................................................................24 Table 17: Crude oil category, as per API............................................................................38 Table 18: GPW calculation of crude ...................................................................................39 Table 19: GPW conversion from US$/MT to US$/bl ..........................................................40 Table 20: APM gas producer and consumer prices ...........................................................41 Table 21: Non-APM gas prices of various fields.................................................................41

Charts Chart 1: ONGC SMODCF data from its FY09 annual report................................................6 Chart 2: Earnings trend of Indian and US E&P...................................................................10 Chart 3: India sedimentary basins ......................................................................................13 Chart 4: Petroleum and natural gas formation....................................................................25 Chart 5: Oil, gas and water deposits in a reservoir.............................................................26 Chart 6: Oil formation mechanism ......................................................................................26 Chart 7: Oil & gas exploration drilling .................................................................................30 Chart 8: Typical oil & gas field production profile................................................................31 Chart 9: ONGC arrests production decline through EOR/IOR campaign...........................32 Chart 10: Petroleum reserves classification .......................................................................33


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I-Sec investment ratings (all ratings relative to Sensex over next 12 months) BUY: +10% outperformance; HOLD: -10% to +10% relative performance; SELL: +10% underperformance

ANALYST CERTIFICATION We /I, Amit Mishra, PGDM, BE, CFA; Gagan Dixit, PGDM, BTech research analysts and the authors of this report, hereby certify that all of the views expressed in this research report accurately reflect our personal views about any and all of the subject issuer(s) or securities. We also certify that no part of our compensation was, is, or will be directly or indirectly related to the specific recommendation(s) or view(s) in this report. Analysts aren't registered as research analysts by FINRA and might not be an associated person of the ICICI Securities Inc.

Disclosures: ICICI Securities Limited (ICICI Securities) and its affiliates are a full-service, integrated investment banking, investment management and brokerage and financing group. We along with affiliates are leading underwriter of securities and participate in virtually all securities trading markets in India. We and our affiliates have investment banking and other business relationship with a significant percentage of companies covered by our Investment Research Department. Our research professionals provide important input into our investment banking and other business selection processes. ICICI Securities generally prohibits its analysts, persons reporting to analysts and their dependent family members from maintaining a financial interest in the securities or derivatives of any companies that the analysts cover. The information and opinions in this report have been prepared by ICICI Securities and are subject to change without any notice. The report and information contained herein is strictly confidential and meant solely for the selected recipient and may not be altered in any way, transmitted to, copied or distributed, in part or in whole, to any other person or to the media or reproduced in any form, without prior written consent of ICICI Securities. While we would endeavour to update the information herein on reasonable basis, ICICI Securities, its subsidiaries and associated companies, their directors and employees (“ICICI Securities and affiliates”) are under no obligation to update or keep the information current. Also, there may be regulatory, compliance or other reasons that may prevent ICICI Securities from doing so. Non-rated securities indicate that rating on a particular security has been suspended temporarily and such suspension is in compliance with applicable regulations and/or ICICI Securities policies, in circumstances where ICICI Securities is acting in an advisory capacity to this company, or in certain other circumstances. This report is based on information obtained from public sources and sources believed to be reliable, but no independent verification has been made nor is its accuracy or completeness guaranteed. This report and information herein is solely for informational purpose and may not be used or considered as an offer document or solicitation of offer to buy or sell or subscribe for securities or other financial instruments. Though disseminated to all the customers simultaneously, not all customers may receive this report at the same time. ICICI Securities will not treat recipients as customers by virtue of their receiving this report. Nothing in this report constitutes investment, legal, accounting and tax advice or a representation that any investment or strategy is suitable or appropriate to your specific circumstances. The securities discussed and opinions expressed in this report may not be suitable for all investors, who must make their own investment decisions, based on their own investment objectives, financial positions and needs of specific recipient. This may not be taken in substitution for the exercise of independent judgement by any recipient. The recipient should independently evaluate the investment risks. The value and return of investment may vary because of changes in interest rates, foreign exchange rates or any other reason. ICICI Securities and affiliates accept no liabilities for any loss or damage of any kind arising out of the use of this report. Past performance is not necessarily a guide to future performance. Actual results may differ materially from those set forth in projections. Forward-looking statements are not predictions and may be subject to change without notice. ICICI Securities and its affiliates might have managed or co-managed a public offering for the subject company in the preceding twelve months. ICICI Securities and affiliates might have received compensation from the companies mentioned in the report during the period preceding twelve months from the date of this report for services in respect of public offerings, corporate finance, investment banking or other advisory services in a merger or specific transaction. ICICI Securities and affiliates expect to receive compensation from the companies mentioned in the report within a period of three months following the date of publication of the research report for services in respect of public offerings, corporate finance, investment banking or other advisory services in a merger or specific transaction. It is confirmed that Amit Mishra, PGDM, BE, CFA; Gagan Dixit, PGDM, BTech research analysts and the authors of this report have not received any compensation from the companies mentioned in the report in the preceding twelve months. Our research professionals are paid in part based on the profitability of ICICI Securities, which include earnings from Investment Banking and other business. ICICI Securities or its affiliates collectively do not own 1% or more of the equity securities of the Company mentioned in the report as of the last day of the month preceding the publication of the research report. It is confirmed that Amit Mishra, PGDM, BE, CFA; Gagan Dixit, PGDM, BTech research analysts and the authors of this report or any of their family members does not serve as an officer, director or advisory board member of the companies mentioned in the report. ICICI Securities may have issued other reports that are inconsistent with and reach different conclusion from the information presented in this report. ICICI Securities and affiliates may act upon or make use of information contained in the report prior to the publication thereof. This report is not directed or intended for distribution to, or use by, any person or entity who is a citizen or resident of or located in any locality, state, country or other jurisdiction, where such distribution, publication, availability or use would be contrary to law, regulation or which would subject ICICI Securities and affiliates to any registration or licensing requirement within such jurisdiction. The securities described herein may or may not be eligible for sale in all jurisdictions or to certain category of investors. Persons in whose possession this document may come are required to inform themselves of and to observe such restriction.


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EQUITIES A Murugappan Executive Director +91 22 6637 7101 [email protected]

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A Primer on India Ep Valuations

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