EX-15.6

EX-15.6 20 d32971dex156.htm EX-15.6 EX-15.6

Exhibit 15.6

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

LOGO

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

APPRAISAL REPORT

as of

MARCH 31, 2015

on the

PROVED RESERVES

CERTAIN FIELDS

INDIA

owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED

DEGOLYER AND MACNAUGHTON

TABLE of CONTENTS


	Page

FOREWORD		1

Scope of Investigation		1
Authority		3
Source of Information		4

DEFINITION of RESERVES		5

ESTIMATION of RESERVES		11

VALUATION of RESERVES		14

Discussion of Fiscal Terms		15
RJ-ON-90/1 PSC (Rajasthan)		15
CB/OS-2 PSC		16
PKGM-1 License Area (Ravva)		16

SUMMARY and CONCLUSIONS		18

TABLES
Table 1 – Gross Proved Reserves
Table 2 – Net Proved Reserves
Table 3 – Reconciliation of Net Proved Reserves
Table 4 – Standardized Measure of Discounted Future Net Cash Flows and Changes therein relating to Proved Reserves

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

APPRAISAL REPORT

as of

MARCH 31, 2015

on the

PROVED RESERVES

CERTAIN FIELDS

INDIA

owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED

FOREWORD

Scope of Investigation

This report presents an appraisal, as of March 31, 2015, of the estimates of the extent and value of the proved oil, condensate, and sales-gas reserves of certain fields in India in which Cairn India Limited (Cairn) has represented that it owns an interest under the terms of various production sharing contracts (PSC) with the Government of India (GOI). This report has been prepared at the request of Vedanta Limited. Vedanta Limited has represented that it is the parent company and 58.9-percent owner of Cairn.

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after March 31, 2015. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Cairn after deducting all interests owned by others.

DEGOLYER AND MACNAUGHTON

Certain properties in which Cairn has represented that it owns an interest are subject to the terms of various production sharing agreements. The terms of these agreements generally allow for working-interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or standard cubic foot of gas equivalent by dividing by product prices to estimate the “entitlement reserves.”

These entitlement reserves are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” In this report, Cairn’s net reserves or interest for certain properties subject to these agreements is the entitlement based on Cairn’s working interest.

The fields evaluated herein are located in the CB/OS-2 PSC (three fields), the RJ-ON-90/1 PSC (six fields), and the PKGM-1 License Area (one field).

The CB-X, Gauri, and Lakshmi fields are located in the CB/OS-2 PSC, the Aishwariya, Aishwariya Barmer Hill, Bhagyam, Mangala, Mangala Barmer Hill, N-E, N-I, Raagashwari (Shallow), Raagashwari Deep, and Saraswati fields are located in the RJ-ON-90/1 PSC, and the Ravva field is located in the PKGM-1 License Area.

The net entitlement interests for the properties evaluated in this report are calculated for each PSC and may change from year-to-year depending on changes to the estimated costs projected for each field, the timing of production as well as price assumptions. Estimates of the entitlement interest for each PSC are as follows:


Area	Net Entitlement Interest
Area	Oil and Condensate (percent)		Gas (percent)

CB/OS-2 PSC		27.50		28.09
RJ-ON-90/1 PSC		42.75		44.94
PKGM-1 License Area		12.40		11.05

DEGOLYER AND MACNAUGHTON

This report also presents values that were estimated for proved reserves using prices and costs as of the date the estimate was made. In this report, the prices and costs were held constant for the lives of the properties. An explanation of the price and cost assumptions is included in the Valuation of Reserves section of this report.

Values of the proved reserves in this report are expressed in terms of estimated future net revenue and present worth. Future net revenue is calculated by deducting cash royalties, operating expenses, capital costs, production taxes, and host country income tax from the future gross revenue. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves attributable to Cairn. Operating expenses include field operating expenses, workover costs, compression costs, and all other direct costs specified by Cairn. Present worth is defined as the future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of oil, condensate, and sales-gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Authority

This report was authorized by Mr. Arun G. Kumar, Dy. CFO, Vedanta Limited.

DEGOLYER AND MACNAUGHTON

Source of Information

Information used in the preparation of this report was obtained from Cairn. In the preparation of this report we have relied, without independent verification, upon information furnished by Cairn with respect to the properties to be evaluated, the production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

DEGOLYER AND MACNAUGHTON

DEFINITION of RESERVES

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (l)-(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

DEGOLYER AND MACNAUGHTON

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

DEGOLYER AND MACNAUGHTON

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

DEGOLYER AND MACNAUGHTON

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

DEGOLYER AND MACNAUGHTON

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

DEGOLYER AND MACNAUGHTON

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

DEGOLYER AND MACNAUGHTON

ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Cairn, and the analyses of areas offsetting existing wells with test or production data, reserves were categorized as proved, probable, or possible.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps and isopach maps were used to estimate reservoir volumes. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP and OGIP.

For those reservoirs where the volumetric method was applied, estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rates, reservoir pressures, gas-oil ratio (GOR) behavior, and water-oil ratio (WOR) behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on existing economic conditions.

DEGOLYER AND MACNAUGHTON

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Estimates of proved reserves contained herein are based on forecasts that terminate at the economic limit, as defined in the Definition of Reserves section of this report, or at the end of the concession life, whichever occurs first.

Gas reserves estimated herein are expressed as sales gas at a temperature base of 60 degrees Fahrenheit and a pressure base of 14.7 pounds per square inch absolute. Separator gas is defined as the total gas produced from the reservoir after deductions for normal field separation, but before fuel usage and flare losses. Sales gas is defined as the separator gas to be delivered to a pipeline inlet after deductions for fuel usage and flare and the removal of nonhydrocarbon components to meet gas sales specifications. Estimates of fuel usage have been provided by Cairn.

The oil and condensate reserves estimated in this report are expressed in terms of 42 United States gallons per barrel. Crude oil reserves are to be recovered by conventional field operations. Condensate reserves are to be recovered by normal field separation.

Data available through January 2015 were used to prepare the estimates shown herein. Production was estimated for the months of February and March 2015. Estimated gross oil, gas, and condensate production was deducted from gross ultimate recovery to arrive at estimates of gross reserves shown herein.

The gross and net proved reserves evaluated herein are presented in Tables 1 and 2, respectively. A reconciliation of the net proved oil and condensate and sales-gas reserves, as of March 31, 2015, is shown in Table 3.

DEGOLYER AND MACNAUGHTON

The estimated gross and net proved developed, proved undeveloped, and total proved oil and condensate and sales-gas reserves, as of March 31, 2015, of the properties evaluated herein are summarized as follows, expressed in millions of barrels (MMbbl) and billions of cubic feet (Bcf):

Proved Developed

Proved Undeveloped

Total Proved

Oil and
Condensate
(MMbbl)

Sales Gas
(Bcf)

Oil and
Condensate
(MMbbl)

Sales Gas
(Bcf)

Oil and
Condensate
(MMbbl)

Sales Gas
(Bcf)

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

186.75

73.94

14.87

3.55

35.24

16.15

4.45

1.34

221.99

90.09

19.31

4.89

Note:

Net reserves include the 41.1-percent minority share not owned by Vedanta Limited.

DEGOLYER AND MACNAUGHTON

VALUATION of RESERVES

This report has been prepared using prices and costs and future price and cost assumptions specified by Cairn. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB).

All economic information provided by Cairn has been expressed in United States dollars (U.S.$) or Indian rupees (Rs.), and all revenue estimates included herein are expressed in Rs. using an exchange rate of Rs.61.15 per U.S.$1.00.

Revenue values in this report have been estimated for the properties using fiscal terms and economic parameters provided by Cairn. A discussion of the fiscal terms and other economic parameters follows.

Oil and Condensate Prices

Cairn has represented that the oil and condensate prices were based on a 12-month average price, calculated as the unweighted average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. All oil and condensate estimated herein is sold under contractual agreements. The volume-weighted average adjusted product price attributable to estimated proved reserves was U.S.$76.67 per barrel for oil and condensate, based on a 12-month average Brent reference price of U.S.$85.43 per barrel. Cairn supplied differentials by field to the Brent reference price, and these prices were held constant for the lives of the properties.

Natural Gas Prices

Cairn has represented that the natural gas prices are defined by contractual agreements based on specific market conditions. The volume-weighted average adjusted product price attributable to estimated proved reserves was U.S.$6.81 per thousand cubic feet. The average contract prices for each contract area were held constant for the lives of the properties.

DEGOLYER AND MACNAUGHTON

Operating Expenses and Capital Costs

Estimates of future operating expenses and capital costs were based on information provided by Cairn. This information included historical costs as well as operating expense and capital cost estimates for future development. Estimates of future operating expenses and capital costs, either higher or lower than the Cairn development plan estimates, may have been made in order to conform to the respective reserves cases.

Abandonment Costs

Abandonment cost estimates were provided by Cairn for each field or contract area and were included as capital costs through escrow payments over the life of the remaining reserves.

All cost estimates were held constant for the life of the evaluation (March 2015 terms).

Discussion of Fiscal Terms

RJ-ON-90/1 PSC (Rajasthan)

Cairn has represented that under the terms of the PSC signed with the GOI, the Contractor (Cairn and its partners) has the right to recover costs and share in the profit proceeds with the GOI. The Licensee (ONGC) pays royalties of 20 percent on the wellhead value of oil and condensate sales and 10 percent on the wellhead value of gas sales. The Contractor is liable for a production tax (termed “cess”) of Rs.4,552 per tonne of oil produced. Royalties and cess are considered allowable costs for cost recovery purposes. Profits are shared based on a sliding scale tied to the ratio of cumulative revenues divided by cumulative investments (exploration and development). Income taxes are assessable at statutory rates for domestic and foreign companies (Cairn’s interests are held by two entities: one domestic entity and one foreign entity).

DEGOLYER AND MACNAUGHTON

CB/OS-2 PSC

Cairn has represented that under the terms of the PSC signed with the GOI, the Contractor has the right to recover costs and share in the profit proceeds with the GOI. The Contractor is not responsible for royalties or cess under the terms of this contract. Profits are shared based on a sliding scale tied to the after-tax rate of return. Income taxes are assessable at statutory rates for domestic companies.

PKGM-1 License Area (Ravva)

Cairn has represented that under the terms of the PSC signed with the GOI, the Contractor has the right to recover costs and share in the profit proceeds with the GOI. The Contractor pays royalties of Rs.481 per tonne on oil sales and 10 percent on the wellhead value of gas sales. The Contractor is also liable for a cess of Rs.927 per tonne of oil produced. Royalties and cess are considered allowable costs for cost recovery purposes. Profits are shared based on a sliding scale tied to the after-tax rate of return. Income taxes are assessable at statutory rates for domestic companies.

The estimated future net revenue and present worth of the future net revenue at a discount rate of 10 percent to be derived from the proved developed and total proved net reserves evaluated herein, as of March 31, 2015, are presented below in millions of Indian rupees (MM Rs.) and millions of United States dollars (MM U.S.$):


Proved Developed				Total Proved				Proved Developed				Total Proved
Future Net Revenue (MM Rs.)		Present Worth at 10 Percent (MM Rs.)		Future Net Revenue (MM Rs.)		Present Worth at 10 Percent (MM Rs.)		Future Net Revenue (MM U.S.$)		Present Worth at 10 Percent (MM U.S.$)		Future Net Revenue (MM U.S.$)		Present Worth at 10 Percent (MM U.S.$)

	162,870		136,586		197,037		157,369		2,664		2,234		3,157		2,573

Note:

Future net revenue and present worth at 10 percent include the 41.1-percent minority share not owned by Vedanta Limited.

Standardized measure of discounted future net cash flows (SMV) and changes therein relating to proved reserves, as of March 31, 2015, are shown in Table 4. The SMV is the net present worth discounted at 10 percent.

DEGOLYER AND MACNAUGHTON

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4 through 932-235-50-9, 932-235-50-30, and 932-235-50-31 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DEGOLYER AND MACNAUGHTON

SUMMARY and CONCLUSIONS

The estimated net proved developed, proved undeveloped, and total proved oil and condensate, sales-gas, and oil equivalent reserves, as of March 31, 2015, of certain fields attributable to the interests of Cairn and located in India are summarized as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

Net Reserves

Oil and
Condensate
(MMbbl)

Sales
Gas
(Bcf)

Oil
Equivalent
(MMboe)

Proved Developed

73.94

3.55

74.53

Proved Undeveloped

16.15

1.34

16.38

Total Proved

90.09

4.89

90.91

Notes:

1.	Sales gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

2.	Net reserves include the 41.1-percent minority share not owned by Vedanta Limited.

Estimates of the present worth derived from the proved developed and total proved reserves of Cairn’s net petroleum interests, as of March 31, 2015, discounted at a rate of 10 percent and expressed in millions of Indian rupees (MM Rs.) and millions of United States dollars (MM U.S.$), are presented in the following table:


	Present Worth at 10 Percent (MM Rs.)		Present Worth at 10 Percent (MM U.S.$)

Proved Developed		136,586		2,234
Total Proved		157,369		2,573

Note:

Future net revenue and present worth at 10 percent include the 41.1-percent minority share not owned by Vedanta Limited.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the March 31, 2015, estimated oil and gas reserves.

DEGOLYER AND MACNAUGHTON

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Vedanta Limited. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

Submitted,

/s/ Degolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

SIGNED: April 24, 2015

LOGO

/s/ Thomas C. Pence, P.E.

Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton

TABLE 1

GROSS PROVED RESERVES

as of

MARCH 31,2015

for

CERTAIN FIELDS

INDIA

with interests owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED


	Gross Reserves
	Proved Developed						Proved Undeveloped						Total Proved
Area Field	Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)		Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)		Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)

CB/OS-2 PSC
CB-X		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000		0.000
Guari		0.409		0.208		0.444		0.000		0.228		0.038		0.409		0.436		0.482
Lakshmi		2.741		1.255		2.950		1.431		4.218		2.134		4.172		5.473		5.084


Total CB/OS-2 PSC		3.150		1.463		3.394		1.431		4.446		2.172		4.581		5.909		5.566

RJ-ON-90/1PSC
Aishwariya		25.795		0.000		25.795		0.000		0.000		0.000		25.795		0.000		25.795
Aishwariya - Barmer Hill		1.611		0.000		1.611		0.000		0.000		0.000		1.611		0.000		1.611
Bhagyam		17.509		0.000		17.509		0.000		0.000		0.000		17.509		0.000		17.509
Mangala		118.823		0.000		118.823		33.550		0.000		33.550		152.373		0.000		152.373
Mangala - Barmer Hill		1.822		0.000		1.822		0.000		0.000		0.000		1.822		0.000		1.822
N-E		0.484		0.000		0.484		0.000		0.000		0.000		0.484		0.000		0.484
N-I		1.176		0.000		1.176		0.000		0.000		0.000		1.176		0.000		1.176
Raagashwari (Shallow)		0.731		0.000		0.731		0.258		0.000		0.258		0.989		0.000		0.989
Raagashwari Deep		1.338		5.163		2.199		0.000		0.000		0.000		1.338		5.163		2.199
Saraswati		0.763		0.000		0.763		0.000		0.000		0.000		0.763		0.000		0.763


Total RJ-ON-90/1 PSC		170.052		5.163		170.913		33.808		0.000		33.808		203.860		5.163		204.721

PKGM-1 License Area
Ravva		13.546		8.239		14.919		0.000		0.000		0.000		13.546		8.239		14.919

Grand Total		186.748		14.865		189.226		35.239		4.446		35.980		221.987		19.311		225.206

Note:

Sales gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 2

NET PROVED RESERVES

as of

MARCH 31, 2015

for

CERTAIN AREAS

INDIA

with interests owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED


	Net Reserves
	Proved Developed						Proved Undeveloped						Total Proved
Area	Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)		Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)		Oil and Condensate (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)

CB/OS-2 PSC		0.81		0.38		0.87		0.45		1.28		0.67		1.26		1.66		1.54
RJ-ON-90/1PSC		71.45		2.26		71.83		15.70		0.06		15.71		87.15		2.32		87.54
PKGM-1 License Area		1.68		0.91		1.83		0.00		0.00		0.00		1.68		0.91		1.83


Total		73.94		3.55		74.53		16.15		1.34		16.38		90.09		4.89		90.91

Notes:

1.	Sales gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

2.	Net reserves include the 41.1-percent minority share not owned by Sesa Sterlite Ltd.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 3

RECONCILIATION of NET PROVED RESERVES

as of

MARCH 31, 2015

for

CERTAIN PROPERTIES

INDIA

with interests owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED


	Oil and Condensate (MMbbl)			Sales Gas (Bcf)			Oil Equivalent (MMboe)

Proved Developed and Undeveloped Reserves as of March 31, 2014		111.53			6.95			112.69

Revisions		7.65			1.29			7.87
Improved Recovery		0.00			0.00			0.00
Purchases or (Sales) of Minerals in Place		0.00			0.00			0.00
Extensions and Discoveries		2.28			0.16			2.31
Annual Production		(31.37	)		(3.51	)		(31.96	)

Proved Developed and Undeveloped Reserves as of March 31, 2015		90.09			4.89			90.91

Proved Developed Reserves
March 31, 2014		75.40			6.03			76.41
March 31, 2015		73.94			3.55			74.53

Notes:

1.	Sales gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

2.	Net reserves include the 41.1-percent minority share not owned by Sesa Sterlite Ltd.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 4

STANDARDIZED MEASURE of DISCOUNTED FUTURE NET CASH FLOWS and CHANGES THEREIN relating to PROVED RESERVES

as of

MARCH 31, 2015

for

CERTAIN PROPERTIES

INDIA

with interests owned by

CAIRN INDIA LIMITED

for

VEDANTA LIMITED


	Total Proved (MM Rs.)			Total Proved (MM U.S.$)

Future cash inflows		424,446			6,941
Future production costs		175,304			2,867
Future development costs		45,859			750
Future income tax expenses		10,246			168
Future net cash flows		193,037			3,157
10% annual discount for estimated timing of cash flows		(35,668	)		(583	)

Standardized measure of discounted future net cash flows		157,369			2,573

The following are the principal sources of change in the standardized measure of discounted future net cash flows during Fiscal Year 2014 (All values are in MM Rs. and U.S.$):

Standardized Measure March 31, 2014		235,486			3,851

Sales and transfers of oil and gas produced, net of production costs		(99,909	)		(1,634	)
Net changes in prices and production costs		(81,576	)		(1,334	)
Extensions, discoveries and improved recovery		5,384			88
Development costs incurred during the period		43,829			717
Revisions of previous quantity estimates		17,798			291
Change in estimated development costs		(19,292	)		(315	)
Purchase or (Sales) of Minerals in Place		0			0
Accretion of discount		28,321			463
Net change in income taxes		27,328			447
Other		0			0

Standardized Measure March 31, 2015		157,369			2,573

Note:

Values for proved net reserves include the 41.1-percent minority share not owned by Vendanta Limited.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.