1.1 In India as in the rest of the world exploration and production of hydrocarbons is
treated on a separate footing than other minerals. This difference not only pertains to the
geological occurrence and techniques for exploration and production of hydrocarbons but
also to the laws and rules applicable reckoning of levies and so on. Further, today only
hydrocarbons are explored and produced from the offshore areas in the Exclusive
Economic Zone of India, which has its own constitutional status. About one-third of the total
indigenous production is from onland areas which mostly occur in the State of Assam and
Gujarat. Royalty is the basic and most important levy on the crude oil and accrues to the
States for the onland production and to the Centre for the offshore production.
1.2 Royalty on crude oil has been fixed for last five decades in terms of the Oilfield
(Regulation and Development) Act 1948 by the Central Government on different
methodologies, which sloughed to balance the interests of the State Governments
concerned with the need to make available petroleum products at a reasonable price in the
domestic market. The latest arrangement in this regard was the Administered Price
Mechanism (APM) through which certain petroleum products were subsidized in the public
interest and a countrywide price parity maintained through higher prices for other petroleum
products and through a non-market driven price for the crude oil produced by National Oil
Companies (NOCs). The basic price of the crude oil for NOCs under the APM was fixed
based on its weighted average cost of production and a post tax return of 15% on the
capital employed which price obviously had no linkage to the international prices of crude
oil. The royalty on crude oil was fixed as a specified rate in relation to the legal provisions
and to the price paid to NCOs under the APM.
1.3 Since early Ninety’s, the ongoing economic liberalization process affected all
sectors of the Indian economy through fundamental reforms of financial sector, trade sector
and like. In the hydrocarbon sector, these reforms included entry of private/joint venture
companies in upstream and downstream sectors, empowerment of the NOCs, liberalization
of industrial licensing, lowering of customs tariff and excise duty and reduction of trade
controls. More importantly in 1997,it was decided to dismantle the APM and a detailed road-
map was notified by the Government .It was envisaged to dismantle the APM in four years
from 01-04-1998 to 31-03-2002, where-after a de-regulated scenario would prevail . In
particular, the price of crude oil payable to the NOCs was linked to an increasing
percentage of import parity price, on FOB basis, over these 4 years and a market driven
price was envisaged thereafter. Around the same time, the new Exploration Licensing
Policy (NELP ) was notified in February, 1999 which stipulated a fiscal and contractual
regime, including royalty comparable to the best worldwide and provide full freedom for
marketing crude oil and natural gas in India. The ultimate aim of these reforms was to put in
place a globally competitive policy and fiscal regime for upstream and downstream
1.4 Due to the extreme volatility of international oil prices which dropped to below
US $ 10 per barrel during 1998-99 and then zoomed up beyond US $ 30 per barrel
during 1999-00 , the road map in relation to the crude oil pricing could not be
followed . The NOCs were paid a floor price of Rs.3469 per MT and a ceiling price
of Rs.5570 per MT for most of the period. Moreover, in view of these un-
anticipated developments, adhoc revisions of royalty had to be affected .In the
mean time, the State Governments as recipients of the royalty on onland
production were pressing hard for a through revision of royalty rates because of
the dismantling of APM.
2. CONSTITUTION OF THE COMMITTEE
2.1 In view of the fundamental changes in the reckoning of the crude oil price received by the
NOCs after 01-04-1998 due to the dismantling of APM and in the context of the overall reform
process in the hydrocarbon sector; a review of the principles for royalty fixation and its
methodology was requisite . Government, therefore, vide Office Memo No. O-22013 2/98-
ONG-III dated 26-04-2000 , set up a Committee, headed by Joint Secretary (Exploration) in the
Ministry of Petroleum and Natural Gas (MOP&NG) for evolution of a new scheme of royalty on
crude oil with effect from 01-04-1998 in respect of crude oil produced by National Oil Companies
(NOCs) outside New Exploration Licensing Policy (NELP) regime. The Committee had Director
(Exploration) and Director (Finance) from the MOP&NG and a representative from Directorate
General of Hydrocarbons (DGH) as its members .Shri J.M. Masukar was Joint Secretary
(Exploration) throughout the functioning of the Committee. Shri N.K. Singh represented both
Exploration and Finance Division in the Committee by virtue of his holding the charge of the posts
of Director (F) and Director (E) in the MOP&NG. Shri R. C. Khurana, DGM was nominated as
DGH representative on the Committee.
2.2 The Committee was required by its terms of reference, inter-alia to:
“(a) Examine and review the system of levy and collection of all imposts on crude oil like royalty
and sales tax except cess keeping, inter –alia, in view the need for making heavy investments in
the oil and gas sector and reduce dependence on imports : the need to augment State
Government’s revenue ;dependence of oil PSUs on their own internal resources in absence of
any budgetary support etc.
(b) Recommend the criteria for determining Royalty on crude oil;
(c) Recommend also the royalty rate/rates and principles for periodic revision;
(d) Suggest the methodology and agency for normative pricing of crude oil;
(e) Consider any consequential amendments in the relevant Acts and Rules governing royalty
and other statutory levies excluding cess;
(f) Consider also any other item which has impact on the foregoing terms.”
2.3 The Committee was also required to examine all issues relating to royalty while
considering the views of concerned State Governments as also the views of oil and gas
producing companies in the country and international experience available in this regard.
2.4 A copy of the Government Office Memorandum consisting the Committee is placed at
Appendix-I of the Report.
3. WORKING OF THE COMMITTEE
3.1.1. During the initial proceedings, the committee finalized the methodology of its working.
The committee decided to get the inputs from all concerned including various State
Governments, especially those producing oil and gas, upstream National Oil Companies
(NOCs), viz, Oil & Natural Gas Corporation Limited (ONGC), Oil India Limited (OIL),
Planning Commission ,other organizations, namely , Oil Coordination Committee (OCC),
Federation of Indian Chambers of Commerce & Industry (FICCI), Confederation of Indian
Industry (CII), Associated Chamber of Commerce & Industry of India (ASSOCHAM), Tata
Energy Research Institute (TERI) and several ex-CMDs of ONGC, OIL and ex-
Secretaries of Petroleum & Natural Gas .The Committee decided to solicit views from the
above sources so as to take all related aspects and inputs in its consideration while
finalizing its Report.
3.1.2. For the sake of uniformity and convenience, the Committee developed five sets of
questionnaires on various issues relation to royalty fixation. These were sent to various
respondents. The first set of questionnaires was sent to all concerned. The second set of
questionnaires was meant specifically for the State Governments. The third set of
questionnaires was developed for NCOs . The fourth set of questionnaires was meant for
OCC while the fifth set was meant for Planning Commission. These sets of
questionnaires can be seen at Annexure-I of Volume-II of this report. The questionnaires
were accordingly sent to various respondents soliciting their
comments/views/suggestions in the matter.
3.1.3. The Committee received detailed inputs from State Governments of Andhra Pradesh,
Assam, Gujarat, Nagaland , Rajasthan , Tamil Nadu , Tripura , U.P & Union Territory of
Dadra & Nagar Haveli . The committee also received detailed inputs from upstream
NOCs, namely, ONGC & OIL as also from the downstream PSUs like Indian Oil
Corporation Limited (IOCL), Bharat Petroleum Corporation Limited (BPCL) and
Hindustan Petroleum Corporation Limited (HPCL). The committee also received
response from a few Ex-CMDs of ONGC & OIL and ASSOCHAM. Despite repeated
reminders, as indicated at page 9 of the Volume –II of the report, responses from others
were not received.
3.1.4. These inputs and suggestions as received from respondents are appended in Volume –
II of this report as
Annexure-I -State Governments
Annexure-III - OCC
Annexure-IV - CMDs of ONGC,OIL, ED -OCC & ASSOCHAM
3.1.5. The Committee studied the inputs from the respondents both received formally and
informally . The Committee found that respondents, especially, the major oil producing States like
Assam and Gujarat and NOCs had raised certain basic issues regarding the principles of fixation
of royalty and had given their own logic. The Committee found that many issues were concerning
economic principles governing the royalty fixation norms and thus relevant for consideration of
the Committee. The Committee, therefore, decided to get the opinion of some expert neutral
agency who could guide the Committee on relevant aspects involving economic principles.
National Institute of Public Finance & Policy (NIPFP), New Delhi which is an eminent and leading
institution, was engaged for the purpose of advising the committee. The Committee
simultaneously studied the earlier awards and the principles followed in these awards for royalty
fixation. The committee also studied the international royalty regime of various oil producing
countries including the methodology of the royalty fixation in these countries in the context of the
overall fiscal regime.
3.2. IDENTIFICATION OF ISSUES
3.2.1. After studying the inputs received from the state Governments ,NOCs, PSUs, Industry
bodies and Experts as also the Royalty Regime of various countries, the Committee identified the
following relevant issues on which it would need to give recommendations after due consideration
i) Whether the royalty on crude oil should be based on Ad valorem basis or specific rate?
ii) (a) What crude oil price should be considered for royalty determination . i.e. the sale price
including levies (like cess &royalty) or the sales price net of levies (like cess and royalty) or the
price at the well head or the import parity /international price?
(b) If crude price is to be taken at the wellhead, how would it be determined?
iii) Whether there should be differential rates of royalty, viz. different rates for onland & offshore :
different rates for various states: and reduced rates slab for incremental crude oil produced as a
result of higher investment on EORTOR projects ?
iv) Whether there should be a single royalty regime in the country in line with NELP regime and
whether rates be tapered over a given period of time to bring these at par with NELP or
v) What should be royalty rate(s)?
vi) Whether is a need for an independent agency for determination of crude oil price / well head
vii) Whether is a need for any amendment to the relevant Acts and Rules?
viii) What should be the royalty regime during the transition period of dismantling of the APM, viz.
1.4.1998 to 31.3 2002?
ix) How cess on crude oil is to be treated for the determination of royalty rates?
3.3 POST RESPONSE DELIBERATIONS
3.3.1. After studying the inputs from the respondents and the identification of issues, the
Committee held detailed discussions with NIPFP. Since some of the stakeholders had divergent
views on many of the important aspects, the Committee decided to hold meetings with all
respondents to the extent possible, in order to apprise them of each other’s view points and get
their reactions on the issues raised by various other respondents. The list of the State
Government authorities, who were contacted for the purpose as also of those with whom the
meetings of the Committee could be held, is placed at Appendix-II of this Report. After the
interactions, the Committee requested NIPFP to evaluate various economic aspects f the
principles of royalty fixation and advise the Committee on all such relevant issues having
economic and financial implications. NIPFP held detailed consultations with the Committee and
submitted their Note addressing these issues. The Committee deliberated upon the advice of
NIPFP, summarized in Section-VI of this Report, regarding all the identified issues, keeping in
mind the views of stakeholders, while finalizing its conclusions and recommendations.
3.3.2. Since its very inception and formation, the Committee held many internal meetings to
deliberate upon the inputs received form State Governments, NOCs and other concerned
sources. In particular, about 10 meetings were separately held with representatives of State
Governments. NOCs and other concerned organizations before finalizing the Report by the
Committee. The Committee also had eleven meetings with NIPFP from time to time. Two
meetings were also held to discuss the matter with senior officials of the Ministry of Petroleum &
3.3.2. In making the recommendations, the Committee had to balance firstly,the need to enhance
the revenues of the States through larger royalty accruals , secondly ,the requirement of
availability of sufficient funds with NOCs for accelerating exploration and production in the country
and thirdly to align royalty regime in India with global regimes or at least to simply the multiplicity
of royalty regimes in existence. The Committee was also guided by the need to provide practical
and implement able recommendations consistent with administrative and financial norms and with
its terms of reference. Lastly, the Committee wanted to have widest possible consultation in its
effort to give such recommendations as would find consensus with various stakeholders, a
process which has taken some time in view of the complexity of issues and divergent opinions
involved. The advice of NIPFP and the meetings held with the State Governments, NOCs and
others were indeed crucial for the Committee to attain the above objectives.
ROYALTY ON CRUDE OIL
4.1. CONSTITUTIONAL AND LEGISLATIVE PROVISIONS
4.1.1. The system of payment of royalties on minerals dates back to several centuries. In India
also, the system has been in existence for a long time. The royalty on crude oil is payable in
accordance with the constitutional and legislative provisions described hereunder:
4.1.2. Under Article 248 read with Entry 53 in List I of the Seventh Schedule of the Constitution of
India, the power of regulation and the responsibility for the developments of oil fields and mineral
oil resources are exclusively within the domain of the Union Government. The Central legislation
in this regard is “the Oilfields (Regulation and Development) Act 1948”. The “Petroleum and
Natural Gas Rules, 1959” have been framed there under. The rate of royalty is determined by the
Central Government under the provisions of Central legislation from time to time and specified in
the Schedule of the Act. Section 6-A of Oil Fields (Regulation and Development) Act, 1948
provides as under:
“6 A (I) The holder of a mining lease granted before the commencement of the Oilfields
(Regulation and Development) Amendment Act. 1969 shall notwithstanding anything contained in
the instrument of lease or in any law in force at such commencement, pay royalty in respect of
any mineral mined, quarried, excavated or collected by him from the leased area after such
commencement at the rate for the time being specified in the schedule in respect of the mineral
The holder of a mining lease granted on or after the commencement of the Oilfields (Regulation
and Development) Amendment Act,1969 shall pay royalty in respect of any mineral oil mined,
quarried, excavated or collected by him from the leased area at the rate for the time being
specified in the Schedule in respect of that mineral oil.
Notwithstanding anything contained in sub-section ( 1) or sub-section (2), no royalty shall be
payable in respect of any crude oil casing head condensate or natural gas which is unavoidably
lost or is returned to the reservoir or is used for drilling or other operations relating to the
production of the petroleum or natural gas ,or both.
The Central Government, may by notification in the Official Gazette, amend the Schedule so as to
enhance or reduce the rate at which royalty shall be payable in respect of any mineral oil with
effect from such date as may be specified in the notification and different rates may be notified in
respect of the same mineral oil mined, quarried, excavated or collected from the areas covered
by different classes of mining leases.
Provided that the Central Government shall not fix the rates of royalty in respect of any mineral
oil so as to exceed twenty per cent of the sale price of the mineral oil at the oilfields or the oil well-
head, as the case may be, or
If the Central Government, with a view to encourage exploration in offshore areas ,is satisfied that
it is necessary in the public interest so to do ,it may, by notification in the Official Gazette exempt
generally ,either absolutely or subject to such conditions ,as may be specified in the notification
,mineral oil produced from such areas from the whole or any part of the royalty leviable thereon.”
4.1.3. The Central Government thus has the powers to enhance or reduce the rate of royalty,
subject to the condition that the royalty shall not exceed 20% of the sale price of the mineral oil at
the oilfields or at the oil well-heads, as the case may be:
4.1.4. Relevant portion of Rule-14 of the P&NG Rules 1959 provides as under: “14:
Royalty on petroleum and furnishing of return and particulars: (1) (a) notwithstanding anything in
any agreement, a lease shall -
where the lease has been granted by the Central Government, pay to that Government, and
where the lease has been granted by the State Government, pay to that Government [a royalty
for the period, beginning ………….. and ending………… at the rate of ……….. per metric tonne of
crude oil and casing head condensate and at ten percent of the value at well-head of natural gas
obtained by the lease] :
Provided that the Central Government or ,as the case may be ,the same State Government with
the approval of the Central Government ,may direct that such royalty be paid in petroleum and
Provided that such royalty shall not be payable in respect of any crude oil, casing head
condensate or natural gas which is unavoidably lost or is returned to the reservoir or is used for
drilling or other operations relating to the production of petroleum or natural gas or both
(2) The lease shall, within the first seven days of every month or within such further time as [the
Central Government or the State Government, as the case may be] may allow, furnish or cause
to be furnished to the Central Government or the State Government, as the case may be] a full
and proper return showing the quantity of all crude oil, casing head condensate or natural gas
obtained during the preceding month from mining operations conducted pursuant to the lease.
The monthly return required to be furnished shall be, as nearly as may be, in the form specified in
the Schedule annexed to these rules……………….”
4.1.5. In addition, Rule 23 of the P&NG Rules, 1959 provides as under
“23 : Fees, etc., payable by the due date .-(1) All license fees ,lease fees, royalties and other
payments under these rules shall ,if not paid to [ the Central Government or the State
Government, as the case may be ] within the time specified for such payment ,be increased by
ten per centum for each month portion of a month during which such fees, royalties or other
payments remain unpaid.
(2) Subject to these rules, if any license fee, lease fee, royalty or other payment due in respect of
a license or a lease is in arrears for more than three months [the Central Government or, as the
case may be, the State government, with the prior approval of the Central Government, may]
cancel such license or lease and such cancellation shall be punished in the official Gazette and
shall take affect from the date of such publication…………”.
4.2. ROYALTY UNDER ADMINISTERED PRICE REGIME
4.2. Central Government has been fixing the specific rates of royalty on crude oil during the APM
period based on different methodologies. For example, during the period 1.4.90 to 31.3.93 royalty
was based on the crude oil price determined on the basis of weighted average cost of production
plus cess. In February 1993, royalty was accordingly notified as Rs. 481/MT for the period
1.4.1990 to 31.3. 1993. Subsequently, royalty was determined based on the weighted average
cost of the production of crude oil by ONGC and OIL plus 15% post tax return on the capital
employed. The royalty was fixed “on account” at Rs.528/MT for the period 1993-96. This was
further revised “on account” to Rs.539.80 MT. The provisional rate of royalty was thereafter
revised to Rs.578/MT w.e.f. 1.4. 1996.
4.3. MULTIPLE ROYALTY REGIMES
4.3. Currently multiple royalty regimes on crude oil prevailing in the country. The regime for
production from the areas awarded to NOCs on nomination basis is the one which is currently
under review by the Committee and wherein the specific rates of royalty are fixed by the
Government and revised periodically. Another regime is in respect of areas under Production
Sharing Contracts (PSCs) prior to NELP. In order to attract Private Indian & Foreign capital
for upstream sector in India, Government under its liberalization programme awarded
discovered fields and exploration blocks through global bidding under PSCs entered into with
the contractors. Under the PSC regime prior to NELP, fixed rates of royalty as prevailing at
the time of bidding were specified in the contracts of discovered fields for the entire contract
period in order to provide fiscal stability to the contractors. However for the discovered fields
on land, royalty is payable to the states at the rates applicable to NOC. The difference
between this and the PSC rate is to be adjusted out of the OIDB cess for some PSCs, while
for others this issue is be4ing sorted out. For offshore discovered fields, frozen royalty rate is
payable to the Central Government. In respect of the pre-NELP exploration blocks the royalty
is payable at the rates applicable to NOC .Third regime is for areas awarded under NELP ,
wherein the royalty rate o crude oil was brought at par with the international rates. The royalty
on crude oil was fixed @ 12.5% for onland crude and @10% for offshore crude with a further
concession of half the normal rate of royalty for deepwater areas (more than 400 Mts) at @
5%during the first 7 years of commercial production. Thus, multiple royalty regimes are
prevailing in the matter of royalty on the crude oil. The areas awarded on nomination basis to
NOCs and under PSCs to Private Joint Venture contractors, prior to NELP, have royalty
regimes which are different than the one under NELP. Even within NELP, there are different
rates for the crude oil production from onland, shallow off-shore and deep offshore areas.
4.4. ROYALTY UNDER APM DISMANTLING PERIOD
4.4.1 During the dismantling of APM period between April, 1998 to March 2002, the crude price
payable to producer companies has been linked with the specific percentage of weighted average
FOB price of actual imports in India. The relevant percentages envisaged in the Scheme of the
Govt., published vide Resolution No. P-20012/29/97-PP, dated 21.11.1997 in the Gazette of
India. Extraordinary was 75% for the year 1998-99, 77.5% for 1999-2000, 80% for 2000-01 and
82.5% for 2001-02. The price for crude oil was envisaged to be market driven with complete
deregulation after the completion of APM dismantling effective from 1.4.2002. The royalty on
crude oil during this transition period is being provisionally fixed based on the crude price
determined on the above principles of linkages with import parity (FOB) prices but with a floor and
upper ceiling. During the period April, 1998 to May 1999, the crude prices in the international
markets remained very soft and were the lowest in the last two decades. Under such a scenario
of falling crude oil prices in the International market, in order to protect the operational viability of
E&P operations in the country, it was decided to fix the minimum floor price for payment to NOCs
at the level of Rs. 3469 per MT inclusive of cess etc.. and the royalty was fixed at Rs 578 per MT
. The crude price however crossed the floor level for the first time in June, 1999. After June 1999,
there was extreme volatility in International market and the crude prices began to rise steeply and
an upper ceiling was fixed on the price payable to NOCs at Rs. 5570/-per MT inclusive of cess
etc. with effect from November,1999. This decision was necessitated by the need to hold down
petroleum product prices in the overall public interest. However, during this period, there were
three revisions in royalty rates on adhoc basis , subject to adjustment on the formalization of a
new scheme of royalty to be made applicable w.e.f. 1.4.1998. The adhoc rates of royalty as fixed
during the period are as under:
Date of Effective Royalty
Order Date rate/MT
2.3.1999 1.4.1996 Rs. 578 The basic price continued till May,1999.
Subject to the condition that royalty amount shall not exceed
20% of the well head value on monthly basis . The well
1.12.1999 1.6.1999 Rs. 750
head value is to be derived by deducting 10% from the
selling price received by ONGC/ OIL
2.5.2000 1.1.2000 Rs. 800 -do-
Subject to the condition that royalty amount shall not exceed
20% of the well head value on monthly basis . The well
9.8.2001 1.12.1999 Rs. 850
head value is to be derived by deducting 8% from the selling
price received by ONGC/ OIL
4.4.2. It is seen that for calculation of royalty, whether maximum of 20%under APM or adhoc
rates after 1.4.1998, the following formula is used:
Royalty amount = Well Head Price X R
This formula has been endorsed by stakeholders.
4.5. DIFFERENT METHODOLOGIES
4.5 As can be seen from the above account the royalty regimes prevailing at different times under
the APM, different principles of fixation of royalty were being followed, including fixation of rates
on adhoc basis sometimes. The crude price considered for royalty purposes was at times
inclusive of cess and sometimes exclusive, and the royalty rates are generally fixed on based on
the administered price & cess. The concept of wellhead price was not utilized apparently due to
practical difficulties since wellhead is not the point of sale in India. With the dismantling of APM
,the issue of determination of “sale price at the wellhead” has assumed significance in view of the
legal requirement that royalty payments cannot exceed 20% of the sale price at the wellhead.
4.6. GLOBAL ROYALTY REGIME
4.6.1 The Committee studied the fiscal regime of the various countries in the present context. A
table depicting Global Petroleum Fiscal Regime, including royalty regimes of various countries, is
placed at Appendix III to this report. It is seen that in most of the oil producing countries of
economic systems similar to India, the royalty rates on crude oil range between 10-20% .Royalty
rates in Asia Pacific region range between 0-15%, except Vietnam where the royalty is upto
4.6.2. After study of the fiscal system of various countries, it is noted that various levies, including
chargeable royalty, is considering imposed a number of factors. The government ‘take’ generally
is in the form of bonuses, direct state participation, income tax, dividends, additional taxes,
domestic oil supply obligations and royalty. The contractor’s ‘take’ usually includes cost recovery,
profit share and depreciation.
4.6.3. Other factor which may directly or indirectly influence the fiscal regime, including royalty, is
the perceptions of investors about the geological prospectivities of the regions. Higher
prospectivity levels would obviously mean higher expected returns on which higher royalty rates
can be charged. In countries like India, there are export restrictions on crude oil in addition due to
its being a net importer. There may also be domestic market obligation to sell the oil at a
regulated price in the country.
4.6.4. The study of the Global Royalty Regimes clearly shows that royalty rates have to be seen
in totality in conjunction with other applicable levies and taxes in order to determine the total
Government ‘take’ vis-à-vis the ‘take’ of operating contractors. The best fiscal regime, including
royalty rate, are so structured that an equitable return to the contractors is ensured along with a
reasonable take for the Government. Removal or at least reduction of such domestic restrictions
on the contractors, as result in fiscal distortion, has its own importance in determining the
attractive of the fiscal regime of any country.
4.7. IMPACT OF THE LIBERALISED ECONOMIC ENVIRONMENT
4.7.1 India is a energy deficient country and our dependence on oil has been increasing in the
last decade. We are a large importers of crude oil ,with more than two third of our requirement
today being met through imports. Under the changed scenario of liberalisation of economy,
imports are now being freely allowed . This will result in competitive oil imports by refineries,
especially those in the private sector. Since price paid for crude oil will be a key factor, refinery
margins being low. After dismantling of APM , even the public sector refineries will not be obliged
to purchase oil form NOCs.
The country has now become self-sufficient in refining capacity . Since refining of crude oil is a
capital intensive operation : with a view to attract investment both from overseas and domestic
private sector in the country in refining activities. The Government had delicensed the refining
activities in 1998. The Government also changes in the EXIM policy in 1998 to enable import of
crude by private and J.V. refineries directly under actual users condition for use in their own
refineries. This dispensation has been extended during 2001to other PSU refineries too and
crude oil imports are no longer canalised. The Government has also amended the EXIM policy
during 1999 to decanalise the exports of petroleum products, namely, petrol, diesel and Aviation
Turbine fuel in addition to decontrolled petroleum products, exports of which is already
decanalised and freed in 1998. The ban on export of crude oil, however, still continues. On the
other hand, the process of rationalisation of customs duty on import of crude oil and products is
going on for the last four years. The Excise duty rationalisation process is also parallaly going on
since 1997 which more mean a lower level of the Counter Vailing Duty (CVD). These changes
are in line with the Policy of the Government for gradual dismantling of APM by 31st March,2002.
4.7.3. The protection to domestic producers both in upstream and downstream oil/petroleum
sector is thus declining. There would be no effective tariff protection to domestic crude oil
producers, because under the WTO regime, tariffs are being rationalised and in a few years
imports including crude oil and petroleum products would attract global tariff structures. This will
result in increased competition in domestic marketing of crude oil by NOCs since exports of oil
are not likely to be allowed to be in national interest in the years to come for creating an equitable
competitive environment for NOCs. Therefore, the levies like royalty ,cess and other taxes will
need be fine tuned.
4.7.4 The National Oil Companies i.e. ONGC and OIL were to get crude oil prices linked to
import parity price after 01.04.1998 but because of high volatility of international prices this was
done within limits of the floor and the ceiling prices. ONGC has been given the 'Navratna' and OIL
the 'Mini Navratna' status with significantly enhanced powers in terms of investments and projects
approvals. Apart from this, "India Hydrocarbon Vision 2025" mandates an ambitious E&P
programme to meet the growing demands of hydrocarbons and ensure energy security for the
country. All these developments would put additional pressure on NOCs to invest more in order to
achieve the national objectives. In view of India being a oil deficit country, NOCs are obligation to
keep on producing at the optimal level, even if the international prices decline below the level
which does not offer a reasonable mark-up to them. NOCs will thus be at a paradoxical position,
the sense that while on one hand there is an obligation on their part to produce more crude oil, on
the other hand the overall protection available to them is diminishing.
4.8. SARKARIA COMMISSION'S REPORT
4.8. The matter of royalty on Minerals, including crude oil petroleum was dealt by the Sarkaria
Commission in its Report in 1998. The relevant extracts from the Report (para 10.9.39 & para
10.9.40) are reproduced below:
"A major demand of the State Government has been payment of royalty on an ad valorem basis
and not on the basis of a specific amount per tonne, especially in view of frequent and sharp
increases in the prices of many minerals and crude oil. A State Government had cited the Nehru
Award of 1962 and Indira Gandhi Award of 1968 in support of its demand that the royalty on
crude petroleum should be based on "full-posted price" rather than on an artificial selling price of
indigenous crude. On the other hand, the State Governments have levied cesses, mineral rights
tax and surcharge ,which are not uniform among the States. This is alleged to have imposed a
discriminatory burden on the prices of minerals over and above the rate of royalty."
"The question of royalty on mineral products in an area where, besides providing adequate rates
to the States , the principles of pricing policy ,the real factors behind movement international price
of crude petroleum, the implications of increase in the prices of basic inputs, etc., are to be
considered. We have dealt with these issues in our Chapter on Mines and Minerals. If there are
administrative considerations against making royalties Ad valorem, there are equity
considerations against not revising them for 3 or more years in times of persistent inflation. As
recommended therein, the review of the royalty rates on minerals should be made every two
years and well in time ,as and when they fall due . The same procedure should also apply to
royalty on petroleum and natural gas."
4.9. ELEVENTH FINANCE COMMISSION'S REPORT
4.9. Eleventh Finance commission has not made any recommendation in regard to royalty on
crude oil & natural gas in their Report except for an observation that royalties on major minerals,
crude oil & natural gas are dependent on the production and the rates fixed by the Government of
India and that to keep pace with the inflation , a growth rate of 5% has been adopted for
projecting revenues from royalties on major minerals.
4.10 SUMMING UP
4.10. The royalty regime for crude oil in India was some-what isolated from the Global Royalty
Regimes, mainly because the hydrocarbon sector was operating under a system where NOCs
were the only significant players and were being awarded acreages on the nomination basis
without any competition. With the dismantling of APM and proposed deregulation w.e.f. 1.4.2002.
the pricing structure in Indian would now be in line with the international trends. Also, after
opening of the sector for private investment and further liberalization through NELP , there would
be several major players in the upstream sector from public and private sectors. NOCs will also
get the market driven prices and face a competitive fiscal regime comparable to those prevailing
elsewhere around the globe. This levies like royalty need to be determined in this overall context
and in line with the global trends. This is all the more necessary in the interest of increased
investment by E&P companies especially for a country like India , where only about 25% of the
hydrocarbon resources have been discovered so far.
SECTION - V
5.1. STATE GOVERNMENTS
5.1.1 As mentioned earlier, the Committee wrote to various State Governments for inputs in the
form of their response to the questionnaires prepared by the Committee and also their views and
suggestions on the issues. The responses were received from the States of Gujarat, Assam,
Andhra Pradesh, Tamil Nadu, Tripura, Nagaland, Rajasthan and UP, which are reproduced in
Annexure-I of Volume-II. The Committee also benefitted from the meetings held between Chief
Ministers of Gujarat and Assam and Union Minister of Petroleum and Natural Gas where royalty
related issues figured. The main points made by various State Governments on the issues
referred are summarised below:
(i) On the issue of whether there should be specific rate or ad valorem rate of royalty, almost all
the states except Andhra Pradesh have proposed royalty rates to be fixed on ad valorem basis.
The State of Andhra Pradesh, however, has suggested specific rate of royalty.
(ii) With regard to the rate of royalty, the State of Gujarat, Assam and Rajasthan have proposed
the royalty @40% of full posted price/landed cost of imported crude (anagolous Middle East
Crude Oil). The State of Tamil Nadu has suggested royalty @25%, Andhra Pradesh has
suggested @20% of the sale price at least and Nagaland has proposed royalty @12.5% on
import parity price +5-10% "add-on" in view of their special status under Article 371-A of the
Constitution. The State of U.P. has proposed @10% of the value of the crude oil at well head.
(iii) With respect to the periodicity of revision, the States of Gujarat, Assam and Nagaland have
suggested for a revision on an annual basis wherea Andhra Pradesh and Tamil Nadu have
proposed a revision after every 2 years. The State of Rajasthan has suggested a revision after
every 4 years wherea U.P. has suggested for a revision after every 3 years or a maximum of 5
(iv) With regard to the desirability of the progressive rates of royalty, the State of Gujarat is not in
favour whereas Assam and Nagaland have supported the concept of progressive rates. The
States of Assam has said that progressive rates of riyalty are desirable and royalty should be
increased proportionately with the increase in productiion.
(v) For determining the normative price of crude oil, the States of Gujarat, Nagaland and U.P.
have preferred to have an independent agence whereas Andhra Pradesh and Rajasthan have
suggested for a Committee. The State of Assam has suggested for an independent tribunal for
the purpose, while Tamil Nadu has suggested Government control on fixation of royalty.
(vi) Regarding the issue as to whether royalty be abolished as in some other countries and the
States be compensated in some other form, say, through production sharing mechanism, non of
the States have agreed for abolition of royalty. The State of Rajasthan, however, has suggested
for consideration of a production linked upfront payment without answering specifically the
question regarding abolition of royalty.
(vii) With regard to the suggestion that royalty should be at per with NELP rates for the blocks
awarded to National Oil Companies on nomination basis, the States of Gujarat, Assam and
Rajasthan have desired to have a higher rate of royalty. The States of U.P. and Nagaland have,
however, agreed the royalty be at per with NELP rates and Tamil Nadu has desired that royalty
should be uniform, irrespective of the nature of companies, whihe hold the blocks.
(viii) Regarding the desirability of having uniform rates of royalty for all the States, the States of
Assam and Nagaland have asked for higher rates. Other States, however, have supported the
proposal of uniform royalty rates. The State of Assam has stated that Government of India has
adopted a policy of special concessions towards the State and other N.E. States with the object
of upliftment of the industrially and economically backward region of the country and has sought
special consideration for higher rates of royalty than other States. Nagaland, however, wants a
suitable "add-no" over and above the rates applicable to other States, in view its special status
under Article 371-A of the Constitution of India.
(ix) In connection with the existing provisions under the P&NG Rules 1959, the Committee
wanted to ascertain the views and suggestions of the States about the methodology for payment
of royalty in kind in view of perceived practical problems in this regard. In response, all the States
except Gujarat and Nagaland have preferred the royalty to be paid in cash. The States of Gujarat
and Nagaland have preferred remaining the option of royalty payment in kind but they did not
indicate the methodology to be adopted.
(x) The Committee sought the views of the State Governments with regard to their perception of
the well head price. The responses of various States were as follows:-
(a) Gujarat : Well Head "VALUE" has been defined as
"published price of crude oil of similar quality
worked back to well head in substantial free
market in any part of the world where such an oil
market may exist".
(b) Assam : Average posted price of Middle East Crude,
inclusive of transportation charges.
(c) Andhra Pradesh : To be worked back by deducting sales tax, from
total selling price.
(d) Tamil Nadu : Value quoted in sale bill.
(e) Nagaland : Wellhead price should be determined taking
delivery points, i.e. GGS etc, in the oil field
making adjustments for the transportation cost
after making a parity with import price.
(xi) Regarding the provisions under P&NG Rules, 1959 relating to late payment of royalty etc,
being equitable and whether they be linked to payment of interest, the States of Gujarat and
Tamil Nadu have replied in affirmative. The State of Assam, in addition to increase by 10%, has
suggested further interest levy for delayed arrear payments due to the delay in fixing royalty. The
States of Nagaland and U.P. have suggested that the late payment be linked with payment of
(xii) In response to a query regarding the basis of royalty on other minerals, the States have
responded as under:
(a) Assam: Royalty is levied on the basis of notification by the Government of India from time to
(b) Gujarat: Rates of royalty for major minerals are decided by Government of India. For minor
minerals, State Government decides the royalty rates. For this Gujarat Minor Minerals Rule
(1966) has been amended in 1944 and recently in 1999. The basis for rates are in the Existing
rates of royalty, the Quantity of mineral excavated, the Supply and demand of minerals, the Pit
mouth sale of minerals, the Market value of end products, the Importance of particular minerals in
particular industry, the Comparison of royalty rates for neighbouring State and other States and
the dtae of last revision.
(c) Rajasthan: Royalty is increased by 20-25% for minor minerals every 3 years. This is due to
increase in the sale of minerals by the lessee due to inter-alia to inflation and higher cost of
(d) Tamil Nadu: The rates of royalties for other minerals are previously (once in three years)
revised and fixed by Government of India on all India basis and being collected as per II Schedule
of Mines and Minerals (Development and Regulation) Act, 1957. For minerals such as garnet,
magnese. etc., the royalty is fixed as 3% Ad valorem basis. The rate is reckoned based on the
sale price of the minerals or as mentioned in their text returns.
5.1.2. States of Gujarat, Rajasthan and Tamil Nadu have suggested amendments in Oil Field
(Regulation & Development) Act, 1948, especially with regard to removal of 29% ceiling of royalty
provided in Section 6A. The State of Gujarat has however suggested for few other amendments
in the Act as also the P%NG Rules, 1959, not directly related to the royalty on crude oil.
5.1.3 Some of the States have given their views on Oil Industry Development (OID) cess on
crude oil as under:
(a) Andhra Pradesh: The OID cess should be reduced without affecting the royalty component of
the State. A part of the amount should be spent for creation for infrastructural facilities for various
oil fields in the country.
(b) Gujarat: Cess was originally envisaged to be levied on crude oil to create a fund by
Government of India for investing in new exploration areas. However, this objective has never
been realized and the amount collected by Government of India has been used as a normal
budgetary resource to meet its annual expenses. Though levy of cess is abolished in New policy,
many PSC's have been signed prior to 1999 for exploration and production of crude oil in India.
These PSC's have still to pay cess @ Rs.900 per tonne which amounts to almost US $3 per
barrel of crude oil produced. Most of the prospective areas in India are relatively small sized and
hence need financial incentives to make their operations viable. If cess on crude oil produced
from such areas is abolished then it would improve economics of oil production from small
structures and there-by enhance indigenous availability of crude oil. Accordingly all PSC's
producing crude oil less than 1000 barrel per day production rate should be exempted from
payment of cess.
(c) Nagaland: A share in OID cess in addition to 'add-on' royalty be given to the State in view of
its special Constitutional status.
5.2 NATIONAL OIL COMPANIES AND OTHERS
The Committee received the views of the two main upstream National Oil Companies as also
OCC. Downstream PSL's. ASSOCHAM etc. These views/suggestions are summarized below:
On the issue of fixation of royalty on Ad valorem basis or specific rate, both ONGC and OIL have
supported the concept of Ad valorem rates instead of specific rate. They have stated that
internationally, the royalty is fixed on Ad valorem basis and under NELP also royalty has been
fixed on Ad valorem basis. Such fixation is also favoured in view of the fact that royalty is
automatically linked to quality of crude oil as well as premiums and discounts and also eliminates
the need for periodic revisions. Lastly, in case of a sudden fall in crude oil prices with a specific
rate of royalty in the deregulated scenario, a violation of the ceiling of 29% stipulated under the
Act. 1948 may take place.
Regarding royalty rates, both ONGC and OIL have both favoured NELP rates since higher rates
for NOC's affect their competitiveness vis-a-vis the international companies.
With regard to the periodicity of revision, NOC's have opined that there may not be such a need
in case of fixation of royalty on Ad valorem basis. However, this may not be always true. Most of
the oil fields of NOC's are on deeling stage. There is a need to infuse large amount of capital
even for maintaining production from these fields. Continuance of production from some of these
fields will become economically unviable in due course of time, when there may be a need to
review the royalty rate in respect of such fields to encourage NOC's to continue production from
these fields by Enhanced Oil Recovery/Improved Oil Recovery schemes in the national interest.
NOC's therefore, want that the policy on royalty may be framed in a way so as to provide for
review of the rates of royalty in such cases.
Regarding methodology for fixation of crude price for royalty, NOC's have stated that the sale
price at the wellhead, as calculated backwards from the price at the sale point, should be
considered since crude oil is not sold at the wellhead unless it is processed and water along other
impurities is taken out. Due to the likely disputes on the working regarding post wellhead cost and
returns, it has been suggested to provide a specified percentage for deduction towards post
wellhead cost and returns. For firming up this percentage, consideration of the past relevant cost
data has been suggested.
NOCs desire the OID cess amount to be excluded from the sale price of crude oil at the wellhead,
since this being a Government levy cannot be considered as cost of production. Further, since
royalty is payable at the sale value at wellhead and cess is payable on the basis of the
acknowledged quantity which is post wellhead figure cess should be deducted from the sale
value of crude to determine the wellhead price, according to them.
NOCs request that the amount of royalty on crude oil may be deducted from the sale price of
crude for working out the sale price at the wellhead.
Regarding an independent agency for determining normative price of cruide, NOCs have stated
that there is no need for such an agency established system during the phased deregulation
period. After complete deregulation, price in any case will be fully market driven.
With regard to desirability of progressive rates of royalty, NOCs have stated that this may not be
advisable as this will lead to differential rates of royalty. On the question of abolition of royalty,
NOCs have not favoured this due to different fiscal systems and overall tax structure in India.
They have however suggested that there should be parity in determination of royalty in India so
that no single oil producer is at a disadvantageous position compared to other producers in the
NOCs have also pleaded for uniform rates of royalty at par with NELP on the following grounds:
(a) NOCs have created knowledge base in the field of Exploration & Production (E&P) in the
country and have helped to create adequate infrastructure in the country for overall development
by hydrocarbon industry. With the support by NOCs, ancillary and other associated E&P service
industry has grown up thus accelerating industrialisation and and generation of employment
opportunities in the country. For continuous generation of E&P data and support by NOCs to the
ancillary and E&P service industry, it is imperative that the fiscal system applicable to NOCs
should be more favourable than the system applicable to NELP blocks or atleast at par with them.
(b) While it is true that the NOCs were either given blocks on a nomination basis, it is also equally
true that the prices paid to them for crude oil were far less than the prevailing international prices:
for example there was no increase in the basic price of crude oil for a period of more than 11
years, between July 1981 and September, 1992. The existing fields of NOCs are fast depleting
and need added efforts and substantial investments to maintain the existing level of production
and moreover the available exploratory pursuits are highly probabilistic and un-predicable.
(c) In the past, NOCs wer asked to continue the exploration activities in various States even
though there were no great promises of hydrocarbon finds in those fields, due to various reasons.
This has also resulted in extra efforts and cost without corresponding benefits to NOCs. This also
resulted in generation of employment opportunities in the States concerned and development of
ancillary and E&P service industry therein thus increasing their pace of industrial activities. The
NOC activities have already benefited the States, therefore.
NOCs have favoured the payment of royalty in case instead of kind.
The NOC perception of wellhead price is given below:
ONGC : To be worked back from sale price by deducting all post wellhead costs
and associated returns.
OIL : Price Ex-wellhead to be derived after deducting operating cost including
transportation and return on capital employed beyond the wellhead to offtake point.
6. INPUTS FROM NATIONAL INSTITUTE OF PUBLIC FINANCE & POLICY (NIPFP)
6.1 As mentioned in Section-III of this Report, NIPFP was engaged for advising the Committee
on various issues, especially with regard to the economic principles involved therein. A copy of
their detailed Note can be seen at Annexure V of Volume-II of this Report . Observations of
NIPFP together with suggestions on various aspects given in their Note are summarised below:
6.2 ECONOMICS OF ROYALTY
6.2.1 BASIC PRINCIPLES
6.2.1 The owner of a piece of land has many ways of utilising the property for generating
income. First, the land can be sold outright and the sale proceeds can be invested in profitable
ventures, including lending the proceeds in the market, to generate income. Second, the owner
can use the land for production on own account, for example, in farming to generate income.
Third, he/she can get into a profit or out-put sharing arrangement with another firm or individual(s)
whereby the latter organizes the production activity and the land owner gets a share of the profit
6.2.2 Royalty is associated with an arrangement of the third type. There are three factors that
further complicate the case of royalty for minerals. First, there is the question of mineral being a
wasting resource. The firm getting the contract for mining the mineral depletes the resource in the
process of mining. Second, how much resource is underneath as well as its quality are not known
with certainty. The cost of prospecting, exploration, and mining is borne by the lessee firm while
the land owner gets a share of the output or profit. Third, there is the problem of asymmetric
information. The owner and the lessee may not - and often do not - have the same information
about the true worth of a mining site. While the owner leasing out a piece of land for mining would
like to believe or posture that it is very promising prospect, the lessee would like to do just the
opposite. All these issues are pertinent in the economics of royalty and are discussed in the note
of NIPFP as under:
6.3 WASTING RESOURCE
6.3 In the context of petroleum (or any other mineral), one of the concerns of State
governments is that it is a non-renewable resource, and royalty to the States is a reward to them
for the use of a wasting resource. Economists such as Hotelling (1931), Solow (1974), and
Dasgupta and Heal (1979) have analysed the consequences of exhaustion of natural resources
on inter-generational equity and appropriate policies. According to the principle provided by
Hotelling (1931) that ruled the discussion on the issue of inter-temporal equity in mineral
extraction for a long time, to a large extent market forces can take care of the problem. Extraction
of a mineral declines and the price goes up automatically as more and more of it is depleted.
What is important is the relationship between the current price of a mineral, its future price and
the rate of interest. Mining entrepreneurs have the option of extracting the mineral now, selling it
and holding the proceeds to earn interest, then it pays to conserve the mineral. Less of a mineral
would be extracted today, if the expected rate of growth of price exceeds the rate of interest. No
mineral is ever completely exhausted under the Hotelling Rule. Royalty based on the ad valorem
principle, under the Hotelling Rule, takes care of the exhaustible nature of the resource. Dasgupta
and Heal (1979) investigated the conditions under which a market system allocates exhaustible
resources in such a manner that the marginal social value of a resource is equal in all uses and is
constant over time so that the benefits accruing from its use are maximized. They came to the
conclusion that the exhaustible resource allocation will be optimal only under the following
conditions: (a) perfect competition, (b) no externalities, (c) no non-convexities in either production
possibility sets or preferences, and (d) existence of 'forward markets'. The nature of pricing and
market regulation in hydrocarbon in the past violated the tenets of perfect competition.
6.4 RISK SHARING MECHANISM
6.4 One of the alternatives to charging a royalty is to sell the oil fields through auction to the
highest bidder. The problem comes with uncertainty and asymmetric information. Neither the
explorer nor the government knows for certain how much oil can be extracted from a particular
field. Furthermore, the explorer may know more about the true worth of the field than the
government. In an auction of oil rights to government-owned land, the government can observe
ex-post, how much oil is actually extracted; this provides additional information on the true value
of the tract. The government thus benefits from auctioning the field with a stipulated royalty
payment. The total payment depends on not only the bid but also some additional information on
the winner's valuation. The payment by the successful bidder equals the amount she bids plus a
royalty based on the amount of oil extracted. Making payments conditional on ex post
observations of valuations serves not only to stimulate bidding competition: it also shifts risk from
the bidders to the seller. If the bidders are risk-adverse while the seller is risk-neutral, then some
amount of risk-shifting is mutually beneficial. The more risk-adverse the bidders are relative to the
seller, the higher is the optimal royalty rate. When there are uncertainties with respect to prices as
well, only an ad valorem royalty shares such risks. Cost-related risks are shared when either
royalty based on price net of some concept of cost is used, or 'profit-sharing' is introduced into the
6.5 DIVIDING OIL REVENUES
6.5 Given that the States issue the licenses for oil exploration or are the lessors of onshore
oilfields, it is useful to ask the question as to what would the State have done if there were no
Central government to regulate the issue of royalty. The logic of risk-sharing suggests that even
without regulatory control of the Central government, the States would have gone in for
auctioning of the oil fields with a low royalty rate due to limited number of bidders and risk-
neutrality with of the public sector oil companies. The optimal royalty rate is considerably difficulty
to calculate and depends on the number of bidders and their degree of risk-aversion. Also, it is
important to note the regressive nature of flat-rate royalty that is specified not as a proportion of
the netback but as a proportion of value of gross output of crude. It can deter marginal
investments, as it is not sensitive to variations in project costs and profitability. This is particularly
relevant for oil wells where extraction has to poor recovery rates.
6.5.2 An alternative way of looking at royalty is through the economic cost of crude oil. The
economic cost of crude oil has three components, the average incremental cost of production, the
risk premium and depletion premium. The risk premium is to enable the producer to recover the
expenses of unsuccessful exploration efforts. The premium can be paid to the producer through a
higher rate of return than the normal rate in successful explorations. The depletion premium is
intended to compensate the owner of the resource for the benefit foregone in the future due to the
present consumption of an exhaustible resource. A crucial question that arises in this context is
how to divide the economic benefit to the country in terms of the difference between the import
parity price of crude and the economic cost of producing and transporting it.
6.6 A HOLISTIC VIEW OF ROYALTY WITH OTHER TAXES AND LEVIES
6.6.1 The question of what should be the precise royalty rate is not only difficult to answer, but
should include considerations such as other taxes and the federal set-up. The Government's take
from the oil-producer in the form of indirect taxes includes not only royalty but also various taxes
and other levies. Prominent among these are Union excise and customs duty, sales tax, and OID
cess, apart from participation by the governments in production. Analysis of royalty in isolation
from the total fiscal package is not wholly meaningful. In the oil sector, royalty has to combine
with the other elements of the fiscal regime to promote the best economic utilisation of the oil
reserves and yield a reasonable take of project case flows for the governments at the Central and
the State levels.
6.6.2 The oil sector has been a major source of revenue for the Centre as well as the State
Governments. The Centre mobilised as much as Rs. 32.645 crore (Table-1) of the tax revenue
from the sector in 1999-00. while the States got Rs.18.106 crore (Table-II) in the same year.
Going by the figures given in Table-I, II & III, royalty constituted only around 4 per cent of the total
revenues of the Central Government as well as State governments. A government with conferred
rights over resources can capture resources from mining either through royalty or through taxes.
There is an important interrelation between royalty and taxes, and royalty should be seen in
conjunction with taxes.
Table I : Revenue of the Central government: 1980-01
Total customs and Union From petroleum sector
excise duties from all Ratio of revenue
Year Union excise
commodities (including Customs duty OID cess Total from petroleum and
OID cess) total revenue (%)
1980-81 9.909 .354 1.158 .60 1.572 15.9
1990-91 45.158 3.701 2.693 2.785 9.179 20.3
1995-96 75.944 8.453 4.339 2.820 15.612 20.6
1996-97 87.859 12.417 6.518 2.558 21.493 24.5
1997-98 88.155 10.026 8.416 2.529 20.971 23.8
1998-99 93.914 8.019 10.860 2.634 21.513 22.9
1999-00 108.800 12.460 16.942 3.243 32.645 30.0
2000-01 123.000 11.014 12.314 2.839 26.167 21.3
Table II: State-wise sales tax payments (inclusive of MSY and CST) on crude oil condensates,
natural gas & petroleum products made by the oil companies to Sates/UT governments: 1999-00.
Year/State 1990-91 1991-92 1992-93 1993-94 1994-95 1995-96 1996-97 1997-98 1998-99 1999-00
Andhra Pradesh 259.62 381.29 430.53 533.49 630.62 746.56 909.29 1154.79
1.14 0.13 0.50 0.69 0.41 0.23 0.32 0.31
Assam 86.92 100.73 108.29 122.83 137.32 148.48 202.94 197.13
Gujarat 556.63 727.05 859.65 879.26 1023.44 1135.51 1531.34 1814.76
Maharasthra 741.06 918.29 1060.65 1145.64 1464.71 1568.64 1822.53
Nagaland 1.56 1.07 1.25 1.71 1.61 1.55 2.22
Tamil Nadu 397.24 520.50 614.19 736.48 814.59 937.84 1181.32
Sub-Total 2934.59 2649.36 3075.06 3420.10 4072.70 4538.81 5649.96
Bihar 112.39 161.22 182.58 199.66 228.18 251.81 294.97
Haryana 45.84 61.23 68.74 83.39 94.88 104.02 184.69
Karnataka 218.01 309.30 354.26 444.52 493.46 601.35 772.74
Kerala 275.12 305.18 397.08 415.40 456.93 567.91 707.80
131.68 187.84 208.24 243.64 313.65 361.78 453.78
Orissa 39.58 55.40 65.53 82.72 100.03 118.02 149.74
Punjab 63.26 80.59 92.21 104.87 108.34 138.45 172.63
Rajasthan 135.08 171.36 220.33 249.63 302.36 367.67 445.95
Uttar Pradesh 289.95 363.39 403.87 461.52 555.40 669.92 851.41
West Bengal 189.91 236.71 294.52 342.94 391.83 391.32 478.67
117.80 145.54 178.15 225.89 268.28 361.23 446.40
Sub-Total 1618.62 2077.76 2469.51 2854.18 3313.34 3933.48 4958.78
Total 3653.21 4727.12 5540.57 6274.28 7386.04 8472.29 10608.74
6.6.3 The concurrent operation of the Centre and the States over oil through the accepted
claims of the States to issue licenses or sign leases for exploration exploitation of oil reserves
within their jurisdiction and the regulatory role of the Centre is another source of complication.
There is a similar problem in the case of major minerals, but the Constitution of India itself
stipulates a greater role of the Centre in the regulation of petroleum by assigning it to the Union
List without any qualifications. While regulation of other minerals is under the Centre only "to the
extent to which such development and regulation under the control of the Union is declared by
Parliament by law to be expedient in the public interest". The role of the Centre was envisaged as
a neutral arbitrator between the oil companies and the State governments. But, because of the
Central policy of subsidising certain petroleum products like high speed diesel, kerosene and
liquid petroleum gas and because of the Center's involvement in exploration, production and
processing of crude oil through Central public sector enterprises, the Centre has become a player
as well as an umpire. Inability to resolve the conflict of interest in the role of the Centre as a
regulator of royalty can be a serious source of strain in Centre-State fiscal relations, as partly
evident from the case of Assam.
6.7 OIL INDUSTRY DEVELOPMENT CESS
6.7.1 Among the items of revenue from petroleum for the Centre, OID cess is an important
component. Around 10 per cent of such revenues now accure from the cess. Furthermore, unlike
other taxes such as Union excise and personal income tax that were shared with the States as
per the Finance Commission awards (the entire tax revenue of the Centre is now shareable), the
OID cess was (and is) not shared.
6.7.2 A cess has been levied on indigenous crude by the OID Act.1974. Initially, the cess was at
the rate of Rs.60 PMT. Over the years, this has increased to Rs.900 PMT. Originally intended to
finance the oil sector's developmental activities, the cess has become a mojor source of net
revenue for the Government. The oil industry has received negligible amounts out of the
collection. Until 1999-00, total net cess collection was Rs.36,oi11 crore, out of which only Rs.902
crore, equivalent to 2.05 per cent, had been transferred to OID Board.
6.7.3 The OID Act.1974 empowered the Central government to levy "as a cess on crude oil and
natural gas, a duty of Union excise". Under the Act "oil industry" includes all activities by way of
prospecting or exploring for or production of mineral oil, refining, processing, transportation,
storage, handling, and marketing of all products, dowstream of an oil refinery and the production
of fertilisers and petrochemicals and all activities directly or indirectly connected therewith. Unlike
in the case of royalty, there is no minimum interval for the revision of the OID cess. The cess
applies as soon as the producer removes the oil to a refinery. Although an OID board was
constituted under the Act, the revenue from the cess is first credited to the Consolidated Fund of
India. Under Section 16 of the Act, the proceeds from the cess are to be utilised, including
transfer to the OID board, through appropriations approved by the Parliament. Because of the
very broad definition of what the proceeds can be used for, there are virtually no restrictions on
the utilisation of the proceeds and these can be used for grants and loans for various purposes.
The proceeds from the cess, and grants and loans appropriated by Parliament, are credited to the
OID Fund. As a percentage of basic crude prices, cess and royalty work out to a very high figure
of 45 per cent in India in recent times.
6.8 ROYALTIES ON THE OTHER MINERALS IN INDIA
6.8.1 Non-oil minerals in India are categorised through the amendments of Schedule of the
MMRD Act.1957 as (a) Major minerals and (b) Minor minerals, such as limestone, sand, marble,
etc., according to their national importance. While the Centre regulates the exploitation and
royalty fixation on major minerals, the States have the claim on the royalty accruals thereof. On
the other hand, the right of regulation and fixation of royalty is solely vested with the State
governments with regard to minor minerals. Royalties on major minerals are imposed under
Section 9 of the MMRD Act.1957 (Amended as MMDR Act in 1999).
6.8.2 The trend of royalty regime is of shifting from specific rate to ad valorem basis in each rate
revision. Whereas in 1995, only items like diamond, gold, precious and semi-precious stone and
residual items were on ad valorem rated, in the revision of 1997, 18 more items were included. In
its latest round of revision of September 12, 2002, the shift to ad valorem basis has been more
pronounced. Out of the 51 listed major minerals, the levy on 36 items is on ad valorem basis.
Such items are, for example, agate, cadmium, copper, diamond, garnet, gold, gypsum,
manganese ore, nickel, zinc, etc., including residual minerals. The specific rate system is retained
for asbestos, china clay, dolomite, graphite, iron ore, etc. The royalty rates for major minerals are
revised once for a 3-year period by Central government notification. The basis of calculating the
royalty is the pits mouth value (PMV) of the mineral, that is, the highest price at which the mineral
can be sold at the mine. If there is no actual local market, then the national PMV is considered.
To arrive at the basis of royalty, i.e., PMV, the following items are to be taken into account for
deduction -- partially or wholly -- from the market price for computation of the gross cost of
Exploration, Mining, Beneficiation.
Depreciation, Interest, Royalty, Taxes, Dead rent, Packing charges, R&D expenditure.
6.8.3 While the above list does provide some indication as to the information that may be useful
in the derivation of the wellhead price in the case of petroleum crude, it also indicates the
complexities involved in a full-blown derivation of the wellhead price from a reference price even
when all the necessary information in adequate detail is available. The major difficulty relates to
the allocation of overhead costs between deductible and non-deductible categories.
6.9 FISCAL SIGNIFICANCE OF ROYALTY
6.9 while appreciating the fiscal significance of royalty in State's revenues, NIPFP have
observed that States derived royalty of Rs.779 crore from crude oil in 1999-00 (Table-III). The
contribution from royalty is significant only in Assam and Gujarat among all oil-producing States,
and even in these two States the relative contribution of royalty on crude has been on the decline
(Table-IV). In Assam, the contribution from royalty in total own non-taxes slumped by 19
percentage points in three years from 83 per cent in 1996-97 to 64.1 per cent in 1998-99,
whereas in Gujarat it fell by 9 percentage points from 22.2 per cent in 1996-97 to 13.61 per cent
in 1998-99. It may be noted that non-tax revenues have been failing steadily in the lat two
decades as a proportion of own revenue collections of the States, and thus the share of royalty in
total revenues has dwindled even more sharply in total own revenues of the States than is
indicated above. Fiscal significance of this source of revenue is marginal in other oil-producing
States, namely, Andhra Pradesh and Tamil Nadu. It is also interesting to note that there has been
a marginal decline in the share of the Centre in total royalty: it declined from almost 64 per cent in
1997-98 to 62 per cent in 1999-00.
Table: III India: Royalty paid by oil-producers to different States: 1997-00
Year Gujarat Assam Arunachal TamilNadu Centre Total share in total
1997-98 340.83 10.45 0.00 3.69 18.54 473.51 1525.96 68.97
1998-99 331.16 100.20 0.00 4.92 20.99 457.27 961.20 1418.47 67.76
1999-00 403.83 123.99 0.00 9.73 26.59 564.14 1100.55 1664.69 66.11
Producer: Private and Joint-ventures
1997-98 1.27 0.00 0.70 0.00 0.00 1.97 105.28 107.25 98.16
1998-99 1.40 0.00 2.32 0.00 0.00 3.72 120.64 124.36 97.01
1999-00 1.68 0.00 2.98 0.00 0.00 4.66 171.20 175.86 97.35
Producer: Oil India Limited
1997-98 0.00 169.48 1.26 0.00 0.00 170.74 0.00 170.74 0.00
1998-99 0.00 180.45 1.16 0.00 0.00 181.61 0.00 181.61 0.00
1999-00 0.00 208.73 1.51 0.00 0.00 210.24 0.00 210.24 0.00
Total of three producers
1997-98 342.10 279.93 1.96 3.69 18.54 646.22 1157.73 1803.95 64.18
1998-99 332.56 280.65 3.48 4.92 20.99 642.60 1081.84 1724.44 62.74
1999-00 405.51 332.72 4.49 9.73 26.59 779.04 1271.75 2050.79 62.01
Note: Nil figures may indicate absence of data/information
Table IV: India: Fiscal significance of royalty from oil and natural gas in major oil-
State Share of royalty in 1996-97 1997-98 1998-99
Own non-taxes 0.90 1.20 1.30
Andhra Pradesh Total own resources 0.21 0.24 0.24
Total receipts 0.12 0.15 0.16
Own non-taxes 83.0 75.0 64.10
Assam Total own resources 24.55 22.64 20.18
Total receipts 6.93 6.61 6.43
Own non-taxes 22.20 15.09 13.61
Gujarat Total own resources 4.57 3.80 3.63
Total receipts 3.61 3.01 2.95
Own non-taxes 0.00 0.10 0.10
Rajasthan Total own resources 0.00 0.02 0.02
Total receipts 0.00 0.01 0.01
Own non-taxes 2.20 1.70 1.90
Tamil Nadu Total own resources 0.22 0.20 0.20
Total receipts 0.14 0.14 0.15
Note: Total receipts include state's own resources from tax and non-tax receipts, as well as State's share in central taxes
6.10 DIFFERING PERSPECTIVES
6.10.1 NIPFP considered the responses from the stakeholders and their views on issues like
merits of specific versus ad valorem royalty, methodology of determining royalty, including
calculation of of the wellhead value and the royalty rate, whether there should be an independent
agency to determine the 'normative' price of crude oil, royalty should be substituted by
production-sharing method and paid in price rather than cash, whether royalty should vary from
State to State and field to field, what should be the periodicity of royalty revision, and what
measures should be implemented to promote exploration and production. While there are
similarities among the responses, the perspectives often differed among the respondents.
6.10.2 On the most basic question of whether the royalty system should be abolished
altogether, all respondents were unanimous about the desirability of its continuation. In addition,
some States like Nagaland and Gujarat preferred profit-sharing. Considering the economic logic,
financial implication and the views of the stakeholders NIPFP have given their views and
suggestions on the following aspects:
6.11 SPECIFIC VERSUS AD VALOREM
6.11.1 The royalty on crude oil so far has been on a specific basis, that is, so many rupees per
MT. This specific rate necessitated a periodic review of royalty to ensure compliance with Oilfields
(Regulation and Development) Act.1948 (ORDA) wherein it is specified that the rate of royalty
cannot exceed 20 per cent of the wellhead value. While the rate could not be revised more than
once every three years, the administered price regime in petroleum gave an additional lever by
which the Central government could ensure compliance of the specific rate with the rate ceiling of
the ORDA. Administered price insulated the system from large fluctuations in the international
price of oil automatically affecting royalties.
6.11.2 According to NIPFP, there is merit in making these levies ad valorem to link inflows to the
Government and outflows from the operators dependent on the price of crude that fluctuates with
market conditions. Both specific and ad valorem levies of royalty can be observed in various
countries, with flat rate royalties usually ranging between 10 and 20 per cent, although the rate for
new contracts are typically around 10 per cent or less.
6.11.3 There appears to be considerable in choosing an ad valorem rather than a specific rate of
royalty. An ad valorem rate provides an efficient way of sharing the risks and rewards between
the oil producers and the deemed owner of the land on which the field is situated. With specific
rate, unless the rate is revised every time price of crude increases significantly, the recipient of
the royalty loses the proper share of the gains. ON the other hand, unless the gain is revised
down every time the price of crude declines significantly, it squeezes the producer's margin and
can act as a disincentive for economically viable marginal fields to continue production. Frequent
changes in royalty on the other hand are administratively clumsy and inconvenient. The fixation of
royalty as a proportion (that is on ad valorem basis) of the price obtained by the domestic
producers (adjusted for post-wellhead costs) and deregulation of the price will remove the
necessity of revising the royalty rate every third year. Certainly regarding the obligation of oil
producers is important for stimulating investment in oil exploration and development. Fixing an ad
valorem rate and deregulating the price of oil will provide this element of certainty.
6.11.4. NIPFP have opined that an ad valorem rate would be preferable to a specific rate as the
former is linked to actual price and would not increase the risk for the producer.
6.12 PRICE OF OIL ROYALTY FIXATION :
6.12.1 According to NIPFP, royalty is a return to the owners of land . It is only natural that this
return should depend upon the price of oil in case of crude oil . Royalty fixation requires the
rationalisation of pricing of oil and moving to market determined prices. Crude oil being a largely
imported energy resource of the country, the international price of this resource should be taken
as the basis for estimation of royalty as this would reflect the offer price of oil by the consumer in
an open market.
6.12.2 According to NIPFP, there appears to be some evidence that the administered price
regime, with its complex system of cross-subsidisation of petroleum products, has coincided with
and led to a slowdown in domestic investment in and production of crude oil and has resulted in
an accumulation of a large deficit in the oil pool account because of infrequent revisions in
product prices in line with international developments. The administered regime has a natural
tendency to lead to rigidities in the prices themselves. It breeds inefficiencies, erodes incentives
for promoting efficient operations and fails to deliver the benefits to the intended beneficiaries.
The price of crude receivable by the domestic producers should be deregulated and the
producers should obtain market price that would be close to the f.o.b. value.
6.12.3. The move from an administered regime to market determined prices in April 2002 will
remove a great source of ambiguity and tension between the Centre and the States in the context
of crude oil . From April 1, 2002., after deregulation, the market price for crude received by
producer adjusted for transportation cost and cost of collection ( that is, the wellhead price)
should be the basis of royalty. The litmus test for 'market price' should be the price determined by
an arm's length relationship. Any dispute regarding the nature of the arm's length relationship (for
example, when crude is sold to a subsidiary of the producer) can be adjudicated by the regulator.
Alternatively, in case determination of arm's length transaction prices proves to be difficult, import
parity prices may be considered.
6.13 TRANSITION PERIOD - APRIL 1998 TO MARCH 2002
6.13.1 The critical question is about the transition until April 1, 2002. According to the Expert
Technical Group o transition from the administered regime to market-based system, the price of
crude oil should have been revised upwards to 75 per cent, 77.5 per cent, 80 per cent and 82.5
per cent of the f.o.b. price during 1998-99,1999-2000,2000-01 and 2001-02. However, this
timetable has not been adhered to and how the transition will be managed is far from clear. With
effect from April 1.1998,the price of crude payable to these companies has been linked to the
weighted average free on board (f.o.b.) price of imported crude. But with considerable volatility in
the price of crude, when the when the f.o.b. price went down rapidly, this market-related price,
which fixed on a monthly basis, was subject to a floor of Rs.1,991 per MT. Symmetrically, when
the international price went up with effect from January 2000, the market- related price was
subject to a ceiling of Rs.5,570 per MT. Thus, while the price of crude receivable by the domestic
producers should have been 82.5 per cent of the f.o.b. value, it is currently only 57 of the f.o.b.
6.13.2 It is difficult to justify why oil-producing States should be bearing the burden of the
subsidies in petroleum in the form of reduced royalties. At the same time, oil companies cannot
pay royalty as a proportion of the import parity price when they do not receive the same. Thus, a
via-media needs to be worked out. The royalty payable to the States ought to be on the basis of
75 per cent of f.o.b. value in 1998-99, 77.5 per cent of of f.o.b. value in 1999-2000, 80 per cent of
f.o.b. value in2000-01 and 82.5 per cent of f.o.b. value in 2001-02 without any floor or ceiling of
Rs.1,991 per MT and Rs.5,570 per MT respectively. At the same time, the crude producers ought
to pay royalty on the basis of actual price they received . Using the method of computing royalty
recommended here, rough calculations show that there may be some refunds due from the
States to the producers for the year 1998-99, while some more royalty may become due to States
for the subsequent three years. These would cancel out to some extent. NIPFP's rough
calculations indicate that the net effect for the transition four year period will mean additional
payments to States. They have suggested that NOCs may not be asked to pay this amount and
Government may have to find a way to deal with the issue without passing on the burden of this
additional amount to NOCs who have not received this notional price that gives rise to this
6.13.3 It is important to note that after deregulation the price for crude will be determined by the
interplay of market forces and will tend to be at par with import-parity. The refineries will not be
willing to pay any price more than the average posted price of analogous crude inclusive of the
transportation charges not only to Indian port but also to the refinery where the oil is being
refined. On the other hand, the crude oil producers will not be willing to accept any price less than
the average posted price of analogous crude less the transportation charges to the Indian port.
Thus, post-deregulation, the price of crude will between the f.o.b. price and the c.i.f price of crude
in the international market. where exactly it will settle will depend on the demand and supply
factors. There does not appear to be any justification for taking the wellhead price as the average
posted price of analogous crude inclusive of transportation charges to the refineries where the oil
produced by the State is being refined as claimed by Assam and Gujarat.
6.14 WELLHEAD PRICE
6.14.1 The point of production and point of sale differ in the case of crude oil. Crude oil is not
sold at the wellhead , but at the custody transfer point or delivery point, which is also called the
off-take point. The material extracted involves, apart from field gathering costs, the cost of
stabilizing storage and transportation . Thus, if royalty is as share to the owners of land, royalty
should relate to the wellhead price (the concerned Rules also prescribe the same ) and there is a
problem of determining wellhead price. According to the law in India, royalty is payable as a
proportion of the wellhead price. India is not alone in adopting this position : country such as
Australia, Pakistan, Norway and the USA impose a royalty on petroleum production calculated by
reference to the value of petroleum at the wellhead.
6.15 DETERMINATION OF WELLHEAD PRICE
6.15.1 The wellhead price is generally calculated by deducting all the post-wellhead costs and
associated returns from the sale price. Normally, exploration and production companies own
complete infrastructure to store, transport and process the crude (both at onshore and offshore
locations) before the same is supplied to refineries, although in some countries (e.g.. Russia), all
transportation facilities are provided by a different agency for a charge. The sale price of crude oil
supplied to refineries is fixed at a post-wellhead location, which is normally the custody transfer
point or delivery point.
6.15.2 The calculation of wellhead value backward from the sale price was provided in the
Petroleum and Concession Rules,1949. According to the Rules: "Wellhead value shall be
published price of crude oil of similar type and quality in a substantial free market in any part of
the world, where such market exist, with suitable adjustments to bring the price back to wellhead
value of the crude oil". Petroleum and Natural Gas Rules.1959, where wellhead price is
prescribed as the basis of royalty but has not been defined, however, subsequently superseded
Conceptually, wellhead value is to be calculated from the sale price by deducting all the post -
wellhead cost and associated returns. It is significant to note that the calculation of post-wellhead
expenses is a tedious exercise and may involve dubious issues about what is and is not an
admissible expense. A more straightforward way is to take predetermined proportion of the price
as post-wellhead expense and derive the royalty as a proportion of the price adjusted for this
6.15.3 Royalty dependent on the wellhead price, that is the price of oil less transportation
charge and other post wellhead expenses, rather than a flat rate royalty can ensure that there is
no disincentive for economically viable marginal fields to continue production. However, there are
practical administrative difficulties in monitoring transportation and other post-wellhead charges.
Upstream companies have to operate flow lines from wellhead to Oil Collection Station (OCS)/
Group Gathering Station (GGS), where the crude, oil, gas, water and impurities are segregated.
They also have to incur operating costs of flow lines from OCS/GGS to Central Tank Farm. These
and other operating costs beyond the wellhead but before sale are fairly non-controversial for
determining the wellhead price. But, how much of depreciation for all the facilities beyond the
wellhead, and of general administration (cost such as accounting, auditing, general insurance)
and interest cost (when the project has a mixture of debt and equity) to consider in the calculation
of wellhead price can lead to protracted negotiations.
6.15.4 This problem of determining the wellhead price (or value, as the case may be) is
reflected in the legislative stipulation in Australia that the valve at the wellhead is the amount
agreed between the license holder on the one hand and the licensee on the other. In the USA,
while transportation cost to the point of sale is allowed for deduction can not exceed 50 per cent
of the royalty value. It has been suggested that wellhead price calculated on the basis of market
determined price of crude oil after the end of the transition period on March 31, 2002 should
constitute the royalty basis, and the cost deductible from the market price should be:
(i) 7.5 per cent of the market determined obtained price or if either party considers the flat rate
may be deducted as either inadequate or too much, then the amount as agreed between the
parties. Such agreements should be signed by the concerned parties at the beginning of the
adoption of the new system, and subsequently, upon award of all licenses. Existing agreements
may be renewed every five years, with a provision for review at the instance of either party. This
mechanism can also take care of the possibility of a lower effective royalty with respect to
additional investments needed for fully exploiting old wells.
(ii) In case such an agreement cannot be reached for any reason, the matter may be referred to
the proposed regulatory agency to prescribe the alternative of a predetermined proportion of the
sale value deductible as post-wellhead costs, whose decision will be final. The figure may be in
the range of 7.5-20 per cent, but not vary from field to field.
NIPFP has further suggested that alternatives (i) and (ii) can be fully applicable only after a
regulatory agency is in place. Until then, in all cases where agreements are feasible, the standard
deduction of 7.5 per cent should be applicable on the basis price as describe above.
6.15.3 Change in the price of oil is neither a necessary nor a sufficient condition for changes in
the post-wellhead costs. For example, post-wellhead costs may remain unchanged when the
price of oil goes up and down. Similarly, the post-wellhead costs may go up with the falling
reserves or some other reason in a particular field even when the price of oil remains unchanged.
Thus, it is desirable that like the mutual agreements, the predetermined deductions also be
reviewed every five years by the regulatory agency, unless both the concerned parties are able to
come to an agreement in the meantime and inform the regulatory agency accordingly.
6.16 ROYALTY RATES
6.16.1 According to NIPFP, royalty has to be seen in the context of other fiscal imposts and
levies. With price of crude fixed by border prices in a deregulated scenario, the royalty will have to
be internalized by the producer. Too high a royalty with high level of customs, sales tax and other
levies will undermine trends in reduction of royalty rates (both negotiated and general) and the
range of most frequently encountered rates, the ceiling rate of 20 per cent on the wellhead vale
does not appear unreasonable; since a medium-term reduction in royalty rate is being advocated
here an immediate application of a rate of 18 per cent is suggested as the applicable ad valorem
rate for onshore areas. For reasons given here in subsequent paras royalty rates for the offshore
and the deep-sea areas should be 15 and 12.5 per cent respectively. Differentiating rate of
royalty by the quality of crude is theoretically sound but difficult to implement due to monitoring
requirements. It would be better to leave such fine tuning to the agreements regarding deductible
costs. An exception, however, be made in the case of heavy oil defined as of less than 25 API,
where there should be a discount of 3 per cent on the generally applicable rate of royalty.
However, the above mentioned royalties must be reckoned on the basis of a price obtained by
the producers in a deregulated market.
6.16.2 The basic price should be an objectively determinable one, e.g. weighted average of f.o.b.
prices. Since prices fluctuate considerably, it is necessary to consider both the frequency at which
royalty payable should be computed as well as the exact base price. It is recommended that
royalty may be paid on a monthly basis as before, subject to reconciliation of accounts once for a
year, on the basis of royalty payable over a weighted average of end-week prices during the year.
This will be equivalent to computing royalty every week.
6.17 DUAL ROYALTY REGIME WITH NEW EXPLORATION LICENSING POLICY (NELP)
6.17.1 Prior to 1991 (except three bidding rounds), only NOCs were given exploration blocks
on nomination basis. In order to attract private investment in oil sector, since 1991, the
Government of India has been offering exploration blocks to private companies from time to time
including under NELP.
6.17.2 With changes under NELP, there is a dual royalty regime in crude. Multiple rates of
royalty can pose various administrative, legal and monitoring problems both for the producers as
well as the governments. Separate accounts
6.18. CONVERGENCE WITH NELP RATES
6.18.1. According to NIPFP, the introduction of NELP has created a dual royalty regime with all
its associated complications and resentments. Ideally, rules be the same for all participants in a
particular sector. Dual regimes - whether, in exchange rates, tax rates and royalties - create an
additional compliance costs and administrative difficulties . NELP has been introduced in order to
attract private investment in the oil sector. In line with the liberalised policy of the Government ,
the motivation is to step up the level of investment in exploration and hasten the pace of
hydrocarbon reserve accretion to meet the increasing demand for petroleum products. According
to NIPF, introduction of NELP is a partial admission of the failure of the old policy -of continued
reservation of the oil sector for public sector companies, the administered regime and levy of a
myriad taxes and levies on the companies - to deliver dynamic growth in the sector.
6.18.2. Having introduced NELP for promoting new investments in the sector, it is difficult to
justify why for fields held on nomination basis, the National Oil Companies should not be given
the same benefits as under NELP. The National Oil Companies have made heavy investments
and created a knowledge base in the hydrocarbon sector in the country. Furthermore, for their
crude ,they have been paid far less than the prevailing international prices. Part of the inefficiency
in their operations, in any case difficult to segregate in terms increased costs of operation, may
reflect not only the public sector nature of these companies but also a non-market non-
competitive environment which they operated and have been operating. Given that their profits as
well as net worth belong to the people ,there is no reason why they should be denied a level
playing field to operate in the sector.
6.18.3. In response to the question of whether the royalty for fields awarded to NOCs on a
nomination basis should be brought at par with the NELP regime, opinions differed widely. The oil
companies wanted the NELP regime to apply to blocks to given on nomination basis because that
would create a level playing field and would also be in conformity with the heavy investments and
creation of knowledge base in the hydrocarbon sector. Furthermore, according to OCC ,the price
paid to theNOCs for their product was far less than the prevailing international prices and there
was no increase in the crude basis for a period of more than 11 years. The NOCs have
contributed a significant sum to the oil pool account towards difference between the full FOB price
of crude oil and the price actually allowed to them from 1st April 1998. The NOCs also have to
pay the OID cess, while the investment requirements are large due to fast depleting existing fields
that require substantial investment to even maintain the existing level of production.
6.18.4. Among the respondent States ,only Nagaland shared the views of the NOCs on
convergence with NELP. Assam expressed its dissatisfaction with the lower NELP rates being
announced without consultation with the States. Gujarat also wanted to make a distinction
between the two regimes since NELP is a new policy and is linked with the liberalisation of the
hydrocarbon sector : therefore it should be treated it as different. Rajasthan wanted the NELP
rates to be raised to 25 percent, the same as that wanted for blocks given on nomination basis.
6.18.5. The concern of the major oil -producing States to maintain the dual regime is
understandable in view of the revenue significance of royalties ,although one may argue that the
policy of higher royalties may be rather short-sighted ,even if revenues were the primary
consideration .The lower rate of royalty and other benefits conferred by the NELP regime can be
said to have been dictated by certain compulsions like the need for infusion of large foreign
investments in competition with other countries and reduce the cost of operations for NOCs too.
There are reasons to prefer a similar royalty regime as outlined above, but this must be done
without administering any adverse revenue shock to the concerned States. This indicated a
gradual whittling down of the recommended 18 per cent rate over a period of time to the NELP
6.18.6 It is not only the royalty rate that should converge to that of NELP. Even in OID cess there
is a dual regime. The license holder under NELP is extemp from not only OID cess but also
import duty and enjoys income exemptions for seven years. There seems to be little justification
for the OID cess to operate differentially between the companies under NELP and under the old
regime. The OID cess for non-NELP sector also should be reduced and replaced by a revenue-
neutral excise duty and this excise duty should apply symmetrically on all producers.
6.18.7 For creating a level playing field, the royalty regime for fields given on nomination basis
should be on par with that of NELP. A period of five years with the royalty rates for fields given on
nomination basis declining from 18 per cent recommended for 2002-03 by 1 percentage point
given every year starting from 2003-04 up to the fourth and 11/2 percentage point in the fifth can
bring about the convergence. Much of the revenue loss for the State and the Centre on account
of this reduction in the royalty rate for fields given on nomination basis may be made up by an
expected increase in output. It is reasonable to anticipate that a part of the higher returns to the
national oil companies because of the reduced royalty will be reinvested in the fields to augment
production and expand the revenue base.
6.18.8 Royalty in offshore and deep-sea areas also need to be brought on par with the NELP
rates. In the case of offshore areas, a lower rate of 15 per cent is suggested to start with; this can
be reduced by 1 percent every year starting from 2003-04 to coincide with NELP rate of 10
percent after five years. Similarly, the rate for deep-sea areas may be reduced by 1.5 percent
every year from the starting level of 12.5 per cent to converge with the NELP rate of 5 per cent.
6.19 INTERSTATE DIFFERENTIALS
6.19.1 In the absence of hard data on differentials in cost conditions, quality of crude, risk profile
of fields, a strict application of a uniform rate of royalty, favoured by all stakeholders but one, has
a lot to recommend itself. What is good for State A, should be good for State B as well. Nagaland
preferred uniform royalty rates, but with an add-on for itself due to special circumstances. It
should be noted that a higher royalty in a State, relative to others, may deter investments and
affect the State adversely in terms of revenue. However, given the political nature of the issue,
the Government may take a view on the question of any add-on for a particular State.
6.20 ROYALTY PAYMENT IN KIND
6.20.1 All the States, except Nagaland and Gujarat, which responded were against the payment
of royalty in kind. Even oil companies did not favour a system of payment in kind as they
anticipated problems for the States in disposing of the royalty received.
6.21 PENALTY FOR LATE PAYMENT
6.21.1 The existing provision of Section 23(1) of Petroleum & Natural Gas Rule 1959 states that
"all license fees, lease fees, royalties and other payment under these rules, shall, if not paid to
the States Government within the time specified for such payment, be increased by 10 per cent
for each month or portion of a month during such fees, royalties of other payment remain unpaid".
The oil companies considered it very harsh and wanted it linked to the prevailing rate of interest,
which is 12 per cent per annum. Thus, they wanted the provision changed to 1percent per month
from 10 percent per month. Nagaland and Uttar Pradesh were also in favour of linking the late
penalty to the interest rate as in the case of other minerals.
6.21.2 Other respondents did not favour any change in the provision. Furthermore, the
Government of Assam was also of the opinion that interest should be paid to the State
Governments for the delayed arrear payments on account of delay in fixing/finalising the revised
rate of royalty.
6.21.3 NIPFP feels that the penalty prescribed for late payment applicable now appears to be
rather punitive. The appropriate penalty for late payment should be the opportunity cost of the
funds delayed, and that could be taken as the prime landing rate of the State Bank of India, plus
100 basis point, the latter providing the incentive for timely payment.
6.22 INDEPENDENT AGENCY FOR ADJUDICATION
6.22.1 The sharp polarisation of views on certain aspects of royalty fixation among different
stakeholders has the potential of developing into acrimony. It would be wise to provide for an
independent agency to adjudicate disputes about royalty between States and the oil companies
that would mainly relate to the deduction of post-wellhead expenses under the proposed scheme.
An independent agency may also fix the predetermined proportion of the sale value deductible as
post-wellhead cost for different fields.
6.22.2 Given the large scale of operations of the oil companies and the nature of the petroleum
market, there is an urgent need for a regulatory agency in the hydrocarbon sector. This regulatory
agency can be mandated with the right to adjudicate disputes on crude oil royalty. It should be
emphasised that the adjudication is neither about the rate or the base, but about the appropriate
application of the rate and the base in the calculation of royalty and the deduction for post-
6.23 TREATMENT OF OID CESS FOR ROYALTY DETERMINATION
6.23.1 A question that has dogged the issue of royalty base is whether the OID cess should be
included in the wellhead price or not. It appears unreasonable to include it in the royalty base
because the cess is not a return to the oil companies but an outgo. Asking them to pay a share of
what they do not receive appears unjustified. It must be recognised that cess is not a levy that
can be passed on to the consumer. On the other hand, excluding the cess from the royalty base
is unjustified because by levying the cess, the Centre effectively erodes the royalty of the States.
Conceptually, however, neither the administered price being paid to the producers, nor the
market price that would be available to the producers after deregulation can be thought of as
varying with the amount of cess. Since, the royalty base is independent of the amount of cess in
both cases, there is little reason to exclude it from the basic price for the purpose of royalty
computation. Thus, although the inclusion of the cess in the royalty base would imply an unfair
burden on the oil companies, it cannot be excluded in practice.
6.24 OID CESS AMOUNT
6.24.1 Current level of cess at Rs.900 PMT is too high and the burden of the oil companies
increases directly into proportion with the level of the cess. With a royalty of 18 per cent, there
would be an unfair burden on the oil companies of Rs.162 (!8 per cent of Rs.900). One way of
resolving this problem will be to gradually reduce the cess on onshore areas by Rs.100 every
year to a lower level of around Rs.400 over a period of five years from April 1, 2002, and partially
compensate for it with higher cess in the case of offshore and deep-sea areas. In the latter case,
the implied lower profitability can be reflected in the dividends of the NOCs without any net impact
on the recipient of the dividends, that is the Central Government. The smaller revenue from lower
cess in onshore areas can be partially compensated also through an Union excise on crude
matched a countervailing duty on import of crude, providing a revenue-neutral method of
removing the problem. Petroleum crude is at present under Union excise, but levying a Union
excise on it is probably not legally barred as long as appropriate legislative action is taken.
Mauskar Royalty Committee Report
7. CONCLUSIONS & RECOMMENDATIONS
7 Based on the inputs received fro the stakeholders and the expert opinions of NIPEF as
also subsequent personal interactions and the detailed deliberations of the Committee and
keeping in view the need for higher investments for exploration and production in the country, the
signification of royalty in the States, revenue and the global royalty regimes, the Committee has
reached the following conclusions on the identified issues.
7.1 The recommendations made hereunder will be applicable to crude oil production from the
(i) Areas granted to NOCs on nomination basis
(ii) Exploration blocks awarded to Pvt/JV contractors prior to NELP
(iii) Onland discovered fields awarded to Pvt/JV contractors
7.2 In respect of the above categories, the Central Government for offshore areas and respective
State Governments for onland areas would be paid royalty as recommended in this Report.
7.3 AD VALOREM VERSUS SPECIFIC ROYALTY RATE
7.3 The committee notes that major producing States and NCOs have supported the concept of
fixation of royalty on Ad valorem basis. NIPFP has also supported fixation on Ad valorem basis as
it provides an efficient way of sharing the risks and rewards between the Licensor and the
producers. The Committee also notes that global trends is towards the Ad valorem rate which is
to be preferred on account of its flexibility and linkage with the price of crude oil. The Committee,
therefore, is of the view that royalty be fixed on Ad valorem basis as against the specific rates for
per unit of production as at present.
The Committee recommends that the royalty be fixed on Ad valorem basis.
7.4 PRICE OF CRUDE OIL
7.4.1 Consideration of crude oil price for royalty determination is somewhat contentious, with
various stakeholders having divergent views. The major oil producing States suggested the full
posted price/landed cost of imported (analogous Middle East) crude. The producers, NCOs are in
favour of the sale price at the wellhead worked back from the actual sale price. NOCs are also of
the view that OIC cess and royalty amount be deducted from the price while working out the sale
price for determining royalty. NIPFP have however suggested that price of crude oil received by
the domestic producers should be deregulated and the producers should obtain the market price
determined on the basis of arm’s length transaction. The Committee notes that deregulation will
come in effect from 1.4.2002 and in a free market like situation no linkage with any
artificial/notional price is called for. The Committee, therefore, feels that the market driven price
obtained/obtainable by the producers should be considered for determining royalty under
deregulated price regime.
7.4.2 The question of price for crude oil during the transition period from 1.4.1998 to 31.3.2002
was also deliberated by the Committee. As brought out earlier in the Report, different specific
adhoc rates of royalty were fixed by the Government from time to time since 1.4.1998. At present,
the rate of royalty is Rs.850/- per MT effective from 1.12.1999 with a ceiling of 20% of the
wellhead price. As noted earlier in the Report, the producers were paid a floor price of
Rs.5570/MT since 1.11.1999 which still continues. It is also seen that the adhoc royalty revisions
have given some relief to the States in terms of crude oil price paid to the producers.
7.4.3 The Committee notes that any consideration of full market/international price w.e.f
1.4.1998 for royalty determination is not appropriate because producers were not to be paid this
price under the system of notified percentages of the price envisaged for various financial years
in terms of the Government Resolution on dismantling the APM. The Committee also notes that
the dismantling of the APM had its own rationale and was done in the overall public interest. The
Committee, therefore, feels that full deregulated market driven price should become effective only
from 1.4.2002 which as of now is the date for complete dismantling of the APM.
7.4.4 NIPFP’s analysis indicates that in case royalty is paid according to notified percentages of
import parity price because they were never paid this crude oil prices. The Committee observes
that adjustments were earlier made from the Oil Pool Account for such kinds of payments and
feels that the additional royalty amount payable to the State Governments for 1998-2002 may be
adjusted accordingly. The Committee also feels that under the circumstances, there would be no
requirement of paying any interest on this adjustment for ‘delayed’ payment, as would normally
be reckoned. The additional payment to the Central Government for 1998-2002, to as estimated
in terms of the Committee’s recommendations may not be large. In fact, depending upon the
movement of crude oil prices for the remaining months of 2001-02, some refunds to NOCs could
be accrue. The Committee, therefore, fells that no adjustments on account of royalty to NOCs or
to Centre, over and above the accounts paid/payable as a result of adhoc revisions since
1.4.1998 be effected.
7.4.6 The Committee notes that as regards the periodicity of royalty calculations. Rule 14 (2) of
P&NG Rules 1959 provides for submission of a monthly return of production by the lessee from
various Mining Leases to the respective Governments. The Committee feels that unless
otherwise agreed or decided between the parties, the periodicity of royalty calculations should
also be on a monthly basis. This arrangement will facilitate convergence with the submission of
monthly returns of productions by the lessee(s).
7.4.7 The Committee, therefore, recommends that:
(i) After 1.4.2002 under the deregulated regime, the wellhead price as derived form the market
driven price obtained/obtainable by the producers based on arm’s length transactions in terms of
the relevant recommendations be considered for royalty calculations.
(ii) Royalty to the States and the Centre during the transition period, from 1.4.1998 to 31.3.2002
be paid on the wellhead price derived in terms of the relevant recommendations of the Committee
and calculated on the basis of pre-notified percentages of the import parity (f.o.b.) price stipulated
in the Government Resolution on dismantling of the APM.
(iii) Additional amounts against the Royalty accrued for onland crude oil production as a result of
the above recommendations, be paid to the States after adjusting the royalty payments made in
terms of adhoc revisions since 1.4.1998. However, these dues may not be borne by NOCs and
may be adjusted by the Government in line with the earlier practices for adjustments of this
nature: and no “delayed” interest will be payable.
(iv) For offshore production, no adjustment of any additional amount, over and above the
payments in terms of the adhoc revision of royalty since 1.4.1998, which accrues either to NOCs
or to Central Government, be carried out.
(v) The royalty calculations be made on a monthly basis.
7.5 WELLHEAD PRICE
7.5.1 Section 6 (A) of Oilfields (Developments & Regulation) Act. 1948 provides for royalty
fixation not exceeding 20% of the sale price at the well head or the oilfield. In practice, well head
is not the sale point. Crude oil before being sold has to gathered, processed and transported to
the point of sale. This involves real costs in terms of infrastructure and operating expenses. It is
therefore logical to determine the well head price, which involves deduction of all the post well
head costs from the sale price obtained by the producer. Major producing states though agreeing
with the concept have different perception about working out the well head price. The States like
Gujarat have defined the well head value as “ the publish price of crude oil of similar quality
worked back to well head in substantial free market in any part of the world where such an oil
market may exist”. According to State of Assam, well head price should be the average posted
price of analogous Middle East crude inclusive of transportation to the refineries. This can be
adjusted with the transportation charges from well head to the said refineries. On the other hand,
according to producers, well head price is required to be calculated back from the actual sale
price by deducting all the post well head costs and associated returns.
7.5.2 Thus, there were divergent views from the respondents regarding the determination of the
price at the well head. The Committee notes that though there is indeed a logic for deductions
towards the post well head costs, their determination involved detailed calculations and also the
methodology for determination of well head price was somewhat complex. The other factors
involved were the components of various costs to be considered, whether it be calculated field-
wise, region-wise or state-wise: the bifurcation of costs into Oil, Associated Natural Gas (ANG) &
Non-Associated Natural Gas (NANG) and the periodicity. It is seen that the concept of well head
price for royalty purposes is prevalent in several countries around the world. In India Joint
Venture Companies are working out the well head prices of natural gas for royalty purposes. The
detailed Note on the concept of well head price, including the international practices which
emerged from the studies of the Committee is placed as Appendix IV to this Report.
7.5.3 On this issue, NIPFP has expressed the clear opinion that calculation of wellhead price is
a complex exercise, there are practical administrative problems in monitoring the post wellhead
costs and it is therefore desirable to allow a flat rate deduction towards the post wellhead costs.
NIPFP has indicated that deduction of around 7.5% would be appropriate under the post APM
7.5.4 The Committee concludes that the system of wellhead calculations is complex in nature
and is quiet likely to result in difference of opinion between producer companies (NOCs) and the
Government, not only regarding the methodology of arriving at the wellhead price but also on
accounting practices and the resultant outcome in terms of the difference in the final wellhead
price. The Committee notes that this system was not practiced in India earlier basically as not
being feasible and it is essential to find an alternative to avoid these practical difficulties and
administrative problems. The Committee therefore agrees with NIPFP that a fixed proportion of
the price be allowed for deduction towards post wellhead expanses so as to arrive at the
wellhead price. Off course in exceptional cases, the parties have the recourse to the dispute
resolution mechanism provided under Rule 33 etc. of the P&NG Rules 1959.
7.5.5 The Committee after considering the financial implications and all related views in the
matter feels that around 7.5% of the sale price for onland crude oil 10% for offshore crude oil
should be allowed towards deduction of post wellhead expanses. Higher deduction for offshore
crude are being recommended by the Committee in order to compensate for the related
infrastructure at offshore and transportation upto the land fall point which entail additional
expenses including the almost compulsory use of Pour Point Depressant. The figures of 7.5% for
onland and 10% for offshore are in the nature of averages and appear to be reasonable
compared to the international percentages and also rules in this regard. It is for this reason that
the Committee has not recommended different percentages for the period 1998-2002 as
contrasted to those for post APM i.e. 1.4.2002, although the basis of price is somewhat different.
7.5.6 The Committee recommends a deduction of 7.5% and 10% of the crude oil price as
recommended above for onland and offshore production respectively, in order to determine the
wellhead price. In case of disputes, between the parties, the matter could be dealt with in
accordance with provision of P&NG Rules 1959.
7.6 ROYALTY RATE
7.6.1 The issue is basically as to what percentage of wellhead price is to be paid to the Central
or State Governments as royalty on crude oil. The Committee considered in detail the views of
stakeholders which were received in response to questionnaires as also expressed during the
meetings. The major producing States have suggested that the royalty rates be fixed at 40% of
the weighted average of the full posted price/landed cost of analogous Middle East crude oil. The
producers however have suggested that the royalty rates be kept at par with NELP rates. OCC
has also suggested a parity with NELP rates. Thus, a major difference of opinion between the
States Governments on one side and the NOCs on the other side. Under the circumstances, the
Committee was also guided by the neutral advice of NIPFP. The Committee The Committee felt
that the demand of States for royalty @ 40% of the landed cost of imported crude was difficult to
accept because it implied a steep hike rates, especially under the deregulated price regime where
the market drive price would be close to the import parity and which would itself be substantially
be higher than the prevailing price since 1.4.98, thus enlarging the base. It was noted that the
application of Ad valorem rate on market driven price would benefit the States substantially. The
Committee studied the global royalty regimes and observed that royalty rates were generally in
the range of 10-15% and the present trend of all the globe was towards decreasing royalty rates.
Some countries like Norway have in fact abolished the royalty, being in form of regressive upfront
levy, in order to prolong the economic life of their fields. Lastly, royalty is not looked at globally in
isolation, because the oil-economics require consideration of all levies and taxes.
7.6.2 High rates of royalty were also not desirable looking the need for higher investments
towards exploration activities in the country. There is an urgent need for substantial investment in
exploration for augmentation of reserve base in view of almost stagnant production in the country
during the last decade. In the absence of budgetary support from the Government, NOCs, who
still are a major player today, have to mobilize the funds through internal resource generation.
This consideration also calls for optimal rates of different levies and tax including royalty.
7.6.3 The Committee is thus required to determine the appropriate rate and the methodology of
its applications for its recommendations, in such a way that it does not hurt the State in terms of
their revenue collections and enhances reasonably royalty take of the States from the level
prevailing prior to 01.04.1998. Another relevant consideration kept in mind by the Committee
were the financial implications for the past period and the future. NIPFP in their advice have
stated that a ceiling of 20% of royalty on sale price at the wellhead does not appear to be
unreasonable in the context of international royalty regime. They have suggested for immediate
application of 18% levy of royalty on the wellhead price for onland crude oil and 15% levy for
offshore crude oil, a reduction of 3.0% in royalty rates has also been suggested for heavier crude
oils of 25 API & less. The Committee however felt that uniform rates of royalty for onland and
offshore during the transition period of phased deregulation of 1998-2002 are desirable in the
interest of fiscal stability.
The Committee in addition felt that multiple royalty regime could not be justified on a
perpetual basis and having uniform royalty rates in line with NELP regime in medium term would
facilitate the convergence of the country’s overall E&P fiscal regime with the global regime.
Reasonable royalty rates would also help in accelerating E&P efforts and in due course lead to
higher realization to the Governments through levies and taxes by larger investments and
production. It was therefore felt that the rates should be structured as to facilitate ultimate
convergence with NELP rates without hurting the revenue collections of the States: even though
some augmentation of revenue collection had already been affected as a result of adhoc
revisions in royalty rates after 1.4.98 from Rs.578/MT to Rs.850/MT (provisional) as of today.
The Committee noted that the NOCs did not get the price envisaged under the APM
dismantling scheme and it recommended a special adjustment mechanism so that the States got
some benefit without burdening the NOCs. The Committee felt therefore that a royalty rate of
18% of the wellhead price based on notified percentages of import parity price, as recommended
by the Committee, for crude oil production from both onland and offshore would be the optimal
rate for the period 1998-2002. With this rate, the states would receive some additional amount for
the transition period 1998-99 to 2001-02 over and above what had already been received as a
result of adhoc revisions since 1.4.1998.
7.6.6 As regard, the royalty rate for post APM period, i.e. after 01-04-2002, the Committee felt
that for 1 year more, i.e. 2002-03, the royalty rate of 18% of the wellhead price based on market
price obtained/obtainable on arms length basis for crude oil production for both onland and
offshore would be optimal, in as much that the States would get some benefit without any
adverse implications to the NOCs. Subsequently, over the next five years, i.e. 2003-04 to 2007-
08, the royalty rates for onland and offshore be tapered down to the NELP royalty rates of 12.5%
and 10% respectively.
7.6.7 The above examination is supported by the result of the sensitivity analysis for various
rates applied on the recommended price by the Committee. It was observed that if the import
parity price of Rs.9092/MT (US$ 26 per bbl. appx.) as prevalent during the year 2000-01, is
considered, onshore royalty @ 18% of the wellhead price calculated as per the methodology
recommended would yield a royalty rate of Rs.1283/MT which is 222% of the rate of Rs.578/MT
as applicable prior to 1.4.1998, if adhoc revisions during the period under review are not taken
into account. Even, at NELP rates of 12.5%, the royalty would be Rs.934/MT which is 162% of
the rate of Rs.578/ PM applicable prior to 1.4.1998, and still higher still higher than the current
rate of Rs.850/ PM revised on adhoc basis. Even if prevailing average price during 2001 of
Rs.7855/MT (US$ 22 per bbl. appx.) is considered the royalty rate @ 18% would work out to be
Rs.1108/MT. The States are thus expected to be benefited even when the current NELP rate of
12.5% is made applicable under the deregulated scenario, if the crude oil prices stabilize around
the rate of Rs.7855/MT or higher. Although it is difficult to predict oil prices for the future, taking
into account increasing demand and stagnant global reserves, long range forecasts of US$ 22-28
per barrel may not be too off the mark, in addition softening of the rupee against US$ will provide
7.6.9 Although NIPFP had recommended a reduction of 3.0%, the Committee feels that a
reduction of 2.5% in the rate of royalty for heavier oils of 25 API and below, over the applicable
rates at a given point of time for normal crude oils, as per its recommendations, was necessary.
This reduced rate is indeed with a view to encourage exploitation of heavy oil fields because
exploitation of such fields involves additional efforts in terms of infrastructure & operating costs
and requires specialized proprietary technologies. The Committee also noted that confessional
royalty regimes for heavy oil are prevailing in countries like Canada. Further recoveries from such
fields are are generally lower and production of heavy oil reserves is required in the national
interest. This reduction of royalty will apply prospectively i.e., only after 1.4.2002, because of the
classification required and heavy oil is not being produced substantially today.
7.6.10 The Committee has already brought out the existing working for royalty calculations at
para 4.5.2 which has been endorsed by the stakeholders, including the major producing States.
The Committee feels that this may continued to be used.
7.6.11 The Committee recommends the following royalty rates for onland and offshore
(i) During the transition period 1998-99 to 2001-02, royalty on crude oil production from
onland and shallow water offshore areas (upto 400mts water dept) be paid @ 18% on the
wellhead price as derived from the price recommended above.
After the complete dismantling of APM, viz. 2002-03 onwards
(a) For crude oil production from onland areas, royalty be paid @ 18% of the
wellhead price as derived from the price recommended above, for the commencement year 2002-
03 and thereafter at the sliding rates by 1.0% for each year till 2006-07 and then by 1.5% in the
subsequent one year to converge with the NELP rate of 12.5% by 2007-08.
(b) For crude oil production from shallow water offshore areas, royalty be paid @
18% of the wellhead price as derived from the price recommended above, for the commencement
year 2002-03 and thereafter at sliding rates by 1.5% for each year till 2006-07 and then by 2.0%
in the subsequent one year so as to coverage with the NELP rate of 10.0% by 2007-08.
(iii) From crude oil production from deepwater areas, beyond 400 mts of water depth, the
royalty rates during the first seven years of commercial production be half of the rates as
recommended above for shallow water areas.
(iv) For heavier crude oils of 25 API and less, the royalty rates be 2.5% lesser than that
recommended above for normal crude oils from onland and offshore with effect from 01-04-2002.
(v) The royalty be calculated in accordance with the existing methodology.
7.7 TREATMENT OF OID CESS FOR ROYALTY DETERMINATION
7.7.1 Treatment of OID cess and its inclusion in the sale price for royalty purposes has been a
bone of contention in the past, even under the APM. Producers were of the view that cess
amount was not a receipt in their hands as a part of the sales proceeds and there was thus no
justification for paying royalty on the amount which was not received by them. The Central
Government on the other hand, were of the considered opinion that cess was a part of the gross
piece of crude oil and the price considered for royalty purposes should include cess amount.
There has however been no consistency in the past in the matter of inclusion of cess amount in
the piece of crude oil for royalty calculations. NIPFP has examined the matter and advised
inclusion of cess since there was little reason to exclude it. The Committee also noted that as
recommended by it above, the royalty will now be determined by the wellhead price derived from
the notified percentages of import parity price for 1998-2002 and market driven price after
1.4.2002 and these will be inclusive of levies like cess and royalty which the producers have to
7.7.2 The Committee concludes that the question of inclusion of OID cess for price determined
for royalty purposes would not be relevant during the phased deregulated regime i.e. 1998-2002
and post APM period, i.e. after 01-04-2002, in view of its other recommendations.
7.8 DIFFERENTIAL RATES OF ROYALTY
7.8.1 In connection with the fixation of royalty rates, the Committee deliberated on the
desirability of differential rates of royalty: such as different rates for onland and offshore areas,
inter-States differentials and special concessional rates in respect of production from fields
needing Enhanced Oil Recovery (EOR)/Imported Oil Recovery (IOR) techniques. The Committee
took note of the views of the stakeholders in this regard.
7.8.2 Desirability of convergence with NELP rates has resulted in the recommendations of the
Committee for differential rates of royalty for onshore and offshore crude oil production in the post
APM period. With regard to inter-State differentials, all the States except the State of Assam and
Nagaland favoured uniform rates of royalty. The State of Assam has asked for higher rates on the
grounds of special consideration for N.E. States, NOCs & OCC, on the other hand, have favoured
uniform rates. The Committee is of the view that such inter-States differentials were not desirable
in the overall economic context. There is no economic logic for differential rates of royalty on the
ground of regional backwardness. NIPFP in their opinion favours uniform royalty rates for all the
States. According to them, higher royalty for a State relative to others might deter investment and
affect that State adversely in terms of revenue ultimately. The Committee concludes that inter-
State differentials are not desirable in general, unless there are exceptional grounds.
7.8.3 The State of Nagaland has asked for royalty "add on" in view of its special status under
Article 371-A of the Constitution of India. The State has been pursuing the matter for a long time
with the Union Government. It may be pertinent to mention that oil & gas operation in this State
remained suspended for about last one decade and only recently the Government of Nagaland
has agreed for resumption of operations. NIPFP while referring to this issue has left to the
Government to take a view, due to political nature of the issue. The Committee feels that in view
of certain special considerations in case of the State of Nagaland, some "add on", such as grants,
may be considered.
7.8.4 The Committee also considered the desirability of having concessional rates of royalty in
respect of additional oil produced from fields needing higher investments due to EOR/IOR
Schemes. It was noted that the recovery factors of oil in India are generally low, below 30% on
average as compared to the level of 50% or more achieved in some countries. There is an urgent
need to improve the recoveries from fields with low recovery factors through implementation of
EOR/IOR Schemes, which involves substantial additional investments and induction of costly
technologies. This was discussed with the States and the concept was found acceptable. NOCs
have also suggested for a review of rates from declining fields, where presumably EOR/IOR
Schemes would be taken up. In order to encourage investments in such Schemes, the
Committee agrees with the rationale of having concessional rates of royalty on additional oil
recovered from such fields. However, the royalty rates would need to be determined on a case to
case basis depending upon the level of investment required for each field. This would need
consultations between the operator of the field and the Government concerned and the exact
modalities worked out.
7.8.5(i) The Committee feels that inter-State differentials are not desirable. However, in view of
certain special considerations in case of the State of Nagaland, some "add on", such as grants,
may be considered.
(ii) The Committee recommends that reduced rates of royalty for production from fields
under EOR/IOR Schemes could be considered on a case to case basis depending upon the level
of investment needed.
7.9 AGENCY FOR NORMATIVE PRICING OF CRUDE OIL
7.9.1 Stakeholders have expressed widely divergent views on the issue of having an agency
for normative pricing. The States of Gujarat and Nagaland have suggested creation of an
independent agency. The State of Assam has suggested a creation of an independent tribunal.
According to NOCs and OCC, there is no such need under the deregulated regime. The
Committee feels that the question of determining normative price of crude would no longer be so
relevant under the deregulated regime where the price will be determined by the market. The
question of normative price will arise only when the transaction is not on an arm's length sales
basis, such as sales to an affiliate or a subsidiary company or like. NIPFP has suggested a role
for the proposed Upstream Regulatory Board in adjudication of such disputes, if any, rather than
creation of a separate agency. The Committee feels that since this would not be an issue to be
dealt with regularly, there may not be any any need to set up a separate independent agency only
for this purpose. In case of disputes, the matter could be settled under the provision of the P&NG
7.9.2 The Committee concludes that there is no need for setting up an independent agency
only for determining of normative price of crude oil.
7.10 NEED FOR AMENDMENTS IN RELEVANT ACTS & RULES
7.10.1 The Committee has carefully examined the royalty-related provisions under the Oil
Fields (Regulation & Development) Act 1948 and the Petroleum & Natural Gas Rules 1959. The
States like Gujarat have suggested several amendments relating to the 20% ceiling on royalty,
license and lease fee, security deposit, surface rent etc. which are specified in the above Act and
Rules. NOCs have suggested amendment of Rule 23 (1) of the P&NG Rules relating to payment
by due date under, which interest on delayed payment @ 10% per month is provided. After
considering all the aspects, the Committee focused only on the royalty related provisions in view
of its terms of reference. The Committee is of the view that amendment is warranted only in
respect of Rule 23 of P&NG Rules 1959 relating to payments by due date. According to NIPFP,
the appropriate penal rate should be the appropriate cost of the funds delayed and that could be
taken as the prime leading rate of SBI plus 100 basis points. The existing provision regarding
penal interest is felt to be too stringent because the stipulated procedure involves calculations as
also preparation & submission of royalty returns and so unavoidable delays at time can be
expected. It is therefore desirable to amend this Rule. The Committee agrees with this view but
feels that slightly higher penal provision than that suggested by NIPFP is necessary.
7.10.2 The Committee recommends amendment of Rule 23 of the P&NG Rules 1959 to the
effect that a penal rate of 200 basis points may be considered over the prime leading rate of SBI
for the delayed period.
7.11 PAYMENT OF ROYALTY IN KIND
7.11.1 The Committee deliberated on the issue of payment of royalty in kind. Due to practical
problems perceived, the Committee has requested for specific views and suggestions from the
States and NOCs regarding the methodology for payment in kind. None of the States have given
their views on the methodology, although the States of Gujarat and Nagaland want to have an
opinion in this regard. NOCs were not in favour because according to them the States were not
geared up in terms of processing, handling and marketing of crude oil and natural gas. The
Committee therefore feels that considering these inherent difficulties and an absence of
methodology, it may not be practicable to make payments of royalty in kind, at the present
7.11.2 The Committee concludes that it is feasible in the present scenario to make the
payments of royalty in kind to the States and the Centre.
7.12 OID CESS ON CRUDE OIL
7.12.1 Levy of OID cess on crude oil has been a subject of discussion by the States as well
as the producers (NOCs). While the States have generally view the cess as an additional revenue
for the Central Government, the NOCs perceive it as an additional burden on their overall
economics. These and some other issues related to OID cess have been raised by the States as
well as NOCs in their written response to the Committee. The States like Gujarat have urged that
OID cess was originally envisaged to be levied on crude oil to create a fund by Government of
India for investigating in newer exploration areas. However, this objective has never been
realized and the large amounts collected by Government of India has been used as a normal
budgetary resource to meet its annual expanses. The State of Gujarat has further sated that
though levy of cess has been abolished under NELP, many PSCs signed prior to 1999 have still
liability to pay Rs.900 per tonne of cess, which amounts to almost US$ 3 per barrel of crude oil
produced. Further, most of the prospective areas in India are relatively small sized and hence
need financial incentives to make their operations viable. If cess from crude oil produced from
such areas is abolished, then it would improve economics of oil production from small structures
and thereby enhance indigenous availability of crude oil less than 1000 barrel per day should be
exempted from payment of cess.
7.12.2 NOCs, like ONGC, on the other hand have urged that they have to compete with other
oil companies which are covered NELP fiscal terms, where cess has been abolished. To provide
a level paying field, levy on cess on NOCs needs a review. They have claimed that cess of
Rs.900/MT is collected by Central Government in addition to royalty which aggregates to around
30% and is to be borne by producer as against custom duty @ 10% on the imported crude oil to
be paid by the importer. This provides negative protection to the domestic producers vis-à-vis the
imported crude oil. Further, after paying 30% towards cess, royalty and after meeting the cost of
production, NOCs have adequate surplus to carry out the planned initiatives for increasing the
production and to make substantial investments in the exploration activities for augmenting the
hydrocarbon reserves. ONGC therefore proposes that the cess @ 5% along with current rate of
royalty vis-à-vis 10% custom duty @ 10% does not provide any protection to domestic producers,
according to NOCs.
7.12.3 NIPFP have also discussed the imposition of OID cess in their Note. They have observed
that the current level of cess at Rs.900 per MT is too high and the burden of the oil companies
increases directly in proportion with level of cess. With a royalty of 18% there would be an unfair
burden on the oil companies of Rs.162 per MT, 18% of Rs.900. One way of resolving this
problem will be to gradually reduce the cess on onland areas by Rs.100 per MT every year to a
lower level of around Rs.400 per MT over a period of five years from 01-04-2002, and partially
compensate for it with higher cess in case of offshore and deep-sea areas. In the latter case, the
implied lower profitability can be reflected in the dividends of the NOCs without any net impact on
recipient of the dividends, that is the Central Government. The smaller revenue from lower cess
in onland areas can be partially compensated also through a Union excise on crude oil matched
by a countervailing duty on import of crude oil, providing a revenue-neutral method of removing
the problem. Petroleum crude oil is at present exempt under Union Excise duty, by levying a
Union Excise duty on it is probably not legally barred as long as appropriate legislative action is
taken, according to NIPFP.
7.12.4 The Committee took note of the views expressed and considered them only to the extent
of their implication on its recommendations. The Committee feels that the substantive issue
raised, including views of NIPFP, regarding OID cess may be examined separately.
7.13.1 The oil sector has been a major source of revenue for the Centre as well as the States.
Central Government's collections from petroleum sector are in the form of custom duty, excise
duty and OID cess as aslo royalty on offshore crude oil whereas the State's collections are
through M.S.T and S.T as also royalty on onland crude oil. Analysis of royalty in isolation from the
total fiscal collection is not desirable in the economic context. Even though the terms of reference
of the Committee are to examine and review the system of levy & collection of all imposts on
crude oil, ,like royalty and sales tax, the Committee did not consider these issues since the States
raised objection s on the terms of reference of the Committee which included review of levies like
Sales Tax, which is a State subject.
7.13.2 The Committee feels that the Government while considering these aspects may take a
comprehensive view, through an appropriate forum separately.
Ad valorem versus specific rate
The Committee recommends that royalty be fixed on Ad valorem basis:
Price of crude oil
The Committee recommends that:
Royalty to the States and the Centre during the transition period from 1.4.1998 to 31.3.2002 may
be paid on the wellhead price derived as per relevant recommendations of the Committee and
calculated on the basis of pre-specified percentages of the import parity (f.o.b.) price as per the
Government order on dismantling of APM.
The additional royalty amount for onland production accrued to the states as a result of these
recommendations, over and above what has been paid or is payable due to adhoc revisions since
1.4.1998. may be paid to the States. Since it is not justified for NOCs to pay the additional
amount so accrued during this period on the logic as brought out in preceding paragraphs, the
amount may be adjusted by the Government as per the earlier practice of adjustment of this
Since the financial implications for offshore production in either way during the period 1.4.1998 to
31.3.2002 are not expected to be significant ,the additional amount ,if any , over and above what
has been paid or is payable due to adhoc revisions since 1.4.1998.accrued either to NOCs or to
the Centre may be waived. Thus, no amount is recommended to be payable by either party for
In the post APM viz .under the completely deregulated regime, the wellhead price as derived from
the market driven price obtained/obtainable by the producers based on arm's length transactions,
as per relevant recommendations be considered for royalty calculations.
The royalty concessions are recommended to be made on a monthly basis.
Committee recommends a deduction of 7.5% of the market driven price obtained for onshore
crude and 10% for offshore crude under the phased deregulated price regime and post APM
period for determination of wellhead price. In case of disputes between the parties, the matter
could be dealt with in accordance with provisions under P&NG Rules 1959.
Considering all aspects the Committee recommends the following royalty rates for onland and
During the transition period 1998-99 to 2001-02. royalty on crude oil production from onland and
shallow water offshore areas (upto 400 mts water depth) may be paid @18% of the wellhead
price as derived from the market driven price obtained by producers as per relevant
After the complete dismantling of APM viz.2002-03 onwards
(a) For crude oil production from onland areas, royalty may be paid @18%for the
commencement year 2002-03 and thereafter at the sliding rates by 1.0% for each year till 2006-
07 and than by 1.5% in the subsequent one year to ultimately converge with the NELP rate of
12.5% by 2007-08.
(b) For crude oil production from shallow water offshore areas, royalty may be paid @18%of the
wellhead price as derived from the market driven price as per relevant recommendations for the
commencement year 2002-03 and thereafter at the sliding rates by 1.5% for each year till 2006-
07 and than by 2% in the subsequent one year so as to ultimately converge with the NELP rate
of 10.0% by 2007-08.
For crude oil production from deep water areas as beyond 400 mts of of water depth, the royalty
rates are recommended at half of them applicable rates as recommended above for shallow
water areas during the first seven years of commercial production.
For heavier crude oils of 25 APM and less ,a further reduction of 2.5% in the royalty rates over
the applicable rates at a given point of time for normal crudes is recommended. Heavy oil
concessions will however be applicable only after the effective date of complete dismantling of
The royalty will be calculated as per the existing methodology.
Treatment of OID cess for royalty determination
The Committee concludes that the question of inclusion of cess for price determination for royalty
purposes would not be relevant during the phased deregulated regime and post APM period
because the royalty will be determined on the wellhead price derived from the specified
percentages of import parity price. viz. Market related price obtained by the producers which will
be inclusive of levies like cess and royalty that the producers have to pay.
Differential rates of royalty
(i) Committee feels that Inter-state differentials are not desirable . However, in view of certain
special considerations in the case of the state of Nagaland, some "add-on" such as grants may
(ii) The Committee recommends that special reduced rates of of royalty for production from fields
under Enhanced Oil Recovery (EOR), Improved Oil Recovery (IOR) Schemes could be
considered on a case to case basis depending upon the level of investment needed. This would
need consultations between the lessee and the lessor . Exact modalities for this may be worked
Agency for normative pricing of crude oil
The Committee concludes that there is no need for setting up and independent agency only for
determination of normative price of crude oil.
Need for amendment in relevant Acts & Rules
The Committee recommends amendment of Rule 23 of P&NG Rules 1959 to the effect that a
penal rate of 200 basis points may be considered over the prime lending rate of SBI for the
Payment of royalty in kind
Committee feels that considering the inherent difficulties, it is not feasible under the present
scenario to make the payments of royalty to the States and the Centre in kind.
OID Cess on Crude Oil
Committee took note of the views expressed and considered them to the extent of their
implication for price determination for royalty purposes. The substantive issue raised regarding
cess should be examined separately.
The Committee feels that Government while considering these aspects should take a
comprehensive view through an appropriate forum separately.