INTRODUCTION

INTRODUCTION

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SECTION – A

INTRODUCTION

In industries like the oil and gas industry, certain ventures are considered high risk, demanding extensive capital investment in a long payback period. To minimize risk, companies develop partnerships called joint ventures. A joint venture consists of an operating partner (operator) and one or more non-operating partners who combine monetary or personnel resources to share a project’s expenses and revenues. The operator manages the venture, arranges venture activities and maintains accounting records. The operator remits venture expenses, collects revenues, and distributes these to the partners, according to their ownership shares. This process is known as Joint Venture Accounting (JVA).

Joint venture agreements typically layout how, when and by whom the joint venture accounting will be maintained.

A joint venture is an association similar to a partnership, but which is entered into for a limited and specific object. These days they are frequently used in large construction project.

As a result of this latter development, large companies have become involved in ‘long-term joint ventures and suitable accounting account of their interest in such ventures has become essential. There are two possible methods of accounting that can be used for such joint ventures.

(1) A separate set of accounting books is provided, in the same way as a partnership. In this case no particular accounting problem exists. All transactions are recorded according to the double entry system and an income statement and balance sheet are prepared in the usual manner.

(2) A separate set of accounting books is not provided. Because of the short duration of many types of joint ventures, separate accounting books are not often provided.

In a joint venture each party, by mutual agreement, assumes responsibility for certain specific task in order that the objectives of the joint venture may be achieved. For example, one party may purchase certain goods on behalf of the joint venture and send them to another party who is responsible for sales. At specific times (e.g. when the venture has been concluded or at other specific times) each entrepreneur must provide the other parties with a complete financial accounting report of all his transactions on behalf of the joint venture.

In order to do this, each entrepreneur records the transactions that he concludes on behalf of the joint venture in his own accounting books, in a special account in the ledger, ‘joint venture with ‘X’. The accounting report that a partner in the joint venture provides to the other partner, will be a summary of the transactions recorded in this account. When all parties have submitted their accounting reports to each other, a joint accounting statement is prepared from this information to determine the result of the venture. This joint statement is also known as memorandum and is prepared separately from the relevant accounting reports. It does not form part of the double entry accounting system in any particular set of accounting books.

The profit and loss of the ventures as determined from the memorandum statement will be divided in the statement between the entrepreneurs, according to the mutual agreement. Each entrepreneur will record his portion of the profit and loss from the venture, as determined in the memorandum statement, in the joint venture

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account in his own accounting books. The debit or credit balance in the account at this stage will represent the amount due by (if a debit balance) or due to (if a credit balance) the other parties in the venture.

SIGNIFICANCE OF THE STUDY:

With the liberalization and globalization of Indian Economy and gradual opening up of the oil sector to private entrepreneurs on global basis where in more and more private companies both Indian and International Oil majors are joining the fray for Oil exploration, cost effectiveness of the operations has become a major pursuit.

With the monopoly diminishing, the organizations have to face a challenge of a highly competitive environment of free economy. It is imperative for the organizations to adapt to the changing environment and manage their activities in a more disciplined and cost effective way.

Being an exploration and production company, exploration and drilling are the major activities of ONGC, covering a substantial portion of its budget allocation. More over in a joint venture scenario, there is a pressing need for ONGC as an operator to improve its budgeting process, on which its cash calls and other fund planning and management is dependent. The company follows a budgeting process wherein the variations between the budgeted amount and actuals are taken into account. However the following shortcomings in the budgeting process has led to the need for the study:

There lies no provision for narrowing down to the root causes of occurring variations of any size apart from the very obvious.

Budget does not reveal the intricacy contributing substantially to the exploratory activities of ONGC like manpower overhead, general and administration overheads. Only the main exploration deviations are given heed.

Budget for upcoming technologies in exploration should be incorporated, thus monitoring and foreseeing of technologies is essential to serve the very purpose of a budget. This will keep the organization from undertaking monetarily voluptuous contracts immediately.

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PROJECT OBJECTIVE :-

PRIMARY OBJECTIVE

To study preparation of JV books of account and variances between the budget and actuals for 5 years, where ONGC and BPCL hold 60% and 40% respectively.

SECONDARY OBJECTIVE

To do Well Cost Analysis.

To study the trends in expenditure under major activity heads i.e. Acquisition, Processing and Interpretation.

To analyze the process of preparation of budgets and AER (Authorised Expenditure Request).

To analyze the cost structure of exploration activities

To implement variance analysis

To conduct research as to why the variance have occurred.

To do a BCG matrix analysis for the block.

SCOPE OF THE STUDY :

The scope of the study is limited to the following factors

The analysis is done to know the operations of ONGC where ONGC is the operator.

Variance analysis is done for the year 2006-07, 2007-08, 2008-09, 2009-10, 2010-11. It is independent to each other, since activities undertaken vary from year to year.

ONGC, Chennai has a total of 37 blocks under the New Exploration Licensing Policy (NELP) of Government of India, for which ONGC is the operator. All the blocks are in the exploratory phase. Out of these 37 blocks, 20 blocks fall under Krishna Godavari (KG) basin and 17 blocks fall under Cauvery basin.

The block is situated in Krishna Godavari region (block code AB-YBB-2011/21).

Purpose of the study

To analyze the process of budgeting and forecasting for the cash requirement with respect to financial position of the venture.

To explore possibility of improving the financial efficiency highlighting the areas of management control.

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RESEARCH DESIGN:

A research has been conducted as to why there has been variance between the budgeted and the actual expenditure in the block budgets. The methodology for conducting the research has been complemented by means of variance analysis. By conducting variance analysis in the organizations block budget, it aids in

i. An overview of all activities involved in exploration.

ii. An in-depth study of the budget by subdividing the total variance on different contributory causes. This gives a clear picture of the different reasons for the overall variance.

iii. Providing reasons and circumstances for variations.

iv. Conductive break up of activities aiding in easier understanding.

v. Accountings of variations of any size as and when they occur.

vi. Help in creating cost consciousness among the employees.

vii. Help in profit planning

viii. Powerful tool for cost control.

ix. Highlights all inefficient performances and the extent of efficiency.

In short, adopting variance analysis in the current budgeting process can help in its, improvisation eventually leading to effective management of activities and in realizing cost effective methods.

Data collection method:

The data were collected in various formats they are-

Annual reports

Magazines

Journals

Websites

Joint Operating Agreement (JOA)

Production Sharing Contract (PSC)

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SECTION- B

INDUSTRY PROFILE

After the Indian Independence, the Oil Industry in India was a very small one in size and Oil was produced mainly from Assam and the total amount of Oil production was not more than 250,000 tonnes per year .

This small amount of production made the oil experts from different countries predict the future of the oil industry as a dull one and also doubted India's ability to search for new oil reserves. But the Government of India declared the Oil industry in India as the core sector industry under the Industrial Policy Resolution bill in the year 1954, which helped the Oil Industry in India vastly.

A significant catalyst in fuelling the growth of the Indian economy, the oil and gas sector presents a powerful scope for investors in the years to come. Of late, the government has followed deregulation path to attract foreign participants. The New Exploration Licensing Policy (NELP), conceived to address the increasing demand supply gap of energy in India, has proved to be successful in attracting the interest of both domestic private sector players and some foreign players.

India is ranked second, behind Australia, in BMI’s composite Business Environment (BE) league table, leading China and Vietnam as a result of a good performance in both the upstream and downstream segments. India ranks second, ahead of Vietnam, in BMI’s upstream BE ratings, with a strong resource position being offset somewhat by extensive state involvement, a limited competitive landscape and only a moderate risk environment.

Oil & Gas – Market Size

Production and Consumption

According to the provisional production data released by the Ministry of Petroleum and Natural Gas, dated June 2011,

Crude Oil production for April 2011 was 3.186 million metric tonne (MMT), as compared to the 2.871 MMT in April 2010.

Natural Gas production during April-January 201 1 was 4096.3 million cubic metres (MCM) During April 2011, 14.006 MMT of crude oil was refined, compared to 13.136 MMT refined in April 2010.

Petroleum

Demand for petroleum products rose by 4.4 per cent (year-on-year) to 144.35 million tonnes (MT) during the financial year 2010-11, according to the latest figures released by the Petroleum Planning and Analysis Cell (PPAC).

Gas

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The proportion of natural gas in the total energy mix has increased to 10 per cent in 2009 from 4 per cent in 1999. The same is expected to increase to 20 per cent in 2025, playing a vital role in the country’s total energy-mix

It is expected that gas production would rise from an estimated 45billion cubic meters (BCM) in 2010 to a possible 95 BCM by 2019.

There are two major sectors within the Oil Industry, upstream and downstream. Upstream is the process of extracting the oil and refining it. Downstream is the commercial side of the business, such as stations or the delivery of oil for heat.

Ministry of Petroleum & Natural Gas

Oil & Gas – Key Developments and Investments

The cabinet has approved the merger between the Russian assets belonging to ONGC and Bashneft and RussNeft promoted by Sistema. This deal will indeed provide access to India to the oilfields of Trebs and Titov. This in turn will enhance the profitability of the Imperial Energy and will boost the ownership of 25 per cent stake in the merged entity along with a say in the management.

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Gujarat State Petroleum Corporation (GSPC) has awarded Larson & Turbo (L&T) an offshore process platform contract KG Basin. Valued at US$ 317.5 million, the offshore process cum living quarter platform project was awarded under international competitive bidding by GSPC to meet its production target of hydrocarbon by July, 2013.

GSPC and Russian petroleum giant, Gazprom Global LNG (GGLNG) have entered into an agreement for supply of up to 2.5 MTPA of liquefied natural gas (LNG).

Quippo Oil & Gas Infrastructure Limited (QOGIL), promoted by Srei Infrastructure, intends to start oil and gas exploration at Cambay Basin in Gujarat in 2011-12. QOGIL was awarded an oil block, (NELP VII Round) for exploration and production in Cambay basin in 2009

The newly approved Petroleum, Chemicals and Petrochemicals Investment Region for Tamil Nadu, set up at Cuddalore and Nagapattinam, has received government support of US$ 1.14 billion.

Oil & Gas - Government Policies

NELP, implemented by government, permits 100 per cent FDI for small and medium sized oil fields via competitive bidding.

Public-private partnerships as well as only private investments can foray into the refining sector. In case of an Indian private company, 100 per cent FDI is allowed.

100 per cent FDI is allowed for petroleum products and pipeline sector as well as natural gas/LNG pipeline, for infrastructure related to marketing of petroleum products, market study of formulation and investment financing.

Minimum 26 per cent equity is covered over five years, in case of trading and marketing The Karnataka Government has announced plans to set up a US$ 822 million, 700-MW dedicated LNG

power plant for its capital. The power plant’s work is expected to be entrusted to the state-owned Karnataka Power Corporation — the nodal agency for power generation.

Oil & Gas - Road Ahead

Ratings agency Fitch has said that India's surplus in refining capacity will continue with the commissioning of new facilities in 2011 and beyond.

Entailing an investment of US$ 13.33-14.44 billion, India's petroleum refining capacities are expected to rise to 240 MTPA by March 2012 from the current 188 MTPA. The capacity addition would facilitate a boost in country's exports of petroleum products, S Sundereshan, secretary, ministry of petroleum & natural gas, stated.

Following are the major projects that are likely to get commissioned within 2011-12: The Guru Gobind Singh refinery project will be commissioned by HPCL-Mittal Energy by September 2011.

HPCL-Mittal Energy is a company set up in joint venture between Hindustan Petroleum and Mittal Energy Investments. The project on completion is expected to add a capacity of 90 million tonnes.

It is expected that Essar Oil will complete the phase-I project of its Vadinar Oil refinery by July 2011. This will raise the existing capacity of 105 million tonnes per annum to 180 million tonnes per annum. The company has also announced its plans to add another 20 million tonnes per annum in phase-II and take the total capacity to 200 million tonnes per annum by September 2012.

IOCL is expected to commission its green field Paradip refinery by mid-2012. The project will add a refinery capacity of 150 lakh tonnes per annum.

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(Source: CMIE)

Steps in Exploration of Petroleum

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COMPANY PROFILE :

Oil and Natural Gas Corporation Limited (ONGC) is an Indian state-owned oil and gas company headquartered at Dehradun, India. It is a Fortune Global 500 company ranked 413,and contributes 77% of India's crude oil production and 81% of India's natural gas production. It is the highest profit making corporation in India, according to filings with the BSE of latest quarter results External Link. It was set up as a commission on 14 August 1956. Indian government holds 74.14% equity stake in this company.

A turning point in the history of India’s oil sector was in 1994. While the oil sector was on the backburner of India's political realm for some time, is was brought to the forefront by the privatization of India's leading oil E&P organization, the ONGC. Simultaneously, there were steps taken for the enhancement of production on the Bombay High oil fields as the result of a INR 150 billion development investment.

One of Asia's largest oil E&P companies, ONGC became a publicly held company as of February 1994, following the Indian government's decision to privatize. This privatization was conceived and achieved (sweat equity) to a great extent by ONGC’s influential Association of Scientific and Technical Officers (ASTO). Eighty percent of ONGC assets were subsequently owned by the government, the other 20% were sold to the public. At this time, ONGC employed 48,000 people and had reserves and surpluses worth INR 104.34 billion, in addition to its intangible assets. The corporation's net worth of INR 107.77 billion was the largest of any Indian company.

After its initial privatization, ONGC had authorized capital of INR 150 billion: it also met its need to raise INR 35 billion to invest in viable oil and gas projects. The Asian Development Bank (ADB) had also set a deadline for privatizing and restructuring at 30 June 1994, if loans were to be granted for development of two ONGC projects. As a consequence of the successful privatization, the loans were granted - US$267 million for development of Gandhar Field, and US$300 million for the gas flaring reduction project in the Bombay Basin. The successfully formulated and implemented privatization strategy put ONGC at par with other large multinational and domestic oil companies.

International rankings

ONGC is ranked as Asia’s best Oil & Gas company, as per a recent survey conducted by US-based magazine ‘Global Finance’

Economic Times 500, Business Today 500, Business Baron 500 and Business Week recognizes ONGC as most valuable Indian corporate, by Market Capitalization, Net Worth and Net Profits.

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ONGC ranks 3rd Oil & Gas Exploration & Production (E&P) Company in the world and 23rd among leading global energy majors as per Platts 250 Global Energy Companies List for the year 2009

ONGC ranks 24th among the Global publicly-listed Energy companies as per ‘PFC Energy 50” (Jan 2008) Finance Asia 100 list ranks ONGC no 1 among Indian Blue Chips. Occupies 155th rank in “Forbes Global 2000” list 2010 of the world’s biggest companies for 2010 based on

sales, profits, assets and market capitalisation. ONGC ranked 402nd position as per Fortune Global 500 - 2009 list;, based on revenues, profits, assets and

shareholder’s equity.

Represents India’s Energy Security

ONGC has single-handedly scripted India’s hydrocarbon saga by :

Establishing 6.89 billion tonnes of In-place hydrocarbon reserves with more than 300 discoveries of oil and gas; in fact, 6 out of the 7 producing basins have been discovered by ONGC: out of these In-place hydrocarbons in domestic acreages, Ultimate Reserves are 2.42 Billion Metric tonnes (BMT) of Oil Plus Oil Equivalent Gas (O+OEG).

Cumulatively produced 803 Million Metric Tonnes (MMT) of crude and 485 Billion Cubic Meters (BCM) of Natural Gas, from 111 fields.

ONGC has bagged 120 of the 238 Blocks (more than 50%) awarded in the 8 rounds of bidding, under the New Exploration Licensing Policy (NELP) of the Indian Government. ONGC has bagged 17 out of 31 blocks awarded in NELP round VIII (14 as operator).

ONGC’s wholly-owned subsidiary ONGC Videsh Ltd. (OVL) is the biggest Indian multinational, with 40 Oil & Gas projects (9 of them producing) in 15 countries, i.e. Vietnam, Sudan, Russia, Iraq, Iran, Myanmar, Libya, Cuba, Colombia, Nigeria, Nigeria Sao Tome JDZ, Egypt, Brazil, Syria and Venezuela. OVL had invested around Rs 50,000 Crores (Approx 10 billion US dollars).

India’s Most Valuable Public Sector Enterprise

Ranked at 2nd position in FE500 list 2010 in net worth and overall composite ranking. ONGC & MRPL won 6 Oil Industry Safety Awards for 2008-09 instituted by OISD, MOP&NG. Ranked at top of the Best companies to work for in Core Sector by Business Today in Feb 2010 edition. Golden Peacock Global Award 2007 for Excellence in Corporate Governance 2009”, conferred by World

Council of Corporate Governance, London. Bagged “BML Munjal Award” for Excellence in Learning & Development in Public Sector category. Bestowed with “Leadership for Business Excellence Award” for leveraging IT in Oil & Gas Sector by Amity

University. ONGC awarded with Gold Trophy for SCOPE Meritorious Award for Corporate Social Responsibility &

Responsiveness for the year 2007-08 and for R&D, Technology Development & Innovation for the year 2008-2009.

Given Best Overall Performance Award amongst the upstream Sector Oil Companies for Oil and Gas conservation programme for 2009 by PCRA

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Clinched Dalal Street investment Journal PSU awards 2010 for Excellent Overall Performance in the category of heavy weights and Highest Market Capitalisation in the category of wealth Builders

Rated ‘Very Good’ in MOU Performance Rating for 2008-09 by the Department of Public Enterprises, Ministry of Heavy Industries in Public Enterprises, GOI.

Pioneering Efforts

ONGC is the only fully–integrated petroleum company in India, operating along the entire hydrocarbon value chain:

• Holds largest share of hydrocarbon acreages in India.• Contributes over 79 per cent of Indian’s oil and gas production.• Refining capacity of about 12 MMTPA.• Created a record of sorts by turning Mangalore Refinery and Petrochemicals Limited around from being a stretcher case for referral to BIFR to the BSE Top 30, within a year. • Interests in LNG and product transportation business.

Competitive Strength

All crudes are sweet and most (76%) are light, with sulphur percentage ranging from 0.02-0.10, API gravity range 26°-46° and hence attract a premium in the market.Strong intellectual property base, information, knowledge, skills and experience

• Maximum number of Exploration Licenses, including competitive NELP rounds. ONGC has bagged 120 of the 238 Blocks awarded in the 8 rounds of bidding, under the New Exploration Licensing Policy (NELP) of the Indian Government. ONGC has begged 17 out of 31 blocks awarded in NELP round VIII(14 as operator).

• ONGC owns and operates more than 22000 kilometers of pipelines in India, including nearly 4500 kilometers of sub-sea pipelines. No other company in India, operates even 50 per cent of this route length.

Strategic Vision: 2001-2020

To focus on core business of E&P, ONGC has set strategic objectives of:

Doubling reserves (i.e. accreting 6 billion tonnes of O+OEG). Improving average recovery from 28 per cent to 40 per cent. Tie-up 20 MMTPA of equity Hydrocarbon from abroad.

The focus of management will be to monetise the assets as well as to assetise the money.

Sourcing Equity Oil Abroad 12

ONGC’s overseas arm ONGC Videsh Limited (OVL), continued to maintain robust growth during 2009-10. The First oil from BC-10 deepwater field in Brazil commenced from 12th July 2009 and currently producing

at a rate of about 72,500 bopd. Production up from 6,000 bpd to 16.700 bpd from Imperial Energy fields in Russia. At close of the financial year 2009- 10, the Proved and Probable reserves (2P) of OVL stood at 357

MMTOE, the second largest holding of proven oil and gas reserves (2P) by any Indian Company, next only to ONGC.

Consortium of OVL acquired 40% in Carabobo Venezuela in May 2010 for developing Carabobo 1 Norte & Carabobo 1 Centre blocks.

The company now has participation in 40 projects in 15 countries. Out of 40 Projects, OVL is operator in 17 projects and joint operator in 6 projects in 11 countries. OVL is currently producing oil and gas from Block 6.1 in Vietnam, Greater Nile Oil Project and Block 5A in Sudan, Imperial Energy and Sakhalin-I Project in Russia, Mansarovar Energy Project in Colombia, Al Furat Project in Syria, PIVSA in Venezuela and Block BC-10 in Brazil. While 7 projects are under development, 23 projects are in exploration phase.

OVL’s produced 8.87 MMTOE during FY 2009-2010, its highest ever production of oil and oil-equivalent gas (O+OEG). Consolidated turnover of OVL stood at 154.64 billion and OVL made a profit of Rs 20.90 billion.

ONGC’s strategic objective of sourcing 20 million tonnes of equity oil abroad per year is likely to be fulfilled well before 2020.

Frontiers Of Technology

• State-of-the-art seismic data acquisition, processing and interpretation facilities

• Uses one of the Top Ten Virtual Reality Interpretation facilities in the world

• Alliances with Transocean, Schlumberger, Halliburton and Baker Hughes, IPR, Petrobras, Norsk, ENI, Shell

• One of the biggest ERP implementations in the Asia13

Best In Class Infrastructure And Facilities

• ONGC’s success rate is at par with the global norm and is elevating its operations to the best in class level, with the modernization of its fleet of drilling rigs and related equipment.

• ONGC has adopted Best-in-class business practices for modernization, expansion and integration of all Info-com systems.

Onshore

• Production Installations :- 240

• Pipeline Network (km) :-17,500

• Drilling Rigs :- 69

• Work Over rigs :- 59

• Well Stimulation unit :-99

• Seismic survey crew :- 34

• Logging Units :- 32

• Engineering Workshops :- 2

• Virtual Reality Centre :- 5

• Regional Computer Centre :- 5

Offshore

•Well Platforms :- 160

• Well-cum-Process Platforms :- 5

• Water Injection Platform :- 7

• Process Platforms :- 22

• Well Stimulation unit :-7

• Drilling Rigs :- 9

• Pipeline Networks (km) :- 4,500

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• Offshore Supply Vessels :- 73

• Multi Purpose Support Vessel :- 6

• Seismic Vessels :- 1

Financials (2009-10)

ONGC posted a net profit of Rs. 167.68 billion despite volatile oil markets and crude prices.

• Net worth Rs. 864 billion • Practically Zero Debt Corporate• Contributed over Rs. 281 billion to the exchequer

The Road Ahead

ONGC looks forward to become an integrated energy provider, with:

• New Discoveries and fast track development• Equity Oil from Abroad• Downstream Value Additions & Forward Integration• Leveraging state-of-the art technology and global best practices • New Sources of Energy • Production from small and marginal fields

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INTRODUCTION ABOUT NEW EXPLORATION LICENCING POLICY (NELP) :

The New Exploration Licensing Policy (NELP) was launched by the Government for accelerating the pace

of hydrocarbon exploration in the country. India is seeking private capital and technology in hydrocarbon exploration as it currently imports about 70-80 per cent of its crude oil requirements. The government has so far awarded 235 blocks under NELP, launched in 1999 and promises equal treatment to both public and private sector firms.

The Ministry of Petroleum & Natural Gas (MOP&NG), on behalf of the Government of India, launched the ninth round under the New Exploration Licensing Policy (NELP IX) on 15 October 2010.

The NELP IX Round attracted a total of 74 bids for 33 out of the 34 blocks on offer. Of the 15 offshore blocks and 19 onshore blocks, single bids were placed for 10 offshore and four onshore blocks respectively. On the other hand, all nine Type-S (area not exceeding 200 square kilometres) blocks received bids with eight blocks receiving multiple bids.

Evaluation of bids is underway and the blocks are expected to be awarded within three months, with contracts being signed subsequently within a month from the award of the blocks.

The New Exploration Licensing Policy (NELP) was formulated in 1997-1998 to boost hydrocarbons exploration in the country. It was designed to provide a level playing field where exploration licences would be granted through international competitive basis to foreign and national oil companies (NOCs).

NELP was first implemented in January 1999 and, to date, eight rounds have been completed with the Ninth Round launched in October 2010.

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Location of blocks provisionally awarded under NELP IX. Source: PetroView®

Need for NELP:

Freedom for operators to market crude oil and gas in the domestic market at market determined price. Up to 100% participation by foreign companies. No signature, discovery or production bonus. Income Tax Holiday for seven years from start of commercial production. No mandatory state participation. Biddable cost recovery limit up to 100%. Large sedimentary areas remained un-explored/ under explored in the country Ever increasing demand supply gap. Requirement of vast capital investment. Early application of prudent & appropriate technology. Need for acceleration in existing leads & commercialization and development of existing discoveries.

SALIENT FEATURES OF NEW EXPLORATION LICENSING POLICY (NELP)

1. There will be no mandatory state participation through ONGC/OIL nor will there be any carried interest of the State.

2. ONGC and OIL to compete for obtaining the petroleum exploration licenses on competitive basis instead of the existing system of granting them petroleum exploration lease (PEL)s on nomination basis. At the same time, ONGC and OIL will also get same fiscal and contract terms as available to private companies.

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3. Open availability of exploration acreages to provide a continuous window of opportunities to oil companies. The acreages will be demarcated on a grid system and pending preparation of the grid, blocks will be carved out for offer.

4. Freedom to the contractors for marketing of crude oil and gas in the domestic market.5. Royalty payments at the rate of 12.5% for the onland areas and 10% for offshore areas. Half of the

royalty from the offshore area will be credited to a hydrocarbon development fund to promote and fund exploration related activities, such as acquisition of geological data on poorly explored basins, promotion of investment opportunities in the upstream sector, institution building etc.

6. To encourage exploration in deep water and frontier areas royalty will be charged at half the prevailing rate for normal offshore area for deep water areas beyond 400 m bathymetry for the first 7 years after commencement of commercial production.

7. Cess, which was earlier levied on crude production has been abolished for the blocks offered under NELP.

8. Companies are exempted from payments of import duty on the goods imported for petroleum operations.

9. There are no signature, discovery and production bonuses. 10. A seven year tax holiday from the date of commencement of commercial production. 11. Contractor is provided fiscal stability during the entire period of contracts.12. A separate Petroleum Tax Guide is in place to facilitate investors.13. A revised model contract is in place.

Initial exploration period will be four years and total exploration period seven years in respect of onland and shallow water blocks. But, in respect of deepwater and frontier areas (the Northeast and less-explored basins), initial exploration period will be five years and total exploration period eight years.

The ceiling limits for procurement procedures of goods and services have been increased, considering the rise in input cost in the international market. Maximum points earmarked for 2D seismic evaluation will be awarded to bidders offering to undertake 3D seismic work for the entire block. The 2D seismic Mandatory Work Programme (wherever applicable) will be waived in case bidders offer to undertake 3D seismic work for the entire block.

The exploration coverage of India’s sedimentary basin has expanded from 11 per cent to 58 per cent after the introduction of the NELP regime. The discoveries made under NELP have resulted in in-place hydrocarbon reserve accretion of a staggering 642 million tonnes of oil and oil equivalent gas.

Prior and written consent of the government will be mandatory for those who get oil and gas blocks from it in future to sell shares to the extent of ownership change.

The petroleum ministry has modified the terms of the model production sharing contract that successful bidders in the forthcoming auction of oil and gas blocks are expected to sign so that they cannot sell shares in them leading to ownership change without the government's “prior written consent.”

The move is apparently prompted by the proposed acquisition of Cairn India by UK-based Vedanta Resources. British oil giant Cairn Energy initially maintained that government approval for ownership change in its Indian arm was not required because it was a share sale and not a transfer of assets. The company, however, subsequently applied for state approval after the petroleum ministry clarified its approval was essential to consummate the deal.

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The revised section 28.2 dealing with share sale-triggered management change as well as the licensee's change in relationship with its parent who has given bank, financial and performance guarantees, says that prior written consent of the government is essential for these changes. Existing model contract only speaks about 'government consent', but not 'prior written consent.'

The idea is to safeguard against transfer of ownership of the entity that operates a field or of a consortium member without the state’s knowledge, said a person familiar with the development.

The ministry has also decided to encourage small and medium-sized oil and gas explorers for small-sized onshore fields. This is sought to be achieved by dropping technical capability of the bidder as a pre-qualification criteria. In the forthcoming auctions, small and medium-sized explorers will be assessed only on the basis of the exploration work that they commit to undertake and on the basis of their financial bids. The proposed investments from these companies are expected to be around $1.1 billion almost similar to NELP 8.

Greater clarity on tax issues and a longer duration for exploration being offered to bidders are likely to attract more domestic firms this time around. New and smaller players will be drawn to shallow water blocks being offered off Gujarat, Maharashtra and Kerala that do not require as much technological expertise as the rest.

Dilip Khanna, partner (oil and gas practice) at audit and consulting firm Ernst and Young, also said the blocks on offer should elicit interest from established Indian oil companies as well as new entrepreneurs looking to enter the upstream business.

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SECTION- C

JOINT OPERATING PROCEDURE

A joint venture (J.V.) is a new corporation formed through the participation of two or more companies in an enterprise in which each party contributes assets, owns the equity (property of the J.V. such as equipment, buildings, capital, etc.) to some agreed upon degree, and shares the risks and benefits of the new enterprise. The key to a successful joint venture is sharing of a clearly defined common business objective.

The purpose of a joint operating agreement (JOA) is to protect a business from failure, yet prevent monopolization within an industry by allowing each party to retain some form of separate operation. JOAs are used in the newspaper, HEALTH CARE, gas and oil, and other industries.

Joint Venture companies are the most preferred form of corporate entities for Doing Business in India. There are no separate laws for joint ventures in India. The companies incorporated in India, even with up to 100% foreign equity, are treated the same as domestic companies. A Joint Venture may be any of the business entities available in India.

A typical Joint Venture is where:

1. Two parties, (individuals or companies), incorporate a company in India. Business of one party is transferred to the company and as consideration for such transfer, shares are issued by the company and subscribed by that party. The other party subscribes for the shares in cash.

2. The above two parties subscribe to the shares of the joint venture company in agreed proportion, in cash, and start a new business.

3. Promoter shareholder of an existing Indian company and a third party, who/which may be individual/company, one of them non-resident or both residents, collaborate to jointly carry on the business of that company and its shares are taken by the said third party through payment in cash.

Advantages of international joint ventures:

Advantages of JV's for the international investing company:

Advantages of JV's for the host country and corporation:

1) Chance to penetrate a new market

2) Chance to sell technology, processes, equipment, consulting services, etc.

3) Chance to invest capital and get return streams for many years

4) Take advantage of the expertise in the local market of the host country company

5) Chance for growth

1) Chance to gain up-to-date technological and managerial know-how

2) Chance to create new industries, skills, training, etc.

3) Chance for increased employment

4) Chance to get important return streams for many years

5) Chance for growth

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Drawbacks of JVs :

Drawbacks of JV's for the international investing company:

Drawbacks of JV's for the host country and corporation:

1) Rapid change in the host country political or economic situation can create substantial losses for the investing corporation

2) Differences in culture and management style can create problems between the partners over settlement of claims, valuation of assets and liabilities, etc.

3) Adverse publicity in local and international media can damage the image and reputation of a company.

1) If the host country is perceived as a difficult marketplace, foreign investors may avoid doing business there.

2) The international partner might not deliver on all the promises made.

Joint Venture Group

ONGC has recognized the need to expand its business through profitable ventures related to petroleum and energy sectors by entering into joint ventures with other Indian and foreign companies. ONGC-Joint venture group (ONGC-JVG) has been formed to give impetus to joint venture activities in areas other than E&P.

ONGC-JVG is responsible for identification and developing new business opportunities with Indian and foreign companies in following areas:

Participation in downstream projects like refining/ gas processing /LNG/ power projects etc.

Participation in construction projects, pipelines, process plants etc.

EXCOM Group

The EXPLORATION CONTRACT MONITORING (EXCOM) Group is the exclusive business face of ONGC for jointly operated oil & gas exploration and production ventures within India. It is the nodal agency of ONGC for single window E&P business communication with companies and the government. Its functions include:

Evaluation and negotiations of bids pertaining to exploration acreages and development of discovered fields under joint venture.

Negotiations, of production sharing contracts (PCS) and joint operation agreements (JOA) with parties to the contract.

Monitoring and co-ordination

Providing opportunities to companies for assessment of prospectively of Indian basins andinvestment decisions through its New Delhi office

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JOINT VENTURE MANAGEMENT STRUCUTURE

The Joint Venture management structure is designed to fit the needs of a particular joint venture.

The joint venture management structure includes:

a. 4 sub-committees (Exploration, Development, Field technical and financial/legal) and

b. 3 work groups (Field Reservoir Engineering/ Geological & Geophysical (G&G)/ Drilling, Field commercial; and Field Satellite Development)

This schedule aims to show each main activity the specialities/ disciplines.

Jointly controlled assets

22

23

24

25

Jointly Controlled Assets

26

List of Blocks surrendered during the year are given below:-

PRODUCTION SHARING CONTRACT-AB-YBB-2011/21

Article 3 – License and Exploration Period

1. The Exploration Period shall begin on the Effective Date and shall consist of three Exploration Phases,each phase not exceeding three Contract Years, for a total period not exceeding eight (8) consecutive Contract Years unless extended pursuant to the terms of the Contract.

2. Except as otherwise provided in this Contract, the term of the first Exploration Phase shall not exceed three (3) consecutive Contract Years (hereinafter referred to as first Exploration Phase).

3. Except as otherwise provided in this Contract, the term of the second Exploration Phase shall not exceed three (3) consecutive Contract Years from the end of the first Exploration Phase (hereinafter referred to as second Exploration Phase).

4. Except as otherwise provided in this Contract, the term of the third Exploration Phase shall not exceed two (2) consecutive Contract Years from the end of the second Exploration Phase (hereinafter referred to as third Exploration Phase).

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Article 5 – Work Programme

1. The Contractor shall commence Petroleum Operations not later than six(6) months from the Effective Date.

2. During the currency of the first Exploration Phase, as per Article 3.2 the contractor shall complete the following Work Programme:

(a) a seismic programme consisting of the acquisition ,processing and interpretation of 1400 line kilometres of 2D seismic data in relation to the exploration objectives.

(b) reprocessing of 300 line kilometres of seismic data.

(c) Acquisition, processing and interpretation of 20,000 stations of Gravity- Magnetic data.

(d) G&G study for technical assessment.

3. During the currency of the second Exploration Phase, as per Article 3.3, the Contractor shall complete the following Work Programme:

(a) Reprocessing of 500 line kilometres of seismic data.

(b) G&G study for technical assessment.

(c) One Exploration Well at water depth 1001-1500m to one of the following depths:

(i) 3000 metres and/or to the formation of Pliocene age

(ii) To basement;

(iii) That point below which further drilling becomes impracticable due to geological conditions encountered and drilling would be abandoned by a reasonable prudent operator in the same or similar circumstances. Abandonment of drilling under this provision by the Contractor would require unanimous approval of the Management Committee.

4. During the currency of the third Exploration Phase, as per Article 3.4, the Contractor shall complete the following Work Programme:

(a) Reprocessing of 500 line kilometres of seismic data.

(b) G&G study for technical assessment.

(c) One Exploration Well at water depth 1001-1500m to one of the following depths:

(i) 3500 metres and/or to the formation of Pliocene age

(ii) To basement;

(iii) That point below which further drilling becomes impracticable due to geological conditions encountered and drilling would be abandoned by a reasonable prudent operator in the same or similar circumstances. Abandonment of drilling under this

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provision by the Contractor would require unanimous approval of the Management Committee.

Article 6 – Management Committee

1. There shall be constituted a committee to be called the Management Committee with functions as stated herein below.

2. Government shall nominate two members representing Government in the Management Committee, whereas each Company constituting Contractor shall nominate one member each to represent Company in the Management Committee provided that in case Contractor constitutes only one Company, that Company shall have two members.

3.Each Party may nominate alternate members with full authority to act in the absence and on behalf of the members nominated under Article 6.2 and may at any time nominate another member or alternate member to replace any member nominated earlier by notice to other members of the Management Committee.

4. One representative of the Government shall be designated as the Chairman of the Management Committee and the second representative of the Government shall be designated as the Deputy Chairman. The member of the Operator, or the member designated by the Operator has two members in the Management Committee shall be designated as the Secretary of the Committee.

5.Operator on behalf of the Contractor with the approval of the Operating Committee shall submit following matters to the Management Committee for the review and it shall have advisory functions :

(a) The annual Work Programmes and Budgets in respect of Exploration Operations and any revisions or modifications thereto.

(b) Proposals for surrender or relinquishment of any part of the Contract Area by the Contractor;

(c) Proposals for an Appraisal Programme or revisions or additions thereto and the declaration of a Discovery as a Commercial Discovery.

(d) Any other matter required by the terms of this Contract to be submitted to it for review or advice;

(e) Any other matter which the Contractor decides to submit for review or advice including matters concerning inter-Party relationships;

6. The following matters shall be submitted by Operator on behalf of the Contractor with the approval of Operating Committee to the Management Committee for approval:

(a) Annual Work Programmes and Budgets in respect of Development Operations and Production Operations and any modifications or revisions thereto:

(b) Proposals for the approval of the Development Plans may be required under this Contract or modifications or revisions to a Development Plan;

(c) Determination of a Development Area;

(d) Appointment of auditors, approval and adoption of audited accounts;

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(e) Collaboration with licensees or contractors of other areas;

(f) Claims or settlement of claims for or on behalf of or against the Contractor in excess of limits fixe by the Management Committee from time to time;

(g) Plans for the production of Crude Oil and Natural Gas prior to the date of commencement of Commercial Production;

(h) Proposal about abandonment plan Site Restoration as required to be submitted under Article 14.10;

(i) Any other matter required by the terms of this contract to be submitted for the approval of the Management Committee;

(j) Any other matter which the Contractor decides to submit to it;

(k) Any matter which the Government refers to the Management Committee for its consideration and reasoned opinion.

Article 7 – Operatorship, Operating Agreement and Operating Committee

1. ONGC shall be the Operator for the purpose of carrying out Petroleum Operations pursuant to this Contract during the term of the Contract.

2. No change in the operatorship shall be effected without the consent of the Government and such consent shall not be unreasonably withheld.

3. The functions required of the Contractor under this Contract shall be performed by the Operator on behalf of all constituents of the Contractor subject to, and in accordance with, the terms and provisions of this Contract and generally accepted Good International Petroleum Industry Practice Provided, however, that this provision shall not be construed as relieving the constituents of Contractor from any obligations or liability under the Contract.

4. Within fifteen days of the Effective Date or such longer period as may be agreed to by Government ,the Companies constituting Contractor shall execute an Operating Agreement The said agreement shall be consistent with the provisions of this Contract and shall provide for among other things:

(a) The appointment, resignation, removal and responsibilities of the Operator;

(b) The establishment of an Operating Committee comprising of an agreed number of representatives of the Companies chaired by a representative of the Operator;

(c) Functions of the said Operating Committee taking into account the provisions of the Contract, procedures for decision making, frequency and place of meetings and

(d) Contribution to costs, defaults, sole risk, disposal of Petroleum and assignment as between the Parties to the Operating Agreement.

4.1 Operator shall provide to Government a copy of the duly executed Operating Agreement within 30 days of the Effective date or such longer period as may be agreed to by Government.

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4.2 In case a single Company constitutes the Contractor, the provisions of Article 7.4 and 7.4.1 shall not be applicable. However, in case of increase in the number of constituents of Contractor, the provisions of Article 7.4 and 7.4.1 shall apply from the date of such increase in the number of the constituents.

Classification, Definition and Allocation of Costs and Expenditures

1. Segregation of Costs

Costs shall be segregated in accordance with the purposes for which such expenditures are made. All Costs and expenditures allowable under Section 3, relating to Petroleum Operations, shall be classified, defined and allocated as set out below in this section.

2. Exploration Costs

Exploration Costs are all direct and allocated indirect expenditures incurred in the search for Petroleum in an area which is, or was at the time when such costs were incurred, part of the Contract Area, including expenditures incurred in respect of :

2.1 Aerial, geophysical, geochemical, paleontological, geological, topographical and seismic surveys, analysis and studies and their interpretation.

2.2 Core hole drilling and water Well drilling.

2.3 Labour, materials, supplies and services used in drilling Wells with the object of finding Petroleum or in drilling Appraisal Wells provided that if such Wells are completed as producing Wells or injection well for enhancing oil recovery, the costs of completion thereof shall be classified as Development Costs.

2.4 Facilities used solely in support of the purposes described in sections 2.2,2.2 and 2.3 above, including access roads, all separately identified.

2.5 Any Service Costs and General and Administrative Costs directly incurred on exploration activities an identifiable as such and a portion of the remaining Service Costs and General and Administrative Costs allocated to Exploration Operations determined by the proportionate share of total Contract Costs (excluding General and Administrative Costs and Service Costs) represented by all other Exploration Costs.

2.6 Geological and geophysical information purchased or acquired in connection with Exploration Operations.

2.7 Any other expenditures incurred in the search for Petroleum not covered under Sections 2.3 or 2.4.

3. Development Costs

Development Costs are all direct and allocated indirect expenditures incurred with respect to the development of discoveries within the Contract Area including expenditures incurred on account of:

3.1 Drilling Development Wells, whether these Wells are dry or producing and drilling Wells for injection of water or Gas to enhance recovery of Petroleum.

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3.2 Completing of Exploration Wells by way of installation of casing or equipment or otherwise or for the purpose of bringing a Well into use as a producing Well or as a Well for injection of water or Gas to enhance recovery of Petroleum.

3.3 Purchase, installation or construction of production, transport and storage facilities for production of Petroleum, such as pipelines, flow lines, production and treatment units, wellhead equipment, subsurface equipment, enhanced recovery systems, offshore and onshore platforms, export terminals and piers, harbours and related facilities and access roads for Production activities.

3.4 Engineering and design studies for facilities referred to in Section 3.3

3.5 Any Service Costs and General and Administrative Costs directly incurred in Development Operations and identifiable as such and a portion of the remaining Service Costs and General and Administrative Costs allocated to development activities, determined by the proportionate share of total Contract Costs (excluding General and Administrative Costs and Service Costs) represented by all other Development Costs.

4. Production Costs

Production Costs are expenditures incurred on Production Operations after the start of production from the Field (which are other than Exploration and Development Costs). The balance of General and Administrative Costs and Service Costs not allocated to Exploration Costs or Development Costs shall be allocated to Production Costs.

5.Service Costs

Service Costs are direct and indirect expenditures incurred in support of Petroleum Operations in the Contract Area, Including expenditures on warehouses, piers, marine vessels, vehicle, motorized rolling equipment, aircraft fire and security stations, workshops, water and sewerage plants, power plants, housing, community and recreational facilities and furniture and tools and equipment used in these activities. Service Costs in any year shall include the costs incurred in such Year to purchase and/or construct the said facilities as well as the annual costs of maintaining and operating the same, each to be identified separately. All Service Costs shall be regularly allocated as specified in Sections 2.5,3.5 and 4 to Exploration Costs, Development Costs and Production Costs and shall be separately shown under each of these categories Where Service Costs are made in respect of shared facilities; the basis of allocation of costs to Petroleum Operations hereunder shall be specified.

6.General and Administration Costs

General and Administrative Costs are expenditures incurred on general administration and management primarily and principally related to Petroleum Operations in or in connection with the Contract Area, and shall include:

6.1 main office, field office and general administrative expenditures in India including supervisory, accounting and employee relations services:

6.2 an annual overhead charge for services rendered by the parent company or an Affiliate to support and manage Petroleum Operations under the Contract, and for staff advice and assistance including financial, legal, accounting and employee relations services but excluding any remuneration for services charged separately under this Accounting Procedure, provided that :-

32

(i) for the period from the Effective Date until the date on which the first Development Plan under the Contract is approved by the Government, this annual charge shall be the Contractor’s verifiable expenditure but shall in no event be greater than the following percentages of the total Contract Costs incurred during the Contract Year in or in connection with the Contract Area and qualifying for recovery pursuant to Section3:

Contract Costs in any Contract Year (in million USD) Annual Overhead charge0-2 3%Over 2-5 USD 60,000 + 2% of Contract Costs in excess of USD 2

millionOver 5 USD 120,000 + 1% of Contract Costs in excess of USD 5

million.

(ii) from the date on which first Development Plan is approve, the charge shall be at an amount or rate to be agreed on between the Parties and stated in the Development Plan.

6.3 All General and Administrative Costs shall be regularly allocated as specified in Sections 2.5, 3.5 and 4 to Exploration Costs, Development Costs and Production Costs respectively, and shall be separately shown under each of these cost categories.

DESCRIPTION OF THE CONTRACT AREA

The area comprising approximately 9,940 Sq.km., offshore India identified as Block AB-YBB-2011/21 described here.

Longitude and latitude measurements commencing at points A, B, C, D, E,F,G and H are given below:

Coordinates Longitudes LatitudePt. Deg. Min. Sec. Deg. Min. Sec.

A 16 56 17 82 59 59B 16 30 00 83 00 00C 16 30 00 84 00 00D 17 51 18 84 00 00E 17 47 25 83 56 39F 17 42 41 83 57 29G 17 33 14 83 40 38H 17 19 35 83 32 35A 16 56 17 82 59 59

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NELP BLOCK AB-YBB-2011/21,

JV--- ONGC- 85%, OIL- 15%.

NELP 1, SIZE IN SKM- 7455 After relinquishing 25% of 9940 skm (original) ;4970 after relinquishing 50% of 9940 skm

Effective Date of Contract – 19/05/2000

MWP Committed Carried Out up to March 2010

Planned 2010-11 Actual 2010-11 Remarks

Phase-1(19-05-2000 to 18-05-2003)Seismic (API)2D-1400 LKGM20000 stationsReprocessing300 LKWells-Nil

Phase-II(19-05-2003 to 18-05-2006)Seismic (API)3D-NilGMNilReprocessing500 LK

Wells:1 well-3000m(WD:1001-1500m)

Phase-III(19-05-2006 to 18-05-2008)Wells:1 Well- TD:4000 M(WD:>2000m)

Phase-1(19-05-2000 to 18-05-2003)

Seismic (API)

2D-1473 LK

GM

59883 stations

Reprocessing

2D-1180 LK

Wells : Nil

Phase-II(19-05-2003 to 18-11-2006)

Seismic (API)

2D : 924 LKM

3D-2012 SK

Seismic (AP)

3D-1475 SK

3D-897 SK OF 1265 SK

Wells-2

1) AB-YBB-2011/21-K-1

(DD7094m Water Depth-2678m)

2) AB-YBB-2011/21-A-1

(DD3779m Water Depth-778m)

Phase-III (19-11-2006 to 18-05-2008)

Phase-IIISeismic:

G & G StudiesContinuation of G & G interpretation of all seismic volumes of AB-YBB-2011/21

Well :Location AB-YBB-2011/21 NAC-A was released on 24.01.Drilling Completed.-AB-YBB-2011/21NAC-A(DD5000m Water Depth-2649.5m)

Phase-IIISeismic

G & G Studies:Post Drill analysis o AB-YBB-2011/21NAC is completed. G&G studies for rift fill prospect in totality of the block is completed

Well : 1

Submitted application seeking extension beyond exploration period to DGH on 4th April,2008 –BGEPIL WAS ASSIGNED a PI of 30% ON 13.05.2008.PI stands as ONGC-65%,OIL-15%, BGEPIL-30%Revised RE:2009-10,BE: 2010-11 was reviewed by MC.2nd Amendment to PSC still awaited.Drilling Holiday granted for the Block under RMP w.e.f 01.01.2008 to 31.12.2010.

MWP of the block completed.

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3D : 1933.456 SK

3D : 439.571 SK(A&F)

Processing

370SK(AreaG) completed

2230SK(A&F) completed

PSTM processing : Area G (1265 SKM)completed

PoSTM Merging A,B,C, F,AF,H : Completed

PSTM Processing : Area AF : (2230 SKM) Completed

3 SBL profiles Completed

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SECTION- D

JOINT VENTURE ACCOUNTING

The company has Joint Ventures in the nature of Production Sharing Contracts (PSC) with Government of India and various other body corporate for exploration, development and production activities. To minimize risks, companies develop partnerships called joint ventures. In some industries like oil and gas industry, certain ventures are considered as high risk, demanding extensive capital investment and a long payback period. A joint venture consists of an operating partner (operator) and one or more non-operating partners who combine monetary or personal resources to share a projects expenses and revenues. The operator manages the venture, arranges venture activities and maintains accounting records. The operator remits venture expenses, collects revenues and distributes these to the partners according to their ownership shares. This process is known as Joint Venture Accounting(JVA).

ACCOUNTING PRINCIPLES FOR OIL AND GAS PRODUCING ACTIVITIES

The financial accounting procedures for petroleum E&P activities are successful efforts or full cost.

Successful Effort Methods:

The successful method effort has only the cost of successful efforts capitalized as oil and gas properties. Costs of exploratory dry holes, geological and geophysical cost in general, daily rentals and other property carrying costs are expensed. The net-unamortized capitalized costs are also amortized over proved reserves and property development costs are amortized over proved developed reserves. Amortization is completed by lease (or property) or certain aggregations of properties as large as a field.

Full Cost Method

In full cost method all property acquisition, exploration and development cost, even dry hole costs, are capitalized as oil and gas properties. These costs represent fixed assets, amortized on a country by country basis using a unit of production method based on volumes produced and remaining proved reserves. The net un amortized capitalized cost of oil and gas properties less related deferred income taxes may not exceed a ceiling consisting primarily of a computed present value of projected future cash flows, after income taxes, from the proved reserves. If a company drills five exploratory wells for $1Million each and only one finds proved reserves, the successful efforts method recognizes a $1 Million asset, where as the full cost method would recognize a $5 Million asset. However investors and stock analysts should be concerned about what the real asset or reserves worth an amount that may be substantially different from the capitalized historical cost.

CLASSIFICATION

The distinguishing features of the successful efforts and the full cost methods are;

1. Property acquisition cost

2. Exploration cost

3. Development cost

4. Production cost

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Support facilities and equipment’s, such as trucks, field service units, warehouses, camp facilities and other facilities, may serve more than one of the four functions of acquisition, exploration, development and production. The facilities and equipment costs are capitalized and the related depreciation and operating cost are allocated to those functions. Depreciation of the capitalized facilities and equipment costs, as well as related operating expenses, are allocated as cost of acquisition, exploration, development or production.

ACQUISITION COST

Acquisition costs include costs incurred to purchase, lease or otherwise acquire a property or (mineral right). They encompass lease bonuses, options to purchase or lease properties, the portion of costs applicable to minerals when land mineral rights are purchased in fee, broker’s fees, recording fees, legal costs and other costs incurred in obtaining mineral rights.

The costs are initially capitalized as unproved property acquisition cost. Unproved property refers to unevaluated property i.e. property not yet evaluated as to whether it has proved reserves. The evaluation of the property through exploration, drilling or lapse of lease if no proved reserves are found, the acquisition cost are removed from the unproved property account and become cost of abandoned or worthless property.

EXPLORATION COST

Exploration cost are those cost incurred In (1) identifying areas that may warrant examination and (2) examining specific areas that possibly contain oil and gas reserves, including drilling exploratory wells and exploratory type stratigraphic test wells. Exploration cost may be incurred before and after the related property is acquired. Exploration cost include cost of topographical or geophysical studies and salaries and other expenses of geologists, geophysical crews ad other persons conducting these studies. Exploration costs also include the cost of carrying and retaining un-developed properties, such as delay rentals and ad valorem taxes on properties. Dry-hole contribution’s and bottom-hole contributions are also included in exploration cost.

DEVELOPMENT COST

Development cost are incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and gas. They include the cost of development wells to produce proved reserves as well as cost of production facilities, such as lease flow lines, separators, heaters, treaters, storage tanks, improved recovery system and nearby gas processing facilities.

PRODUCTION COST

Production cost are the cost of activities that involves lifting oil and gas to the surface and gathering treating, processing and storing in the field. Hence, in a broad sense, production cost includes all cost of acquisition, exploration, development and production. However for successful efforts and full cost accounting, the term production cost or lifting cost refers only to those costs incurred to operate and maintain wells, related equipment’s and facilities that logically by their nature are expensed as incurred as part of the cost of oil and gas produced. Production cost include the labour to operate the wells and facilities, repair and maintenance expense, materials and supplies consumed, ad valorem taxes and insurance on property and severance or production taxes.

37

JOINT INTEREST ACCOUNTING

The block under study is an operated joint venture and the operator has the following roles:-

1. Maintain files related to all joint operations

2. Prepares billings to joint owners

3. Reviews all billings to joint owners

4. Prepares statements for jointly operated properties

5. Prepares pay out status reports pursuant to farm-in and farm-out agreements

6. Arranges or conducts joint interest audits of billings and revenue distribution from joint venture operations.

7. Responds, for the company as operator, to joint interest audits by other joint interest owners.

BUDGETING AND WORK PROGRAMME

Subsequent to entering into PSU with the Government and JOA with the parties, the activities under the oil & gas exploration and procedure operations get initiated through the preparation and submission of the budgets and work programmes by the operators to each of the parties, OC and MC with in the time as stipulated in the PSU as well as the JOA.

PROCESS NARRATIVE

S.No Activities including control Responsibility1 Based on the Minimum Work Programme (MWP) a recommended

work programme for the financial year is prepared by the technical department. The work programme detailed the activities planned for the year which in turn forms the basis for the preparation of the recommended budget. The approved work programme with likely cost estimate is forwarded to the designated officer in JVG. The designated officer in finance JVG in consultation with the technical department prepares the recommended budget in an excel sheet. The following factors are factored in while budget preparation:

Planned activities Latest prices Details of capital requirements Contractual payments Stores and spares items

Number of hours, line kilometers to be surveyed, number of wells to be surveyed etcCertain activities not included in the MWP my also be incorporated

Designated officer, technical department and finance, JVG

38

in the budget if these are essential to the exploration. 2 The budget along with the work program is forwarded to the

competent authority in Finance department of the JVG for approval.

Competent authority, finance JVG

3 The budget and work programme are further forwarded to the block manager for approval

Block manager

4 Next, the budget and the work programme are forwarded to the basin manager for approval.

Basin manager

5 Upon approval of the basin manager, the budget and the work programme is forwarded to the OC for review and approval. The OC ensures whether planned activities during the year are as per the MWP. If required an explanation may be obtained for activities not planned in the MWP.

Operating manager

6 Upon review and approval of the budget and the work programme by the OC, the same is forwarded to the other JV partners (non-operators) for their review, deliberation and approval. After review, the budget and work programme is sent back to the OC by the other partners

Designated officer, finance, JVG

7 The OC approved budget and work programme are then forward to MC for its deliberation and final approval. For deviation between the work programme and the MWP the designated officer in JVG provides justification for the additional expenditure/activity. The MC finally approves the budget and work programme.Revised budget may be submitted to the OC and MC from time to time for approval of the same.

Management committee member

8 The approved budget and work programme is forwarded to DGH by finance, JVG within time lines specified In the PSC and the JOA.

Designated officer, Finance JVG

9 An annual AER has to be submitted to the OC for approval of expenditures with respect to exploration operations, drilling work over expenditure and plant and equipment. Each AER should identify the operation by specific reference to the applicable line items in the budget and work programme, describe the work in detail, contain the best estimate in total funds required to carry out such work, outline the proposed work schedule, provide a time table for anticipated cash calls and any other supporting information.

Designated officer, Finance JVG and operating committee.

39

FLOW CHART FOR BUDGETING AND WORK PROGRAMME.

40

AER

Once the annual budget, work programme and AER are approved, expenses in connection with the joint operations are incurred.

PROCESS NARRATION

Si.No ACTIVITIES INCLUDING CONTROL RESPONSIBILITY1 On commencement of activities on the field expense are

incurred. Those which are directly identifiable against the JV are charged to the JV/NELP get accumulated in the ONGC company code. Finally , at each quarter and these common cost get allocated to the JV/NELP

Designated officer, technical department designated officer, finance JVG.

2 Physical data of volume of work completed including man hour spent activity wise is obtained from the activity centres duly signed by the competent authority. Based on this information the designated officer in finance JVG prepares a block-wise activity report containing details of deployed data and forwards the same to the corporate accounts for cost allocation. Cost accounts are done on a quarterly basis after entering the physical data in SAP.

Designated officer, costing department, designated officer JVG.

3 Parent company overheads (PCO) are changed for operational ventures. The PCO amount is system calculated on the basis of actual expenses booked in the concerned cost object as per the respective Production Sharing Contract (PSC).

Designated officer, Finance JVG.

41

FLOW CHART FOR INCURRING EXPENDITURE AND ALLOCATION OF COST:

42

PREPARATION AND SUBMISSION OF INVOICES AND EXPENSE DETAILS

All expenses incurred by ONGC as an operator on behalf of other JV partners in carrying out the joint i=operations are borne and paid by the JV partners in proportion to their participating interests. Thus all expenses incurred by ONGC as an operator are subsequently reimbursed by non-this operators through preparation and submission of invoice and expense details. This is a statement of charges and credits specifying the expenses incurred against each budgeted activity and income generated during the course of operations. These have to be inline with the approved budget and AER.

FLOW CHART FOR PREPARATION AND SUBMISSION OF INVOICES AND EXPENSE DETAILS:

43

44

Total Invoice Details

Details of non-operators share of expense

Summary Statements

MEASUREMENT AND ANALYSIS

Computation of variance

The variance adopted is unique in the organisation. It has been formulated depending up on the nature of the expenditure the activity proposes. It may be broadly classified as follows.

API VARIANCE

Acquisition Cost Variance = Acquisition Price Variance + Acquisition Quantity Variance

Processing Cost Variance = Processing Price Variance + Processing Quantity Variance

Interpretation Cost Variance = Interpretation Price Variance + Interpretation Quantity Variance.

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SECTION- E

PIE-CHARTS, TABLES AND FIGURES

46

TOTAL EXPENDITURE FROM 2006-11(IN USD)

Expenditure 2006-07 2007-08 2008-09 2009-10 2010-11

Acquisition 22581083 6936513 -177954 -175396 0Processing 1864886 1343233 1167992 -1640 36296Interpretation 69606 692800 229284 613065 36178Environmental Studies

7233

0 0 0 0

OTHERS 0 0 0 0 0Geological & Geophysical

0 138126 77507 131806 249099Petroleum Exploration License Fee

166566 132190 105902 105606 543124G&A Cost 71004 45433 135794 197535 341617Well related Expenditure 310665 0 49986401 1118292Main Office Expense

320710 162883 451049 1846157 442097Total 25391753 9451178 1989574 52703534 2766703

47

Fig 1: TOTAL EXPENDITURE FOR THE YEAR 2006-07

48

Fig 2: TOTAL EXPENDITURE FOR THE YEAR 2007-08

49

Fig 3: TOTAL EXPENDITURE FOR THE YEAR 2008-09

50

Fig 4: TOTAL EXPENDITURE FOR THE YEAR 2009-10

51

Fig 5 : TOTAL EXPENDITURE FOR THE YEAR 2010-11

52

ANALYSIS :

In 2006-07, the amount spent on Acquisition was 89% of the total expenditure. Whereas the other attributes like Processing, Well Related Expenditure, Main Office Cost and Petroleum Exploration Licensing Fees were only 8%and 1% for rest of them respectively.

In 2007-08 also, for Acquisition a major chunk was spent which is 74%.This year Processing that happened was more than last year at 14%.Interpretation was 7% and Main Office Expense was 2% whereas PEL Fees ,G & G and G & A Costs were just 1% of the total expenditure.

In 2008-09, Processing took over with 55% as the acquired areas had to be drilled. So the Main Office Expense was 19% along with the Interpretation, that was 11%.The other expenditures were G&A, PEL Fees and G & G Cost being 6%, 5% and 4% respectively.

In 2009-10 though, the Well Cost Expenditure took the mammoth share of 94% whereas rest of the components like Main Office Expense was 4% along with G&A Cost and Interpretation being 1% each.

In 2010-11,the Well Cost Expenditure reduced to less than its half the previous year to 40%,PEL Fees took 19% of the share, Main Office Expense occupied 17%,G & A Cost increased to 13%, G & G became 9%,alongwith Processing and Interpretation which were 1% each.

In budgeting (or management accounting in general), a variance is the difference between a budgeted, planned or standard amount and the actual amount incurred/sold. Variances can be computed for both costs and revenues.

53

BUDGET V/S ACTUAL – AB-YBB-2011/21 FOR THE YEAR 2006-07 (In USD)

Particulars Budgeted Cost

Actual Cost

Variance Amount

Reasons Comments

G&A Cost 64121 71004 -6883 The variance is due to provision made for increase in employee benefits on account of pay revision arrears, leave salary, PRBS, etc allocated to activities as per company policy.

UNFAVOURABLE

PEL Fees 162065 166566 -4501 This is a statutory payment and the variation is within 10% of the budget as per the PSC.

UNFAVOURABLE

G&G 525543 7233 518310 The variance is due to provision made for increase in employee benefits on account of pay revision arrears, leave salary, PRBS, etc allocated to activities as per company policy.

FAVOURABLE

Acquisition 26195441 21081083 5114358 Budget provision was made for 102640 LKM. Payment was made for 91307.78 LKM. Hence the variance.

FAVOURABLE

Processing 3118790 1864886 1253904 Budget provision has been kept for 155793 LKM where as actual acquisition was confined to 78252 LKM due to logistic as well as block configuration. No variance, the change in INR is due to USD to Rupee conversion.

FAVOURABLE

Interpretation 224668 69606 155062 Variance is due to the Price and not due to quantity.

FAVOURABLE

Drilling 3998709 310665 3688044 FAVOURABLESea-bed Logging

1614504 1500000 114504 FAVOURABLE

Company Overhead

429038 320710 108328 As per Actuals FAVOURABLE

Total 36332879 25391753 10941126

54

NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2006-07 API VARIANCEParticulars Std Price Std

Quantity

Std Price per Unit

Actual Price

Actual Quantity

Actual Price per Unit

Price Variance

Quantity Variance

Cost Variance

1 2 3 4 5 6 7=5*(3-6) 8=3*(2-5) 9=(7+8)

Acquisition Cost2D Seismic Data Acquisition 429281 924 464.59 1372812 924

1485.73 -943531 0 -943531

3 D Seismic Data Acquisition

25766160 102640 251.03 19708271

91307.78 215.84

3213113.15

2844775.85 6057889

Processing Cost2D Processing

41190 1913 21.53 11461 924 12.40 8434.22 21294.78 29729

3D Processing

3077600 153880 20 1853425 77328 23.97 -306865 1531040 1224175

Interpretation CostComputing Services

224668 19252 11.67 69606 19252 3.62 155062 155062

TOTAL 29538899

23015575 2126213.37

4397110.63

6523324

55

TOTAL EXPENDITURE BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2006-07

56

ACQUISITION, PROCESSING AND INTERPRETATION COST AB-YBB-2011/21 FOR THE YEAR 2006-07

57

PEL FEES for AB-YBB-2011/21 FOR THE YEAR 2006-07

58

G & A COST FOR AB-YBB-2011/21 FOR THE YEAR 2006-07

59

G & G COST FOR AB-YBB-2011/21 FOR THE YEAR 2006-07

60

DRILLING COST FOR AB-YBB-2011/21 FOR THE YEAR 2006-07

61

BUDGET V/S ACTUAL – AB-YBB-2011/21 FOR THE YEAR 2007-08 (In USD)

Particulars Budgeted Cost

Actual Cost

Variance Amount

Reasons Comments

G&A Cost 28707 45433 -16726 The variance is due to provision made for increase in employee benefits on account of pay revision arrears, leave salary, PRBS, etc allocated to activities as per company policy.

UNFAVOURABLE

PEL Fees 121220 132190 -10970 This is a statutory payment and the variation is within 10% of the budget as per the PSC.

UNFAVOURABLE

G&G 308152 138126 170026 The variance is due to provision made for increase in employee benefits on account of pay revision arrears, leave salary, PRBS, etc allocated to activities as per company policy.

FAVOURABLE

Acquisition 8046649 6936513 1110136 Budget provision was made for 2430 SKM. Payment was made for 2191SKM. Hence the variance.Budget provision was kept for financial year 2007-08. The work was completed in 2006-07. Bill for 8 SKM was paid during 2006-07. Hence the variance.

FAVOURABLE

Processing 3332694 1343233 1989461 Budget provision has been kept for 2430 SKM where as actual acquisition was confined to 2190 SK due to logistic as well as block configuration. No variance, the change in INR is due to USD to Rupee conversion. Processing was carried out

FAVOURABLE

62

by in-house resources, provision was kept for 250SKM, where the actual volume is about 206 SKM hence the variance.Initially the processing was planned to be completed within the fiscal but spilled over to FY: 2008-09,hence the variance. The amount booked is for part of the volume only.

Interpretation 123000 692800 -569800 The variance is due to provision made for increase in employee benefits on account of pay revision arrears, leave salary, PRBS, etc allocated to activities as per company policy.

UNFAVOURABLE

Company Overhead

189604 162883 26721 As per actuals FAVOURABLE

Total 12150026 9271138 2878888

63

NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2007-08 API VARIANCEParticulars Std Price Std

Quantity

Std Price per Unit

Actual Price

Actual Quantity

Actual Price per Unit

Price Variance

Quantity Variance

Cost Variance

1 2 3 4 5 6 7=5*(3-6) 8=3*(2-5) 9=(7+8)

Acquisition Cost3 D Seismic Data Acquisition 8046649

448.15

17955.258

6936513

447.72 15492.97 1102415 7720.761 1110136

Processing Cost3D Processing

3332694 2430 1371.47901

1343233 2191 613.0685 1661678 327783.5 1989461

Interpretation CostComputing Services

123000 4954 25 692,800 4954 140 -569800 -569800

TOTAL 11502343 8972546 2194293 335504.3 2529797

64

TOTAL EXPENDITURE BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2007-08

65

ACQUISITION PROCESSING AND INTERPRETATION COST AB-YBB-2011/21 FOR THE YEAR 2007-08

66

G & A COST FOR AB-YBB-2011/21 FOR THE YEAR 2007-08

67

G & G COST FORAB-YBB-2011/21 FOR THE YEAR 2007-08

68

PEL FEES for AB-YBB-2011/21 FOR THE YEAR 2007-08

69

BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2008-09 (IN USD)

Particulars Budgeted Cost

Actual Cost

Variance Amount

Reasons Comments

G&A Cost

2411514 586843 1824671Expenditure incurred as per actuals. FAVOURABLE

PEL Fees

103542 105902 -2360

This is a statutory payment and the variation is with in 10% of the budget.Reason for variation primarily because of exchange rate variations over the period in which licence fees accruals were booked.

UNFAVOURABLE

Acquisition

  -207761 207761

Variation is on account of reversals on account of 3D seismic acquisition and processing activity completed in 2007-08.

NOT APPLICABLE AS

IT’S A REVERSAL OF

PREVIOUS YEAR

Processing

3890000  1165997 2724003Expenditure incurred as per actual activity. FAVOURABLE

R&D (Special Studies)

60000 29807 30193

Expenditure incurred as per actuals for high resolution biostratigraphy of drilled wells FAVOURABLE

G & G Support

171875 77507 94368

Expenditure incurred as per actuals. FAVOURABLE

Interpretation

459000 229284 229716

Expenditure incurred as per actuals.

FAVOURABLEWell Related Expenditure

32608696   32608696

Budget kept in the to mature category.No expenditure incurred in 2008-09 as per actual activity. FAVOURABLE

Total

39704627 

1989574 37717048

70

NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2008-09 API VARIANCEParticulars Std Price Std

Quantity

Std Price per Unit

Actual Price

Actual Quantity

Actual Price per Unit

Price Variance

Quantity Variance

Cost Variance

1 2 3 4 5 6 7=5*(3-6) 8=3*(2-5) 9=(7+8)

Acquisition Cost3D Seismic Data Acquisition Nil Nil Nil Nil Nil Nil Nil Nil Nil

Processing Cost3D Processing3D Special Processing (PSTM/AVO Inhouse)

3890000 10040 387.450 1165997 6744 172.894 1446967 1277036 2724003

Interpretation CostComputing Services 459000 3256 140.971 229284 3256 70.418 229716 0 229716

TOTAL4349000 1395281 1676683 1277036 2953719

71

TOTAL EXPENDITURE BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2008-09

72

ACQUISITION PROCESSING AND INTERPRETATION COST AB-YBB-2011/21 FOR THE YEAR 2008-09

73

G & A COST FORAB-YBB-2011/21 FOR THE YEAR 2008-09

74

G & G COST FOR AB-YBB-2011/21 FOR THE YEAR 2008-09

75

PEL FEES FOR AB-YBB-2011/21 FOR THE YEAR 2008-09

76

R & D (Special Studies) FOR AB-YBB-2011/21 FOR THE YEAR 2008-09

77

BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2009-10 (Amount in USD)

Particulars Budgeted Cost

Actual Cost

Variance Amount

Reasons Comments

G & G SUPPORT

206250 131806

74444

As per actuals. FAVOURABLE

PEL FEES 103542 105606

-2064

As per actuals booked on accrual basis and variance in dollars due to exchange rate variation.

UNFAVOURABLE

DATA COPYING CHARGES

219512

219512

As per actuals FAVOURABLE

ACQUISITION -175396

175396

As per actual reversals for past costs of 3D seismic acquisition carried out in 2007-08

PROCESSING 67500 -1640

69140

Budget will be carried forward to 2010-2011 as report generation will be completed in 2010-2011

FAVOURABLE

INTERPRETATION

639000 613065

25935

As per actuals .Detailed re interpretation of the G&G data of about 3270 SKM of 3D data pertaining to area AF and G. Inview of taking up the well, G&G activity pertaining to propsective area only carried out hence the variance.

FAVOURABLE

DRILLING 58195052 49986401

8208651

Rig was on location of well NAC#A till 19.3.2010 and moved to next location on 20.3.2010.Hence only 58 days cost charged to the location instead of 69 days cost which was budgeted. Hence the variance.

FAVOURABLE

G & A COST 3307592 3307592

0

Charges as per actuals. FAVOURABLE

TOTAL

62738447 53967434 8771014

78

NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2009-10 API VARIANCEParticulars Std Price Std

Quantity

Std Price per Unit

Actual Price

Actual Quantity

Actual Price per Unit

Price Variance

Quantity Variance

Cost Variance

1 2 3 4 5 6 7=5*(3-6) 8=3*(2-5) 9=(7+8)

Acquisition Cost3D Seismic Data AcquisitionMobilization Charges 58195052 4970

11709.266 49986401 4970

10057.6259 8208651 0 8208651

Processing Cost3D Processing3D Special Processing (PSTM/AVO Inhouse)

Interpretation CostComputing Services

639000 3270 195.412844

613,065 3270 187.481706 25935

25935

TOTAL 58834052 50599466 8234586 0 8234586

79

TOTAL EXPENDITURE BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2009-10

80

ACQUISITION PROCESSING AND INTERPRETATION COST AB-YBB-2011/21 FOR THE YEAR 2009-10

81

G & A COST FORAB-YBB-2011/21 FOR THE YEAR 2009-10

82

G & G COST FOR AB-YBB-2011/21 FOR THE YEAR 2009-10

83

PEL FEES FOR AB-YBB-2011/21 FOR THE YEAR 2009-10

84

DRILLING COST FOR AB-YBB-2011/21 FOR THE YEAR 2009-10

85

BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2010-11 (In USD)

Particulars Budgeted Cost

Actual Cost

Variance Amount

Reasons Comments

G & G SUPPORT 226875 249099 -22224 As per actuals and variance within 10% of budget.

UNFAVOURABLE

CONSULTANT,CONTRACTOR & PROFESSIONAL FEES

480000 0 480000 Activity not carried out. Hence the variance.

FAVOURABLE

PEL FEES 103542 543124 -439582 As per actuals booked on accrual basis and variance due to upward revision in the PEL Fees subsequent to GOI order which was not applicable while budgeting for BE 2010-2011.Hence the variance.

UNFAVOURABLE

DATA COPYING CHARGES

219512 0 219512 As per actual. FAVOURABLE

ACQUISITION 0 0 0

PROCESSING 0 36296 -36296 Actual cost of 3D Seismic Special Processing activity carried out in 2009-10 and budgeted in 2009-10; accounted in 2010-2011 as report genenration completed in 2010-2011.Variance with BE 2010-2011 as intiallly activity was budgeted in 2009-10.No new activity was carried out in the block this year.

UNFAVOURABLE

INTERPRETATION 284000 1639295 247822 As per actuals .Detailed re interpretation of the G&G data of about 600 SKM of 3D data was taken up. Inview of taking up the well, G&G activity pertaining to propsective area only carried out hence the variance.

FAVOURABLE

SPECIAL STUDIES 142668 0 142668 Post drill G&G analysis reflected under the budget head interpretation. No new activity taken up in the block this year.

FAVOURABLE

GEOCHEMICAL MODELLING

120000 0 120000 FAVOURABLE

86

LAB STUDIES OF CUTTING & CORES

150000 0 150000 Activity not carried out. Hence ,the variance.

FAVOURABLE

DRILLING 1447347 1118292.05

329055 Intial budget in BE 2010-2011 was kept for spillover costs of well NAC#A which was drilled in 2009-10.Additional service tax liability on hiring of drilling rigs for drilling of well NAC#A , not reflected in the accounts of 2009-10 , accounted in this year and reflected against 2010-2011 budget.Further liability for water charges and consumption of oil well cement also accounted this year.Details in 3B form.

FAVOURABLE

G & A COST 724653 783714 -59061 Charges as per actuals.Variance within 10% of the budget and within tolerance limits.

UNFAVOURABLE

TOTAL 3898597 2766704 1131893

87

NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2010-11 API VARIANCEParticulars Std Price Std

Quantity

Std Price per Unit

Actual Price

Actual Quantity

Actual Price per Unit

Price Variance

Quantity Variance

Cost Variance

1 2 3 4 5 6 7=5*(3-6) 8=3*(2-5) 9=(7+8)

Acquisition Cost3D Seismic Data AcquisitionMobilisation Charges 1447347 4970 291.22 1118292 4970 225 329055 0 329055Processing Cost3D Processing3D Special Processing (PSTM/AVO Inhouse)

Interpretation CostComputing Services 284000 600 473 36178 600 60 247822 0 247822

TOTAL 1731347 1154470 576877 0 576877

88

TOTAL EXPENDITURE BUDGET VS ACTUAL FOR NELP BLOCK AB-YBB-2011/21 FOR THE YEAR 2010-11

89

ACQUISITION PROCESSING AND INTERPRETATION COST AB-YBB-2011/21 FOR THE YEAR 2010-11

90

G & A COST FOR AB-YBB-2011/21 FOR THE YEAR 2010-11

G & G COST FOR AB-YBB-2011/21 FOR THE YEAR 2010-1191

PEL FEES FOR AB-YBB-2011/21 FOR THE YEAR 2010-11

92

DRILLING COST FOR AB-YBB-2011/21 FOR THE YEAR 2010-11

93

CONCLUSION

94

CONCLUSION

95

To be concluded that the variance analysis by the project proves to been effective method for accounting

cash flows and there by helps the organisation in monitoring its fund flows in its exploration activities. The method

can help in developing efficient budgets with minimisation of huge variation between budgeted and actual figures.

It can help check each stage of mobility of cash and makes all activities accountable. Thus variance analysis of

NELP block helps the organisation in making judicial and effective decisions in the coming age of privatization.

Thus it can make the organisation maintain stable position in all its cost activities in years to come.

Findings of the study

The operator has been effective in narrowing down the variance from 2007- 2011.

The variance analysis can be applied to all cases provided the standard or (budgeted) and actual are known.

It was observed that the variance is predominantly due to the price component, reflected as a result of possible delays in , or due to environmental factors outside the operators control.

It is also observed that the quantity variance is relatively less significant in the total variance, indicating fairly good prediction of physical parameters in budgeting major activities.

The variance analysis helped in given an in depth overview of the budget.

The budgeting process developed can be applied to all areas of exploration and production activities.

It helped in accounting for varied sizes of variances.

It helps in careful examination of the current budgets and considering the same while budgeting for future purposes

96

TOTAL VARIANCE ANALYSIS FROM 2006-2011 FOR AB-YBB-2011/21

97

TOTAL EXPENDITURE FROM 2006-2011 FOR AB-YBB-2011/21

98

G & A COSTS FROM 2006-2011 FOR AB-YBB-2011/21

99

PEL FEES FROM 2006-2011 FOR AB-YBB-2011/21

100

G&G COST’s FROM 2006-2011 FOR AB-YBB-2011/21

ELEMENTS WISE ANALYSIS:-

101

The variance between the years is growing narrow. Except the year 2008-09, where there is a steep rise from the previous year. This is due to the fact that whatever budget that was allocated for the project couldn’t be used appropriately as the work done in Acquisition and Processing was less than the estimated square area.

For the Total Expenditure there was a gradual decline as in 2006-07,the company had went into acquiring the sites for project and major chunk had gone into that . The next year 2007-08, however the acquisition had reduced to a greater level and the major amount had gone into employee benefit schemes. The expenditure in 2008-09 was due to the fact that exchange rates were high. Most of the activities ensued as they were estimated. Even the R&D of special studies for high resolution biostratigraphy of drilled wells had started by this period. Whereas the very next year 2009-10, the developing countries were trying to improve upon their GDP’s. The company was also working upon its acquired blocks and the activities like processing, interpretation and drilling had been initiated. This took the expenses to a new overhead. In 2010-11 though, the cost for the activities were stabilized and so it had reduced considerably.

The General and Administrative costs have gone up gradually with the initiation of the Processing and interpretation of the data from the region or blocks that were acquired. In 2009-10 the plot was actually drilled so the cost went high.

The PEL Fees had changed minimalistically over the years. But in 2010-11 the cost has gone up due to all the different factors-Inflation being one of the major ones.

The G & G Expenses are growing steadily except the dip it took in 2008-09.

102

RECOMMENDATIONS

All activities must be budgeted mandatorily to avoid huge variance

In case new technologies are likely to be adopted in the future, then the same must be considered at the time of budgeting.

Variation in budgeting should always be accounted for

Precautionary measures must be taken or certain funds should be set aside for R & D a well as adoption of innovative technologies.

103

APPENDIX

APPENDIX

104

DEFINITIONS

“Authority for Expenditure Request” means it is a document that describes the scope of work gives estimated timings of such expenditure and shows the estimated final cost which is the amount requested for approval.

”Abandonment” means all or any action or conduct by the operator for the purpose of site restoration, abandoning fields, joint operations, joint property or any other operations.

”Accounting procedure” means the principle and procedure of accounting set out in APPENDIX C

”Affiliate” means a company or a body

”Approved Work Program” (AWP) means a work program or a budget that has been approved by the management committee pursuant to the provision s of this contract.

”Article” means an article of this contract and the term articles means more than one article

”Budget” means a budget formulation in relation to a work programme

”Company” for the purpose of this contract means a company which is a party to this contract and were more than one company is party to the contract, the term company shall means all such companies collectively, including their respective successors and permitted assigns.

“Cash call” means any request for payment of cash made by the operator in accordance with an approved work program.

”Contract” means this agreement and appendices mentioned here in and attached here to and made an integral part hereof and any amendments made there to pursuant to the terms hereof.

”Contract area” means on the effective date the area described in appendix A and delineated on the map attached as appendix B or any portion of the said area remaining after relinquishment or surrender from time to time pursuant to the terms of this contract.

”Contract cost” means exploration cost development cost and production cost

”Contract year” means a period of twelve consecutive months counted from the effective date or from the anniversary of the effective date.

”Contractor” means the company or companies.

”Crude oil” means all kind of hydrocarbons and bitumen both in solid and liquid form.

”Development well” means a well drilled deepened or completed after the date of approval of the development plan pursuant to development operations or production operations for the purpose of producing petroleum.

”Directorate General of Hydrocarbon” (DGH) means an organisation including its successors under the ministry of petroleum and natural gas.

”Discovery” means the finding during the petroleum operations

“Depreciation” means it is a measuring of the wearing out, consumption or loss of value of a depreciable asset.

105

“Depletion” means it is the reduction in value of an asset.

“Drilling cost” means all cost and expenses incurred in any manner in any connection with planning, preparation, drilling deepening, side tracking and testing of wells.

”Effective date” means the latter of the date on which this contract is executed by the parties or the date of issue of license.

”Exploration cost” means those cost and expenditures incurred in carrying out exploration activities.

”Exploration operations” means operations conducted in the contract area pursuant to this contract in search for petroleum and in the course of an appraisal program.

”Exploration period” means the period mentioned in article 3 during which exploration operations may be carried out by the contractor as provided in article 3

”Exploration phase” means any of the periods specified in article 3 in which the contractor is required to complete the MWP.

”Exploration well” means a well drilled for the purpose of searching for undiscovered petroleum accumulations on any geological entity.

”Field” means an oil field

“JIB Statement” means statement that includes details of all expenses party details current AER details, billing period.

”License” means a petroleum exploration license.

”MWP” means with respect to exploration phase the work program specified in article5 with respect to such phase.

”Oil field” means with in the contract area an oil reservoir or a group of oil reservoirs with in a common geological structure.

” Operating agreement” means the agreement entered by the constituents of the contractor in accordance with article7.

”Operating committee” means the committee established by that name in the operating agreement pursuant.

”Participating interest” means in respect of each party constituting the contractor the undivided share expressed as a %age of such parties participation in the rights and obligations under this contract.

”Parties” means the parties signatory to this contract including their successors and permitted assigns under this contract.

”Petroleum operations” means the exploration activities

”Petroleum” produced and saved means gross petroleum saved minus impurities such as water or solids produced along with petroleum.

”Reservoir” means a naturally occurring discrete accumulation of petroleum.

106

”Work program” means a work program formulated for the purpose of carrying out petroleum operations.

“Production Sharing Contract” (PSC) means an agreement between the parties to a well and the government

regarding the percentage of production of each party will receive after the participating parties have recovered a

specified amount of cost and expenses.

107

ACRONYMS

AER Authorised expenditure request

BDP Books of delegated powers

CO Costing module

DEPRUN Depreciation run

DGH Director general hydrocarbons

DWIP Development wells in progress

E&P Exploration and production

EPOD Expand plan and development

EWIP Exploratory wells in progress

FI Finance exchange

FOREX Foreign exchange

G&A General and administrative

G&G Geological and geophysical

ICAI Institute of chartered accountant

INR Indian national rupees

IO Internal orders

IUT inter unit transfer

JIB Joint interest billing

JOA Joint operating agreement

JV Joint venture

JVG Joint venture group

MC Management committee

MT Metric tonnes

108

MWP Minimum work program

NELP New exploration licencing policy

NTA Net trading average

OC Operating committee

PCO Parent company overhead

PP Production property

PSC Production sharing contract

WBS Work breakdown structure

API Acquisition processing interpretation

BIBLIOGRAPHY

WEB SITE

www.ongcindia.com

www.mysap.com

www.google.com

www.wikipedia.com

www.MoneyWorks4me.com

www.infraline.com

BOOKS

INTRODUCTION TO OIL AND GAS JOINT VENTURE by john wilkinson

ONGC manual

JOINT OPERATING AGREEMENT

PRODUCTION SHARING CONTRACT

109

110