Oil And Gas ing 3c2a2i

Oil & Gas ing Principles & Issues KABIR TAHIR

BAYERO UNIVERSITY, KANO FACULTY OF SOCIAL AND MANAGEMENT SCIENCES DEPARTMENT OF ING 2nd July, 2012 COURSE: ACC 8211 (Oil and Gas ing) CLASS: M.Sc. ing SESSION/SEMESTER: 2011/2012 Session — First Semester LECTURER: Kabir Tahir Hamid, PhD CONSULTATION: Strictly by Appointment OFFICE: A8, Department of ing, Aminu Alhassan Dantata School of Business, New Campus, Bayero University, Kano. A.COURSE DESCRIPTION

This course is designed to introduce students to the fundamentals of oil and gas ing, different ing principles and procedures prevalent in the petroleum industry and ing framework of the Nigerian petroleum industry. B. COURSE OBJECTIVES i) To develop an understanding of the nature and historical development of oil and

gas ing. To develop an understanding of the basic characteristics and differences between the downstream and the upstream sectors and their activities. iii) To develop an understanding of ing for exploration, ditching, and development costs. iv) To develop an understanding of petroleum products pricing, ing standards and financial statement disclosures in the oil and gas industry. C. COURSE CONTENTS 1. History and Nature of Oil and Gas Operations 1.1 Definition of Petroleum 1.2 Origin of Petroleum, Its Industry Characteristic and Activities 1.3 The History of the Nigerian Oil and Gas Industry 1.4 The Nature of Petroleum Assets and the Process of Acquiring It 1.5 ing Dilemmas in Oil and Gas ing 1.6 The Upstream and the Downstream Sectors of the Nigerian Oil industry 1.7 NNPC and DPR and Their Roles 1.8 PPPRA and the Proposed Petroleum Industry Bill (PIB) 2011 2. Oil Prospecting and Reserves Valuation 2.1 Steps in Prospecting for Oil and Gas 2.2 Types of Oil and Gas Wells 2.3 Estimation and Valuation of Oil and Gas Reserves 2.4 Classification of Reserves 2.5 Oil and Gas Reserves Estimation ii)

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3. Arrangements, Agreements and Contracts in the Nigerian Petroleum Industry 3.1 Types of Operating Contracts in the Petroleum Industry 3.2 Contract Arrangements in the Nigerian Petroleum Industry and their Operations 3.3 Financial and Fiscal Monitoring Mechanisms of Agreements in the Petroleum Industry 4. ing Principles and Standards in the Oil and Gas Industry 4.1 Application of GAAPs in the Oil and Gas Industry 4.2 Classification of Costs in the Oil and Gas Industry 4.3 Methods of ing in the Oil and Gas Industry 4.4 ing Standards in the Oil and Gas Industry 5. Procedures in Oil and Gas ing 5.1 Basic ing Transactions 5.2 Depreciation, Depletion and Amortization (DD & A) 5.3 ing for Oil and Gas Exploration and Acquisition Costs 5.4 ing for Oil and Gas Development and Production Costs 5.5 ing for Crude Oil Refining, Petrochemical and Liquefied Natural Gas 5.6 Petroleum Products Pricing and Marketing 5.7 Typical Oil and Gas Financial Statements and Oil and Gas ing Disclosure D. RECOMMENDED TEXT BOOKS i) Fundamentals of Oil and Gas ing by Gallun, R. A., Wright J. C., Nichols, L. M. and Stevenson. J. W. ii) Financial ing and Reporting by Oil and Gas Producing Companies by FASB iii) ing for Oil and Gas Exploration, Development, Production and Decommissioning Activities by SORP v) International Petroleum ing by Wright, C. J. and Gallun, R.A. vi) Financial Reporting in the Oil arid Gas Industry by Pricewaterhousecoopers vii) Petroleum ing, Principles, Procedures and Issues by Gallun, R. A. and Wright viii) Fundamentals of Petroleum by Kate. V.D. ix) Petroleum ing: Principles, Procedures & Issues by Jennings, D. R., Feiten, J. B. and Brock, H. R.

E. METHODOLOGY Discussion papers, covering the theoretical aspects of each topic, would be prepared and presented in the class, to be followed by discussion exercises. Some of the exercises would be attempted in the class, while the rest would be left to the students to practice on their own. F. GRADING FORMULA Continuous Assessment 40% Semesters Examination 60% Aggregate 100% The continuous assessment marks are to be absorbed through snap test (s) to be given without notice, scheduled test(s) and/or assignment(s).

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1.0 HISTORY AND NATURE OF OIL AND GAS OPERATIONS 1.1 Definition of Petroleum The term petroleum is said to have been derived from two Latin words, Petra, meaning rock, and Oleum, meaning oil. Eventually, the term petroleum came to refer to both crude oil and natural gas. More broadly defined, Petroleum (i.e. crude oil and natural gas) refers to mixture of hydrocarbons that are molecular in nature, in various shapes and sizes of hydrogen and carbon atoms, found in small connected pore spaces of some underground rock formations. While crude oil refers to hydrocarbon mixture produced from underground reservoirs that are liquid at the normal atmospheric pressure and temperature, natural gas refers to hydrocarbon mixtures produced from underground reservoirs that are not liquid but gaseous at the normal atmospheric pressure and temperature. Hydrocarbons are compounds containing only the elements hydrogen and carbon, which may exist as solids, liquids or gases.

1.2 The Origin of Petroleum, Its Industry Characteristics and Activities 1.2.1 The Origin of Petroleum Geologists and Geophysicists dealing with the earth crust propound that rock formations within the earth’s crust consist of igneous, metamorphic and sedimentary rocks. While, igneous rocks are rocks that are formed as a result of cooling and solidification of molten magma, sedimentary rocks, such as sandstone, developed as a direct result of erosion, transport and deposition of pre-existing igneous rock, along with remains of plants and animals. Eroded particles of igneous rocks are carried to low areas and are deposited into sedimentary layers through the action of wind and water. Metamorphic rocks develop when igneous or sedimentary rocks are subjected to heat and pressure resulting from the weight of overlying rocks stresses, thus converted into metamorphic slates and quartzite. Nearly all significant oil and gas reservoirs in the World today are found in sedimentary rocks, as the accumulation of oil or gas in igneous or metamorphic rocks is very rare; however petroleum can be reservoired in these types of rock under certain albeit rare conditions. The extreme heat and pressure associated with these types of rocks drives off or burns any organic material or hydrocarbons. It can therefore be said that, out of the three types of rocks explained above (namely, igneous, sedimentary and metamorphic rocks) only sedimentary rocks form the source in which hydrocarbons reservoirs are found. Even in the sedimentary rocks, hydrocarbons are possibly found in only sandstone (shale) and not limestone and dolomite. In other words, sandstones are the source rock in which oil and gas is formed and accumulated, while limestone and dolomite evolve through chemical processes. However, it is important to note that the various rock formations, as well as, the various changes in the earth's crust do not, by themselves, explain the evolution of oil and gas. The earth is made up of a core over 4,000 miles in diameter surrounded by the earth's mantle, which is approximately 2,000 miles thick. The earth's surface is underlain by the lithosphere, a relatively thin layer, some 125 miles in thickness, that is composed of the crust and upper mantle. Commercial oil and gas are found only in the crust of the earth. Explanations propounded on the origin of petroleum have their bases in geology and geophysics. Geology is the science that studies the planet earth, the materials it is made up of, the processes that act on these materials, the products formed, and the history of the planet and its life forms since its origin. Most geological studies are focused on aspects of the earth's crust because it is directly

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observable and is the source of energy and minerals for today's modern industrial societies. On the other hand, geophysics is the science that studies the earth by quantitative physical methods. Over the last two centuries, two theories—the inorganic theory and the organic theory—have been advanced to explain the formation of oil and gas. Although no one theory has achieved universal acceptance, most scientists and professionals believe in the organic origin of petroleum. The inorganic theory recognizes that hydrogen and carbon are present in natural form below the surface of the earth (diamonds, for example, indicate the presence of carbon in the earth's mantle). Different related theories explain the combination of the two elements into hydrocarbons. These include the alkali theory, carbide theory, volcanic emanation theory, hydrogeneration theory, and the high temperature intrusion theory. Except for the intrusion theory, most of the inorganic theories have been largely discounted. The intrusion theory argues that high temperatures applied to carbonate rocks can produce methane gas and/or carbon dioxide. This theory applies only to gas, not to the heavier hydrocarbons (oil). Based on abundant direct and indirect evidence, most scientists accept the organic theory of evolution of oil and gas. According to geological research, the earth was barren of vegetation and animal life for roughly one half of an estimated five billion years of the earth's existence. Approximately 600 million years ago, an abundance of life in various forms began in the earth's oceans. This development marks the beginning of the Cambrian period in the Paleozoic era. Nearly 200 million years later (in the Devonian period), vegetation and animal life had spread to the landmasses. The Paleozoic (roughly 350 million years), Mesozoic (roughly 150 million years), and Cenozoic (roughly 1000 million years), eras have been labeled as successive and definitive geological time periods by geologists, which brings us up to the present. These time periods are shown in Table 1. Table 1: Geologic Time Period

Era Cenozoic "Modern Life" Mesozoic "Middle Life"

Paleozoic "Ancient Life"

Period Quaternary Tertiary Cretaceous Jurassic Triassic Permian Carboniferous Devonian Silurian Ordovician Cambrian

Approx. Duration in million yrs. 3 63 71 54 35 55 65 50 35 70 70

Indicative New Life Forms Large Mammals Large Dinosaurs

Early Reptiles, Amphibians and Fish Bacteria, Algae and Jellyfish

Crypotozoic or Precambrian

4,000

Approximate age of the earth

4,600,000,000 years

The basic premise is that oil and gas are formed from chemical changes taking place in plant and animal remains. Through the process of erosion and transportation, sediments are carried from the land down the rivers and, together with some forms of marine life, settle into the ocean floor. Most hydrocarbons are believed to be derived from tremendous volumes of plankton, algae, and bacteria 5

common in ocean basins and lakes, and other marine lives that lived millions years ago in low land areas, usually in the oceans. The theory posits that the remains of plants and animals were deposited along with the eroded particles of igneous rocks, which have been weathered through physical and chemical reactions. The weight and pressure of’ layer upon layer of the eroded particles of the igneous rocks resulted in the formation of sedimentary rocks, and some chemical and bacterial processes turned the organic substances in the sedimentary rock into oil and gas. The sedimentation process can be observed even within an individual's lifetime. For example, the delta area at the mouth of a large river is formed by sedimentation. Layer after layer of silt, mud, particles of sand, and plant and animal life are deposited on the ocean floor, with a great portion of the plant and animal life coming from the ocean itself. Anaerobic bacteria in the sediment aid in breaking up the organic material and releasing oxygen, nitrogen, phosphorus, and sulfur from the organic material, leaving the balance with a much higher percentage content of hydrogen and carbon and, thus, a more petroleum-like composition. After formation, oil and gas move upward through the layers of the sedimentary rock due to pressure and the natural tendency of oil to rise through water. The petroleum migrates upwards towards the earth surface through the porous rock formations until it becomes trapped by an impervious layer of rocks. When this occurs, the oil remains there and forms a petroleum reservoir. A reservoir is a rock formation with adequate porosity and permeability to allow oil and gas to migrate to a well bore at a rate sufficient as to be economically producible (most geologists believe the earth initially formed from molten rock, or magma, and cooled into solid igneous rocks. During the cooling and contraction processes, some rock solidified beneath the surface). The impervious layer formed a seal which prevent hydrocarbons from leaking to the surface. If the seal is inadequate, little quantity of the hydrocarbon escapes to the surface. This is known as oil seeps. Seeps at the surface are often used as indicator of potential hydrocarbon reservoirs in the subsurface. In some instances, oil and gas migrate directly to the reservoir area. More often, however, movements in the earth's crust caused additional shifting, folding, bends, and fissures, and a secondary migration of the oil and gas took place through porous layers until another impermeable seal was reached. This may occur when an area is subjected to new tectonic forces, earth quakes, tsunami, etc. To search for new oil and gas fields, therefore, geologists and geophysicists devote their efforts to understanding the distribution of rocks that could be sources, seals, and reservoirs in an attempt to develop locations for potential traps within petroleum systems. While it can be seen that oil and gas are formed through the sedimentary process, this does not necessarily mean that the oil and gas have remained in the source beds or places of origin. Hydrocarbons are known to have been preserved for hundreds of millions of years and the process of hydrocarbon formation is undoubtedly continuing, but much more slowly than is the rate of consumption of hydrocarbons. Generally, marine and lacustrine source rocks generate oil whereas coal source rocks commonly generate natural gas. The impervious rock that prevents further movement of the oil and gas is known as trap. There are four broad classifications of traps, namely: (1) structural strap (2) truncation trap (3) stratigraphic trap, and (4) a combination trap. Structural trap is a result of upheavals of the earth and may take the form of an anticline, fault or dome. Anticlines are the most significant reservoirs of hydrocarbons and are estimated to contain

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around 80 per cent of the world’s oil. However, in order for an oil and gas reservoir to have been formed, four necessary conditions must have been met. These conditions are: (1) there must have been a source of oil and gas, i.e. the remains of plants and animals; (2) heat and pressure resulting in the transformation of the organic substances of the remains of plants and animals into oil and gas; (3) Porous and permeable sedimentary rock formations through which the oil and gas was able to migrate upwards after formation. Porosity is the measure of the pore openings in a rock in which petroleum can collect; none of the sedimentary rocks are completely solid. The greater the porosity, the more petroleum the rock can hold, and the closer the rock is to the surface, the more the porosity. It is within the pore spaces that the oil and gas initially accumulated, together with some water called connate water. The pore spaces may constitute up to 30 percent of the volume of the reservoir rocks that are relatively close to the surface. As depths increase, the porosity of the formation tends to decrease as the result of compaction from the weight of the overlying layers of sediment. Permeability, on the other hand, measures the relative ease with which the oil and gas can flow through the rocks and is expressed in millidarcies. The flow of oil and gas through a reservoir takes place in microscopic channels between pore spaces. In some cases fractures are also present that provide greater permeability. If there is high permeability, oil and gas can move through the formation with relative ease. Low permeability will decrease or even block the movement of fluids through the formation. Though, permeability may be improved through fracturing (i.e. introduction of a mixture of sand and water or oil into the formation under high pressure to clean the channels between the pores) and acidizing (i.e. introduction of hydrochloric acid into the formation to enlarge and clean the channels between the pores), porosity is difficult, if it impossible to be improved. There are two types of producing reservoirs, namely (1) oil reservoir and (2) gas reservoir. While the components of oil reservoir are crude oil, basic sediment, water and associated gas, the components of gas reservoir are non-associated gas, condensates and natural gas. To be commercially viable therefore, a petroleum reservoir must have adequate porosity and permeability and must have a sufficient physical area of rock that contains hydrocarbons. In other words, the reservoir must contain high quantity of oil and gas, so that when produced and sold, cover the cost of production (including payment of royalties to the government) and leave some profit margin for the producing company and tax revenue to the government. Condensate are hydrocarbons that are in a gaseous state at reserviour conditions but condense into liquids as they travel up the wellbore and reach surface conditions. (4) an impervious rock formations that a prevents the oil and gas from further migration, thereby enabling the oil to collect.

Evidence ing the Organic Theory of Oil and Gas Formation The following are the evidence ing the organic theory of the origin of oil and gas: 1. sedimentary beds are rich in organic matter; 2. some of the chemical components of oil are the same as those found in plants and animals; 3. the chemical composition of oils and gases derived from so called source rocks match the observed composition of oils and gases in nearby reservoirs; and 4. the recent discovery of bio-fuel (a fuel that is derived from biomass-recently living organisms or their metabolic byproducts-from sources such as farming, forestry, and

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biodegradable industrial and municipal waste) the proposition that hydrocarbon itself is most likely to have been originated from the remain of plants and animals. 1.2.2 Characteristics of the Petroleum Industry Although the primary purpose of this course is to deal with the ing principles and practices in the oil and gas industry, it is considered that the appreciation of operational aspects of the industry is important for a better understanding of ing practices in the industry. Basically, the objective of the oil and gas industry is to exploit and recover hydrocarbons (crude oil and gas) in its natural form from large sub-surface reservoirs, subject it to changes through chemical and physical processes in a refinery, gas plant or petrochemical plant in order to obtain products such as gasoline, diesel, kerosene, jet fuel, lubricants, asphalt, bitumen, petrochemicals and treated natural gas.

It is important to add that although Exploration and Production (E&P) procedures and processes are more important to geologists and geophysicists, the knowledge of the procedures and steps involved in locating and acquiring mineral interest, drilling and completion oil and gas wells and producing, processing and selling petroleum products is necessary in order to understand their ing implications. Hence, it is important that ing students and ing practitioners become familiar with the process.

Oil and Gas industry is one of the vital industries in the world, largely because of its strategic role in every economy and the world, at large. The distinctive features that characterized the industry are derived from the nature of crude oil, its operations and commercial arrangements. Some of these characteristics of the oil and gas industry may include the following: 1. High Level of Risk and Uncertainty: The level of risk in oil and gas operations can be both substantial in amount and wide in scope, and locating new well sites even in already established field is surrounded with high level of uncertainties. Exploration operations are risky because oil is hidden underground and the only conclusive evidence of its presence in any form, quantity and quality is drilling. There is therefore a geological risk of drilling and hitting a dry hole. In addition, there are market risk (the risk of not finding an outlet for production at a satisfactory price), sovereign/political risk (the risks of nationalization of operations, currency devaluation, licensing and exploration agreements), partner risk (the risk of partner default, distrust, unwillingness, inability or delay in paying due shares of cost of exploration and development), youth militancy risk (the risk of kidnapping of personnel and vandalisation of equipments by militant youths) and tax risk (the risk of unexpected change in tax provisions) . Consequently, the risk of loss of capital is very high. 2. Dominance of the World Economy: The second feature of oil and gas industry is its dominance of the world economy, in of financial figures, unlimited potentials as raw material, global economy development and international politics and touches the lives of people in any more ways, anywhere on earth. Exxon Mobil, Saudi Aramco, Chevron and Shell B.P. are one of the largest companies in the World today in of financial figures and profitability. 3. Long Lead-Time between Investment and Returns: Even in normal circumstances, upstream activities can take several years, thereby complicating the risk further in oil and gas operations. The operations are highly capital intensive, requiring large amounts of capital

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investment up-front. The lead-time therefore stretches the capital outlay and brought about long gestation period between investment and return from the investment. 4. Significant Regulation by Government Authorities: The petroleum industry, in any part of the world is subject to involvement, participation, intervention and regulation by various governments and its agencies. This is as a result of the indispensability of oil, its depletable nature and its influence in international politics. 5. Technical and Operational Complexity: Finding oil has proved to be a difficult task and therefore demands the best technology possible. This results from the complexity of operations, especially in the offshore terrain. 6. Specialized ing Rules for Reporting and Complex Tax Rules: There are fundamental dissimilarity between financial/tax ing in the oil and gas industry and other industries. This arises from the nature of oil and gas industry, its highly technical operations and specialized activities. 7. Lack of Correlation between Investment and the Value of Reserves: The amount invested in oil and gas operations usually does not bear any relationship with the value of oil and gas reserve, as a result of the inherent difficulties in estimating the value of reserves and the need for up-front large investments in petroleum exploration and production. Although, these characteristics are most evident in Exploration and Production (E&P) functions of the oil and gas industry, they are found in other segments of the industry in varying degrees. 1.2.3 Activities/Segments in the Nigerian Oil and Gas Industry Nigerian oil and gas companies may be involved in four different types of functions or segments, namely Exploration and Production (E&P), storage and transportation, refining and hydro processing, and distribution and marketing. A company may decide to operate in any of the four segments or a combination thereof. The four segments are briefly explained below: 1. Exploration and Production (E&P): Exploration is the search for oil with a view to discovering oil-in-place, while production is the removal of oil from the ground and surface treatment. In this segment, companies explore from underground reservoirs of oil and gas and produce the discovered oil and gas using drilled wells, through which the reservoir oil, gas and water are brought to the surface and separated. Companies that are involved in E&P are only to explore and produced the discovered oil and gas and sell it depending on the nature and conditions of the contract, i.e. concession, t venture or production sharing contracts. This segment is an upstream activity. 2. Storage and Transportation: This segment encomes the storing and moving of petroleum from the production field to crude oil refineries and gas processing plants. Once crude oil and gas produced and treated, it is stored in tanks and later transported to refineries and gas processing plants by road tankers, railway tankers, sea oil tankers, and pipelines. 3. Refining and Hydro Processing: Refining is the treatment of crude oil in order to form finished products and may extend to the production of petrochemicals. This segment required plants to be put in place for the separation and processing of hydrocarbon fluids and gases into various marketable products such as gasoline, diesel, kerosene, jet fuel, lubricants, asphalt, bitumen, petrochemicals and treated natural gas. Crude oil refining involves the breaking down of hydrocarbon mixture into useful products, through distillations, cracking, reforming and extraction process. The factors that determine the refinery configuration are:

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(1) (2) (3) (4) (5) (6) (7) (8)

the domestic, regional or global economy; availability of crude oil; price of crude oil per barrel; quantity of product to be developed and present technology; regulations (i.e. government and OPEC regulations); market trends; environmental issues, competition; and degree of integration.

Petrochemical is a substance produced commercially from the feedstock derived from oil and gas. The functions of petrochemical plants, therefore, is to turn outputs of the refining process either in form of crude oil fractions or their cracked or processed derivatives into feedstock that will ultimately be used in the manufacture of a number of other products, e.g. plastics, detergents, nitrogen fertilizers, etc. The gas mixtures consist largely of methane (the smallest natural hydrocarbon molecule consisting of one carbon atom and four hydrogen atoms). Natural gas usually contains some of the next smallest hydrocarbon molecules commonly found in nature: Ethane (two carbon, six hydrogen atoms, abbreviated C2H6), Propane (C3H8), Butane (C4H10), and Natural gasolines (C5H12 to C10H22). These four types of hydrocarbons are collectively called natural gas liquids (abbreviated NGL) which are valuable feedstock for the petrochemical industry. When removed from the natural gas mixture, these larger, heavier molecules become liquid under various combinations of increased pressure and lower temperature. Liquefied petroleum gas (abbreviated LPG) usually refers to an NGL mix of primarily propane and butane typically stored in a liquid state under pressure. LPG (alias bottled gas) is the fuel in those pressurized tanks used in portable "gas" barbeque grills. Sometimes the term LPG is used loosely to refer to NGL or propane. The more natural gas liquids in the gas mixture the greater the energy, and the "richer" or "wetter" the gas. For various economic reasons, wet gas is commonly sent by pipeline to a gas processing plant for removal of substantially all natural gas liquids, before sale. The remaining gas mixture, called residue gas or dry gas, is over 90 percent methane and is the natural gas burned for home heating, gas fireplaces, and many other uses. Crude oil can be many different mixtures of liquid hydrocarbons. Crude oil is classified as light or heavy, depending on the density of the mixture. Density is measured in API degree (which is a measure of how heavy or light a petroleum liquid is compared with water). Heavy crude oil has more of the longer, larger hydrocarbon molecules and, thus, has greater density than light crude oil. Heavy crude oil may be so dense and thick that it is difficult to produce and transport to market. Heavy crude oil is also more expensive to process into valuable products such as gasoline. Consequently, heavy crude oils sell for much less per barrel than light crude oils but weigh more per barrel. Both natural gas and crude oil may contain contaminants, such as sulphur compounds and carbon dioxide (CO), that must be substantially removed before marketing the oil and gas. The contaminant hydrogen sulfide (H22S) is poisonous and, when dissolved in water, corrosive to metals. Some crude oils contain small amounts of metals that require special equipment for refining the crude. 10

Liquefied natural gas operations encomes a number of interdependent activities ranging from gas gathering from the field, transmitting the gas to plants, treating the gas, compressing the gas into liquid, transporting the gas by ship to buyers, receiving the compressed gas at the buyer’s terminal and packing the gas into cylinders for storage and distribution. Different mixtures of petroleum have different uses and economic value. Numerous useful products that are derived from petroleum include the following: (a) Transportation Fuels [Automotive Gas Oil (AGO), popularly known as diesel and Motor Spirit (PMS) popularly known as petrol, etc]. (b) Heating Fuels, like the Dual Purpose Kerosene (DPK), popularly known as kerosene. Kerosene (DPK) is a thin, clear combustible hydrocarbon liquid with a density of 0.780.81g/cm obtained from the fractional distillation of petroleum between 150 and 275 °C. Kerosene is widely used to power jet fuel engines, rockets and as a heating fuel in households. The combustion of Kerosene is similar to that of diesel with Lower Heating Value of around 18,500 Btu/1b, or 43.1 MJ/Kg, and its Higher Heating Value is 46.2MJ/kg. (c) Liquefied Petroleum Gas (otherwise known as cooking gas is made up of 70% propaneC3 and 30% butane-C4). It is a product of petroleum refining and, it can also be obtained from natural gas processing. It consists of hydrocarbons as vapors, at normal temperatures and pressures, but turns liquid at moderate pressures. LPG uses include; cooking, heating in households, fuel for transport etc. (d) Natural gas and residual fuel can be burned to generate electricity. (e) Petrochemicals from which plastics, as well as clothing, building materials, cream, pomade, soap, petroleum jelly, etc are produced. 4. Distribution and Marketing: Distribution and marketing involve the activities associated with getting finished products from distribution points into the hands of end s. Marketers are of different categories, namely major marketers (like Oando PLC, Mobil Unlimited, Con Oil, Texaco, etc.), independent markets (like Azman oil and gas, Sani Brothers Ltd., Pure Oil, Dan-Kano Petroleum, etc) and part-time marketers. The first activity is above is referred to upstream activity, while the last three activities are downstream activities. It is worthy to note that an oil company can either be integral or independent. While an independent oil company is one involved primarily in Exploration and Production (E&P) activities only. An integral oil company is one involved in Exploration and Production (E&P) activities as well as at least one of the other segments, namely storage and transportation, refining and hydro processing and marketing and distribution. An integrated company is also known as midstream. Figure I: Organization of the ing Function in an Independent Oil Company

Controller

Field Clerical and Services

Equipment and Supplies Inventory

s Payable

Property ing

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t Interest ing

Revenue ing

General ing

Taxes and Regulatory Compliance

Equipment and Supplies Inventory 1. Maintains equipment and supply inventory records. 2. Prices and records warehouse receipts, issues, and field transfers. 3. Oversees physical inventory taking. 4. Prepares reports on equipment and supplies inventory. s Payable 1. Maintains s payable records. 2. Prepares vouchers for disbursements. 3. Distributes royalty payments. 4. Maintains corporate delegated limits of authority and verifies that disbursements are made within those limits. Property ing 1. Maintains subsidiary records for (a) Unproved properties, (b) Proved properties, (c) Work in progress, (d) Lease and well equipment, and (d) Field service units. 2. s for property and equipment acquisition, reclassification, amortization, impairment, retirement, and sale. 3. Compares actual expenditures of work in progress to authorized amounts. t Interest ing 1. Maintains files related to all t operations. 2. Prepares billings to t owners. 3. Reviews all billings from t owners. 4. Prepares statements for tly operated properties. 5. Prepares payout status reports pursuant to farm-in and farm-out agreements. 6. Arranges or conducts t interest audits of billings and revenue distributions from t venture operations. 7. Responds, for the company as operator, to t interest audits by other t interest owners.

Revenue ing 1. s for volumes sold and establishes or checks prices reflected in revenues received. 2. Maintains oil and gas revenue records for each property. 3. Maintains records related to properties for purposes of regulatory compliance and production taxes. 4. Computes production taxes. 5. Maintains “Division of Interest” master files, with guidance from the land department, as to how revenue is allocated among the company, royalty owners, and others. 6. Computes amounts due to royalty owners and t interest owners and prepares reports to those parties. 7. Invoices purchasers for sales of natural gas. 8. Maintains ledgers of undistributed royalty payments for owners with unsigned division orders, owners whose interests are suspended because of estate issues, and other undistributed production payments. 9. Prepares revenue accruals. 12

General ing 1. Keeps the general ledger. 2. Maintains voucher and cash receipts and disbursements records. 3. prepares financial statements. 4. Prepares special statements and reports. 5. Assembles and compiles budgets and budget reports. Taxes and Regulatory Compliance 1. Prepares required federal, state and local tax returns for income taxes, production taxes, property taxes, and employment taxes. 2. May prepare other regulatory reports. 3. Addresses allowable options for minimizing taxes Figure II: Organization of ing Functions in Small Integrated Oil Company Corporate Controller

Financial ing &

Budget, Cost Analysis & Reports

Considerations

Pipeline

Corporate Tax

ing Policy & Research

Production ing

& Crude oil Trading ing

Refining ing

Marketing ing

Figure III: Organization of ing Functions in Production Division of Large Integrated Company Controller Production Division Budgets & Internal Reports

Compliance & Taxation

Budgets

Revenue ing

Policy Planning &

Financial ing & Investments

Regulatory Compliance

Oil

Recruitment and Development

General ing

Taxes

Gas

istrative

Investments

Internal Reports

Performance Management

Management Information System ing Policies

Internal Control

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t Interests

External Reports

1.3 The History of the Nigerian Oil and Gas Industry In order to understand the importance and nature of financial ing and reporting in the petroleum industry, it is helpful to briefly review the industry's history, particularly in Nigeria, right from its inception to date. In ancient history, pitch (a heavy, viscous petroleum) was used for ancient Egyptian chariot axle grease. Early Chinese history reports the first use of natural gas that seeped from the ground; a simple pipeline made of hollowed bamboo poles transported the gas a short distance where it fueled a fire used to boil water. Seventeenth century missionaries to America reported a black flammable fluid floating in creeks. From these creeks, Indians and colonists skimmed the crude oil, then called rock oil, for medicinal and other purposes. Later, the term rock oil would be replaced by the term petroleum from petra (a Latin word for rock) and oleum (a Latin word for oil). Eventually, the term petroleum came to refer to both crude oil and natural gas. By the early 1800s, whale oil was widely used as lamp fuel, but the dwindling supply was uncertain, and people began using alternative illuminating oils called kerosene or coal oil extracted from mined coal, mined asphalt, and crude oil obtained from surface oil seepages. Therefore, the petroleum exploration and production industry may be said to have begun in around mid 1800s. There was mention of an oil discovery in Ontario, Canada, in 1858, and Pennsylvania, in USA in 1859, with a steam-powered, cable-tool rig with a wooden derrick used in drilling. Shortly thereafter, a number of refineries began distilling valuable kerosene from crude oil, including facilities that had previously extracted kerosene from other sources. Transportation of crude oil was a problem faced from the earliest days of oil production. The coopers’ union constructed wooden barrels (with a capacity of 42 to 50 US gallons) that were filled with oil and hauled by teamsters on horse-drawn wagons to railroad spurs or river barge docks. At the railroad spurs, the oil was emptied into large wooden tanks that were placed on flatbed railroad cars. The quantity of oil that could be moved by this method was limited. However, the industry's attempts to construct pipelines were delayed by the unions whose would face unemployment and by railroad and shipping companies who would suffer from the loss of business by the change in method of transportation. Nevertheless, pipelines did come into existence in the 1860s; the first line was made of wood and was less than a thousand feet long. New demands for petroleum were created in the 1920s, largely because of the growing number of automobiles, as well as, the use of petroleum products to generate electricity, operate tractors, and power automobiles. The oil industry was able to increase production to meet the greater demand without a sharp rise in price. Compared with World War I, World War II which had its onset in 1939, used more mechanized equipment, airplanes, automotive equipment, and ships, all of which required huge amounts of petroleum. The search for oil in Nigeria dates back to 1908 when a German Company, by name the Nigerian Bitumen Corporation, obtained a licence to explore for oil in Okitipupa area of Ondo State. The company’s efforts were unsuccessful and with outbreak of the First World War, its operations were disrupted. Two decades later, Shell D’Arcy (the predecessor of Shell Petroleum Development Company of Nigeria Ltd) started exploration of Niger Delta in 1937 having acquired exploration right from the British Colonialists over the entire Nigerian territory under an exclusive exploration licence. The company operated under the Mineral Ordinance No. 17 of 1914 which gave companies ed in 14

Britain or any of its protectorates the right to prospect for oil in Nigeria. Except for a brief disruption of operations of the company in 1941 to 1946 because of the Second World War, it continued as the sole concessionaire in Nigeria until 1959 when exploration rights became available to oil companies of other nationalities. The first deep exploration well was in 1951 at Iho, 10 miles North-east of Owerri to a depth of 11,228 feet, but it was a dry hole. Shell discovered oil in a commercial quantity at Oloibiri, Rivers State (presently in Bayelsa State), in 1956, after half a century of exploration, with an equivalent investment of N120 million. This oil field came on stream in 1958 producing 5,100 bpd. From 1938 to 1956, almost the entire country was covered by concession granted to the Company (Shell-BP) to explore for petroleum resources. This dominant role of Shell in the Nigerian oil and gas industry continued for many years, until Nigeria’s hip of the Organization of the Petroleum Exporting -Countries (OPEC) in 1971. After which the country began to take firmer control of its oil and gas resources, in line with the practice of other of OPEC. In 1960 the Organization of Petroleum Exporting Countries (OPEC) was formed by Saudi Arabia, Kuwait, Iran, Iraq, and Venezuela. Later, eight other countries ed OPEC—the United Arab Emirates and Qatar in the Middle East; the African countries of Algeria, Gabon, Libya and Nigeria; and the countries of Indonesia and Ecuador. Ecuador, who ed OPEC in 1973, suspended its hip from December 1992 to October, 2007. By 1973 OPEC produced 80 percent of world oil exports, and OPEC had become a world oil cartel. Member countries began to nationalize oil production within their borders.

Table 2: GDP Per Capita and Population Estimates of OPEC Countries S/No.

Name of Country

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

Algeria Angola Ecuador (**) Indonesia Iran* Iraq* Kuwait* Libya Nigeria Qatar Saudi Arabia* United Arab Emirates Venezuela*

13.

Date ed OPEC 1969 2007 Reed 2007 1962 1960 1960 1960 1962 1971 1961 1960 1967

Location Africa Africa South America Asia Middle East Middle East Middle East Africa Africa Middle East Middle East Middle East

1960

South America

Source: OPEC at http://www.opec.org/library/ Notes: # as at 2006 * Founder (**) Ecuador ed OPEC in 1973, suspended its hip from December 1992 to October, 2007

15

Figure IV:

2010/2011 statistics shows that the bulk of OPEC oil reserve is located in Venezuela with 24.8% and Saudi Arabia with 22.2% , followed by four middle East countries, namely Iran 12.7%, Iraq 12.0%, Kuwait 8.50% and United Arab Emirates 8.2%. The statistics show that two third of the OPEC oi reserve (65.70%) is located in the Middle East countries. OPEC (2011) shows that Nigeria has proven oil reserve of 3.1% of total OPEC reserve. Figure V:

However, as against what obtains in some OPEC member countries where National Oil Companies (NOCs) took direct control of production operations, in Nigeria, the Multi-National Oil Companies (MNOCs) were allowed to continue with such operations under t Operating Agreements (JOA), clearly specifying the respective stakes of the companies and the Government of Nigeria in the ventures. As a result, this period also witnessed the arrival on the scene of MNOCs such as the Gulf

16

Oil and Texaco (now ChevronTexaco), Elf Petroleum (now Total), Mobil (now ExxonMobil), and Agip, in addition to Shell, which was already playing a dominant role in the industry. To date, these companies constitute the major players in the Nigerian oil industry, with Shell still maintaining a leading role. t Venture Agreements (JVAs) and Production Sharing Contracts (PSCs) also dominate the production agreements between the oil companies and the NNPC. Similarly, it is worth noting that the exploration of oil and gas in Nigeria had taken place in five major sedimentary basins, namely, the Niger Delta, the Anambra Basin, the Benue Trough, the Chad Basin and the Benin Basin. But, the most prospective basin is the Niger Delta which includes the continental shelf and which makes up most of the proven and possible reserves. All oil production to date has occurred in this basin. In 1971, as oil became more important to the economy, the country established the Nigerian National Oil Corporation (NNOC) and ed OPEC as the 11th member. It acquired 33 /3% in Nigerian Agip and 35% in Elf. NNOC ran as an upstream and downstream company and the petroleum ministry had a regulatory function. On April 1, 1977, a merger between NNOC and the ministry of petroleum created Nigerian National Petroleum Corporation (NNPC). This was to combine the ministry’s regulatory role and NNOC’s commercial functions: exploration, production, transportation, processing, oil refining and marketing. The Nigerian National Petroleum Company (NNPC) was established as a state owned and controlled company, as a dominant player in the downstream sector and a major player in the upstream sector through t venture agreements with all major international players. The regulatory role was later to be assumed by the Petroleum Inspectorate, a unit of NNPC. Through the years, NNPC has been active in seismic exploration onshore and offshore. Its seismic crew, known as Party X, has made several discoveries such as a field in block OPL- 110 in the Niger Delta, the Oredo field, etc. It also carried out work on contract for Phillips Petroleum and other E&P companies in the Chad, Anambra and Benue Basins. But NNPC has depended on the technological capabilities of the major operators, like Shell, Mobil, Gulf (Chevron) and others, which produced the bulk of Nigerian oil and did most of the exploration work.

The NNPC in 2010 developed a comprehensive framework designed to herald the intensification of exploration activities in the Chad Basin. The move was seen as a fresh boost to the Federal Government's efforts to build up the nation's proven oil reserve through exploration of new frontiers for oil and gas production. Oil may be found in commercial quantity in the Chad Basin, because of the discoveries of commercial hydrocarbon deposits in neighboring countries of Chad, Niger and Sudan which have similar structural settings with the Chad Basin. Discoveries made in neighbouring countries in basins with similar structural settings are: Doba, Doseo and Bongor all in Chad amounts to over 2 Billion barrels (Bbbls); Logone Birni in Southern Chad and Northern Cameroun, over 100 Bbbls; and Termit-Agadem Basin in Niger totals over 1bbbls. The search was not limited to the Chad Basin alone but covers extensive inquest in the entire Nigerian Frontier Sedimentary Basins which include- The Anambra, Bida, Dahomey, Gongola/Yola and the Sokota Basins alongside the Middle/Lower Benue Trough. Petroleum has recently (i.e. in 2012) discovered in Anambra Basin, which is now to the league of oil producing states.

The NNPC New Frontier Exploration Services (NFES) Division which is leading the search for crude oil find in the entire Inland Basins acquired 3,550 sq km of 3- D seismic data for processing and interpretation in addition to the already acquired 6000km of 2-D data that was reprocessed. Over 600,000 seismic section and 30,000 well logs were scanned and vectorised for the eventual drilling. Before, 2010, 23 wells have been drilled with two of the wells, Wadi-1 and Kinasar encountering non-commercial gas. 17

1.4 The Nature of Petroleum Assets and the Process of Acquiring it Before an oil company drills for oil, it first evaluates where oil and gas reservoirs might be economically discovered and developed. The procedure involved in acquiring petroleum assets includes the following: (i) Leasing the Rights to Find and Produce: When suitable prospects are identified, the oil company determines who (usually a government in international areas) owns rights to any oil and gas in the prospective areas. In the Nigeria the government own both the surface and the subsurface, as all lands are granted by the government on rent for 99 years. In contrasts, in United States, whoever owns "land" usually owns both the surface rights and mineral rights to the land. Whoever owns, (i.e., has title to), the mineral rights negotiates a lease with the oil company for the rights to explore, develop, and produce the oil and gas. The lease requires the lessee (the oil company), to pay all exploration, development, and production costs, and pays royalty to the lessor. The oil company may choose to form a t venture with other oil and gas companies to co-own the lease and tly explore and develop the property. (ii) Exploring the Leased Property: To find underground petroleum reservoirs requires drilling exploratory wells. Exploration is risky, as a number of exploration wells may have to be abandoned as dry holes, i.e., not commercially productive. Wildcat wells are exploratory wells drilled far from producing fields on structures with no prior production. Several dry holes might be drilled on a large lease before an economically producible reservoir is found. To drill a well, an oil company typically subcontracts much of the work to a drilling company that owns and operates rigs for drilling wells, who can do the drilling more effectively, efficiently and economically because of experience. Drilling contracts may take the form of footage rate contract (requiring installmental payment per foot of hole drilled until the required depth is reached), day rate contract (requiring daily payment of specified amount in respect of the number of feet drilled) or turnkey contract (where the contractor is paid only after satisfactory drilling of well to the required depth and other conditions specified in the contract). (iii)Evaluating and Completing a Well: After a well is drilled to its targeted depth, sophisticated measuring tools are lowered into the hole to help determine the nature, depth, and productive potential of the rock formations encountered. If these recorded measurements, known as well logs, along with recovered rock pieces, i.e., cuttings and core samples, indicate the presence of sufficient oil and gas reserves, then the oil company will elect to spend substantial sums to "complete" the well for safely producing the oil and gas. (iv) Developing the Property: After the reservoir (or field of reservoirs) is found, additional wells (known as development wells) may be drilled and surface equipment installed to enable the field to be efficiently and economically produced. (v) Producing the Property: Oil and gas are produced, separated at the surface, and sold. Any accompanying water production is usually pumped back into the reservoir or another nearby underground rock formation. Production life varies widely by reservoir between over 50 years to only a few years, and some for only a few days. The rate of production typically declines with time because of the reduction in reservoir pressure from reducing the volume of fluids and gas in the reservoir. Production costs are largely fixed costs independent of the production rate. Eventually, a well's production rate declines to a level at which revenues will no longer cover production costs. Petroleum engineers refer to that level or time as the well's economic limit. (vi) Plugging and Abandoning the Financial Property: When a well reaches its economic limit, the well is plugged, i.e., the hole is sealed off at and below the surface, and the surface equipment is removed. Some well and surface equipment can be salvaged for use elsewhere. Plugging and abandonment costs, or P&A costs, are commonly referred to as dismantlement, restoration, and abandonment costs or DR&A costs. Equipment salvage values may offset the 18

plugging and abandonment costs of onshore wells so that net DR&A costs are zero. However, for some offshore wells, estimated future net DR&A costs may exceed $1 million per well due to the cost of removing offshore platforms, equipment, and perhaps pipelines. When a leased property is no longer productive, the lease expires and the oil company plugs the wells and abandons the property. All rights to exploit the minerals revert back to the lessor as the mineral rights owner. 1.5 ing Dilemmas in Oil and Gas ing The nature, complexity, and importance of the petroleum E&P industry have caused the creation of an unusual and complex set of rules and practices for petroleum ing and financial presentation. The nature of petroleum exploration and production raises numerous ing problems. Here are a few: (1) Should the cost of preliminary exploration be recorded as an asset or an expense when no right or lease might be obtained? (2) Given the low success rates for exploratory wells should the well costs be treated as assets or as expenses? Should the cost of a dry hole be capitalized as a cost of finding oil and gas reserves? Suppose a company drills five exploratory wells costing $1 million each, but only one well finds a reservoir and that reservoir is worth $20 million to the company. Should the company recognize an asset for the total $5 million of cost, the $1 million cost of the successful well, the $20 million value of the productive property, or some other amount? (3) The sales prices of oil and gas can fluctuate widely over time. Hence, the value of rights to produce oil and gas may fluctuate widely. Should such value fluctuations affect the amount of the related assets presented in financial statements? (4) If production declines over time and productive life varies by property, how should capitalized costs be amortized and depreciated? (5) Should DR&A costs be recognized when incurred, or should an estimate of future DR&A costs be amortized over the well's estimated productive life? (6) If the oil company forms a t venture and sells portions of the lease to its venture partners, should gain or loss be recognized on the sale? 1.6 The Upstream and the Downstream Sectors of the Nigerian Oil Industry As earlier stated, Shell D’Arcy was the first to discover oil in commercial quantity in Nigeria at Oloibiri, Rivers State (presently, Bayelsa State) in 1956. However intensified search for oil from 1957 to 1959 resulted in discovery of Ebubu and Bomu oil fields in Rivers State, and Ughelli in Delta State, which was the first hydrocarbons find, west of the Niger. By 1961 Mobil, Gulf (now Chevron), Agip, Tenneco and Amoseas (now Texaco) etc ed the search for both onshore and offshore oil and gas in Nigeria. This led to the first offshore discovery in 1964 in Okan field in Delta State. Currently, all the early explorers have discovered oil and are producing it, with an upwards of 3,000 producing oil wells in the country. Prior to 1971, the Government had no t venture participation in the operations of oil companies in Nigeria. By 1971 all concessions earlier granted to the companies were converted to t venture agreements. In 1973, production sharing contract emerged between the NNPC and Ashland, followed by risk service contract between NNPC and Agip Energy and Natural Resources in 1979 and agreements involving these types of contracts were entered into between the NNPC and the oil companies. Foreign oil companies largely dominated the upstream sector until the first discretionary allocation of acreages to indigenous companies in 1990. Oil blocks were allocated to eleven (11) indigenous companies. The companies who operated sole risk contracts, were encourage farm-out (i.e. to assign an interest in a licence to another party) 40 per cent of their interest to foreign 19

companies, mainly for financial and technological back-up (the foreign companies who acquire interest in a licence from another party, are said to have farm-in in indigenous companies minning interest). More allocations were made between 1991 and 1993 and there are now an upwards of forty (40) indigenous private sector companies licensed to prospect for oil in Nigeria’s upstream sector. Some of the companies, including Summit Oil, Consolidated Oil and Amni Petroleum Development Company have made commercial discoveries and are already producing oil, while others are at various stages of exploration and production. In addition the NNPC through two of its subsidiaries- the Nigerian Petroleum Development Company (NPDC) and Direct Exploration Services of the National Petroleum Investment Management Services undertake oil exploration and production. In total, an upwards of 55 companies are operating in Nigeria under t venture, production sharing contract, service contract, sole risk contract and NNPC direct exploration efforts. Nigeria’s expertise in the upstream sector in the African Subregion, which is relatively superior, had attracted a number of African countries to look up to it for assistance. For example in 2010 Uganda and Nigeria have signed MOU on oil and gas industry. The agreement covers human resource training, technological transfer, t projects and offering on evaluation of the crude oil. Crude oil and gas production is expected to start by 2012. There will also be construction of a refinery with a capacity of 150,000 to 200,000 barrels of oil a day. Four companies, including Heritage, Dominion, Neptune and Tullow Oil, are exploring for oil and gas in the Lake Albert basin. The MOU signed between Nigeria and Uganda is a positive development. With increased E&P activities in the region, more countries would be fortunate to discover Oil and Gas reserves in their territories. Activities in the downstream sector were given boast in 1965 with the construction of the first refinery in Port Harcourt by Shell-BP, with an initial capacity of 35,000 bpd, which was later increased. As the economy grew, demand for petroleum products grew along with it necessitating the establishment of Warri refinery in 1978, Kaduna refinery in 1980, and subsequently, another refinery, which is the forth refinery, was built at Port Harcourt to supplement the old one. However, these refineries at various points in time have been bedeviled with problems of sabotage, fire out breaks, poor management and lack of regular turnaround maintenance, thereby making it difficult for the refineries to meet local demands for petroleum products. In similar vein, petrochemical plants were built in Warri and Kaduna in 1988 and subsequently, another company was built in Eleme, near Port Harcourt. These companies were meant to produce polypropylene, carbon black, linear alkyl benzene (LAB), heavy alkylate, benzene, polyethylene and chlorine, among others. Table 3: Installed Capacity of Nigerian Refineries S/N NAME OF THE COMPANY 1 2 3 4

Kaduna Refinery and Petrochemical Company Limited (KRPC). Warri Refinery and Petrochemical Company Limited (WRPC). Port-Harcourt Refinery Company Limited (PHRC). Eleme Petrochemical Company Limited (EPCL).

Total

Date Installed Commissioned Capacity (bpd) 1980

110,000

1979

125,000

1965 1989

35,000 150,000

445,000

20

1.7 NNPC, DPR and Their Roles 1.7.1 Nigerian National Petroleum Corporation (NNPC) The NNPC occupies a central position in the Nigerian oil and gas industry. It was incorporated on April 1, 1977 through Decree No. 33 of 1977, by a merger of the defunct Nigerian National Oil Corporation (NNOC) created by Decree 18 of 1971, and the former Federal Ministry of Petroleum Resources, with Chief Festus Marinho, as the pioneer GMD. NNPC is charged with the responsibility of managing the Nigeria’s oil and gas resources in all segments of the petroleum industry (namely Exploration and Production (E&P), storage and transportation, refining and hydro processing and distribution and marketing). The roles of the corporation include the following: 1. refining, treating, processing and handling of petroleum for the manufacture and production of petroleum product’s and its derivatives; 2. the conduct of research on petroleum and its derivatives and promotion of activities to utilize the results of such research; 3. giving effects to agreements entered into by the Federal Government with a view to securing participation by the Government or the Corporation; 4. engaging in activities which would enhanced the overall well being of the petroleum industry in the overall interest of the country; 5. undertake such activities considered necessary or expedient for giving full effect to the provisions of the law establishing it; and 6. managing Government investment in the oil companies in which the Government has a stake. In l985 the Corporation was organized into five semi-autonomous sectors in the quest to enhance its operational efficiency. These sectors were (1) oil and gas sector, (2) refineries sector, (3) petrochemical sector, (4) pipelines and products marketing, and (5) the petroleum inspectorate. Similarly, the Corporation was re-organized in 1988 with a view to putting it on commercial footing, with three basic areas of responsibilities. These are (1) corporate services (which include finance, istration, public affairs, personnel, legal and technology), (2) operations (which include exploration and production, refining, gas processing and petrochemicals) and (3) National Petroleum Investment Management Services (NAPIMS) -which supervises Government investment in t venture companies, markets oil that accrues to the Government and engages in exploration activities in areas where oil companies consider too risky to venture in to. Another important aspect of the 1988 re-organization was the transfer of the Petroleum Inspectorate back to the Petroleum Resources Department of the Ministry of Petroleum Resources from which it was originally brought to be part of the NNPC. In 1992, another reorganization of the Corporation was carried out which led to the establishment of six directorates (namely (i) exploration and production, (ii) refining and petrochemicals, (iii) engineering and technical, (iv) finance and s, (v) commercial and investment and (vi) corporate services), which each headed by a Group Executive Director (GED) who reports to the Group Managing Direct (GMD). The 1992 reorganization of the Corporation conferred on the crude oil and marketing division of the exploration and production inspectorate the responsibility for marketing the crude oil that accrues to the Government. Similarly, twelve (12) strategic Business Units (SBUs) or subsidiary companies were also established in the 1992 reorganization. Nine of the subsidiaries are fully owned by NNPC, while the remaining three subsidiaries are tly own with foreign oil companies. The ful1y owned subsidiaries of the Corporation are:

21

1. The Nigerian Petroleum Development Company Limited (NPDC) charged with the responsibility for exploration, development and production of petroleum. 2. The integrated Data Services Limited (IDSL) charged with the responsibility of seismic data acquisition, processing and interpretation, petroleum reservoir engineering and data evaluation for NNPC and other oil and gas companies in Nigeria and West Africa. 3. Warri Refinery and Petrochemicals Company Limited (WRPC) charged with the responsibility of refining petroleum and the production of carbon black and polypropylene petrochemicals. 4. Kaduna Refinery and Petrochemicals Company Limited (KRPC) charged with the responsibility of refining petroleum and the production of linear alkyl benzene and heavy alkylalates. 5. Port Harcourt Refining Company Limited (PHRC) charged with the responsibility of refining petroleum especially for export. 6. Pipelines and Products Marketing Company Limited (PPMC) charged with the responsibility of transporting crude oil to the refineries and refined products through its pipelines and deports to markets both locally and internationally. 7. Nigerian Gas Development Company Limited (NGC) charged with the responsibility of gathering, treating and developing gas resources for transmission to major industrial and utility gas companies in Nigeria and neighbouring countries. 8. Eleme Petrochemicals Company Limited (EPCL) charged with the responsibility of manufacturing a range of petrochemicals products such as polyethylene, polyvinyl chloride etc from natural gas and refinery by-products and market them locally and internationally. 9. Nigerian Engineering Technical Company Limited (NETCO) charged with the responsibility of providing engineering services to the NNPC group and other oil companies in the country. The three other subsidiaries that are tly own with foreign oil companies are: 10. Nigeria Liquefied Natural Gas Limited (NLNG) owned tly by the NNPC, Shell, Elf, Agip and International Finance Corporation (IFC) charged with the responsibility of harnessing, processing and marketing gas resources. 11. Calson (Bermuda) Limited initially owned tly by the NNPC and Chevron (but the Government has now divested from the company). Calson is charged with the responsibility of marketing the country‘s excess petroleum products abroad. 12. Hydrocarbon Services Nigeria Limited (HYSON Limited) owned tly by the NNPC and Chevron, and charged with the responsibility of providing logistics and services to Calson (Bermuda) Limited. In addition to these subsidiaries, the industry is also regulated by the Department of Petroleum Resources (DPR), a department within the Ministry of Petroleum Resources. The DPR ensures compliance with industry regulations; processes applications for licenses, leases and permits, establishes and enforces environmental regulations. The DPR, and NAPIMS (National Petroleum Investment Management Services), play a very crucial role in the day to day activities throughout the industry. In order to realize its vision and mission as well as provide optimal service to its customers, the Nigerian National Petroleum Corporation (NNPC) has been structured as follows:

22

Figure VI: Organizational Structure of NNPC GMD’S STAFF GGM, LNG & POWER

MD NETCO

GROUP MANAGING DIRECTOR NNPC M1

MD HYSON MD PPMC

GGM CSLD

GGM PUBLIC AFFAIRS GGM DD GGM AUDIT GGM ETD GGM RENEWABLE ENERGY GGM INVESTMENT GGM R & D GGM NIG. CONTENT

GGM GREENFIELD EXPORT REF.

GGM ITD

GGM CORPORATE STRATEGY MD NIDAS

MD NIKORMA

GED E&P

GGM NAPIMS MD IDSL MD NPDC

GED R&P

GED F&A

GGM S

MD PHRC MD WRPC MD KRPC

GED CS

GGM HR

GGM FINANCE

GGM MEDICAL

GM TREASURY

GGM P&G

MD NGC

GM INSURANCE

GGM COMD

GGM LONDON OFFICE

GGM INT’L VEN. OPP.

1.7.2 THE DEPARTMENT OF PETROLEUM RESOURCES (DPR) Prior to independence in 1960, the Hydrocarbons Section of the Ministry of Lagos Affairs handled petroleum matters in the country. However, when petroleum activities gathered momentum in the country, a petroleum division (later named DPR in 1970) was created under the Ministry for Mines and Power. In 1971, Nigerian National Oil Corporation (NNOC) was created as the commercial arm of the DPR, while DPR itself continued as art of the Ministry of Mines and Power. In 1975, DPR was upgraded to a ministry and named the Ministry of Petroleum and Energy (later renamed the Ministry of Petroleum Resources-MPR). The promulgation of Decree 33 of 1977 merged the MPR with NNOC to form the NNPC. Under the Decree, an inspectorate arm (called the Petroleum Inspectorate) was set up to act as the regulatory arm of the oil and gas industry. In 1985, the MPR was re-established. However, Petroleum Inspectorate remained with NNPC until its re-organization of March 1988 that resulted in the excision of the Inspectorate and its transfer back to the Petroleum Resources Department of the Ministry of Petroleum Resources. The functions of the DPR include the following:

23

1. supervising all petroleum industry operations being carried out under 1iences and leases in the country, with a view to ensuring compliance with the established laws and regulations; 2. monitoring the petroleum industry in order to ensure that operations are in line with national policies and goals; 3. enforcing safety regulations and ensuring that operations conform to national, as well as, international industry practices and standards; 4. keeping and updating records on petroleum industry operations relating to reserves, production/exports, licences and leases, as well as rendering regular reports of them to the Government; 5. advising the Government and relevant agencies on technical matters and public policies, which may have impact on the istration and control of petroleum; 6. processing all applications for licences to ensure compliance with laid down guidelines before making recommendations to the Minister of Petroleum Resources; and 7. ensuring timely and adequate payments of all rents and royalties as and when due.

1.8 PPPRA and the Proposed Petroleum Industry Bill (PIB) 2011 1.8.1 Petroleum Products Pricing Regulatory Agency (PPPRA) The Government on 14th August 2000 set up a 34 member Special Committee on the review of Petroleum Products Supply and Distribution drawn from various Stakeholders and other interest groups to look into the problems of the downstream petroleum sector. It mission is to reposition Nigeria's downstream sub-sector for improved efficiency and transparency. Its vision is to attain a strong, vibrant downstream sub-sector of the petroleum industry, where refining, supply, and distribution of petroleum products are self-financing and self-sustaining. Prior to the setting up of the Committee, the downstream sector was characterized by the following problems: 1. Scarcity of petroleum products leading to long queues at the service stations 2. Low capacity utilization and refining activities at the nation's refineries (poor state of the refineries) 3. Rampant fire accidents as a result of mishandling of products- products adulteration 4. Pipelines vandalisation 5. Large scale smuggling due to unfavourable economic products borders' prices with the neighbouring countries 6. Low investment opportunities in the sector. Functions of PPPRA 1. To determine the pricing policy of petroleum products; 2. To regulate the supply and distribution of petroleum products; 3. To create an information databank through liaison with all relevant agencies to facilitate the making of informed and realistic decisions on pricing policies; 4. To oversee the implementation of the relevant recommendations and programmes of the Federal Government as contained in the White Paper on the Report of the Special Committee

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on the Review of the Petroleum Products Supply and Distribution, taking cognizance of the phasing of specific proposals; 5. To moderate volatility in petroleum products prices, while ensuring reasonable returns to operators. 6. To establish parameters and codes of conduct for all operators in the downstream petroleum sector; 1.8 Petroleum Industry Bill (PIB) 2011 The Petroleum Industry Bill is an attempt to bring under one law the various legislative, regulatory, and fiscal policies, instruments and institutions that govern the Nigerian petroleum industry. The Bill is expected to establish and clarify the rules, procedures and institutions that would entrench good governance, transparency and ability in the oil and gas sector. It aims to introduce new operational and fiscal for revenue management to enable the Nigerian government to retain a higher proportion of the revenues derived from operations in the petroleum industry. The government argues that, since the commencement of oil and gas production in Nigeria in 1958 after the discovery of oil in 1956 in Oloibiri (Bayelsa State), no comprehensive law has been put in place for effective istration of the Nigerian petroleum industry. The PIB therefore seeks to replace sixteen (16) petroleum industry Acts, which have many inadequacies, with an omnibus Act that provides for better fiscal and regulatory management of the oil and gas sector. Oil and gas production commenced in Nigeria in 1958 after the discovery of oil in Oloibiri (Bayelsa State) two years earlier. By the 1990’s Nigeria engaged in a number of unincorporated t ventures with international oil companies to develop the industry. However, the country had challenges funding its commitments to the t ventures. As a result, Production Sharing Contracts (PSC) were introduced as alternative funding mechanisms. However, PSCs lack transparency, good governance practices, and are not in line with international best practices. For instance, Nigeria does not capture any part of windfall profits from increases in crude oil prices. Additionally, cost controls, ing procedures, and acreage management are inadequate. In response to these challenges, the Obasanjo government in 2000 constituted the first Oil and Gas Reform Implementation Committee (OGIC) to recommend a policy for reforming the sector. The recommendations defined the need to separate the commercial institutions in the sector from the regulatory and policy‐making institutions. In 2007, the Yar’Adua government reconstituted OGIC under the chairmanship of Dr. Rilwan Lukman to use the provisions of the National Oil and Gas Policy to setup legal, regulatory, and institutional structures for managing the oil and gas sector.The Lukman Report, submitted in 2008, recommended regulatory and institutional frameworks that when implemented will guarantee greater transparency and ability. This report formed the basis for the first Petroleum Industry Bill (HB 159) that was submitted in 2008 as an Executive Bill. The controversy raised by the Bill prompted the constitution of a federal inter‐agency team headed by Dr. Tim Okon (former NNPC’s Group General Manager on Strategy) to review the Bill. The team’s report submitted in 2010 (IAT 2010) is at the crux of the controversies around the PIB because it introduced more stringent fiscal provisions that guarantee a higher share of oil revenues to Nigeria.In 2011, the Senate submitted its version of the Bill (SB 236) that is seen as a much‐weakened version. Subsequently, the House of Representatives submitted its version of the Bill (HB. 54) in 2011. The Bill was sponsored by six Honourable . The draft Petroleum Industry Bill (PIB) was designed to act as an all-encoming piece of legislation and as a result, some 15 pieces of existing legislation will be revoked upon ratification. It 25

will create a number of new institutions with mandates over the upstream sector. Specifically, the policy making function will reside with the Petroleum Directorate. The Petroleum Inspectorate will replace the Department of Petroleum Resources (DPR), currently within the Ministry of Energy. This commission will act as the independent regulatory body and licensing agency for the upstream sector. On the operational side, NNPC will be replaced by the Nigerian National Petroleum Company Limited (NOC). The vision is to turn NNPC into an integrated oil and gas NOC, and a limited liability company. The National Petroleum Investment Management Services (NAPIMS), currently part of NNPC, will be replaced by the National Petroleum Assets Management Agency (NAPAMA). This body will monitor and approve all upstream costs and manage tax/royalty oil (but not profit oil). NAPAMA will exist outside of the NOC as a separate and independent agency. The Research and Development division within NNPC will be carved out into an independent entity, the National Petroleum Research Center. A separate Frontier Service will also be created. The key objectives of the PIB include: 1. Enhance exploration, exploitation and production of oil and gas: The PIB will eliminate funding bottlenecks, increase investments by comprehensive deregulation of the downstream sector to make it attractive to investors, and increase acreage available for investment by reclaim acreage that is not being developed by the current owners. 2. Increase domestic gas supplies: The Bill provides that all existing and future petroleum mining lessees shall meet their domestic gas supply obligations for the specified periods as the gas will be used for power generation and industrial development. Failure to meet this obligation attracts a stiff penalty. 3. Create a peaceful business environment: The Bill seeks to align the interest of the host communities to those of the oil companies and the government. The Petroleum Host Communities Fund, which will be funded with 10% of the net profit of the oil companies operating in the communities, shall be used to develop the economic and social infrastructure of the host communities. Communities will forfeit contributions in the Fund when vandalism or unrest causes damage to upstream facilities. 4. Fiscal Framework for increased revenue: The PIB establishes a progressive fiscal framework that encourages further investment in the industry whilst increasing accruable revenues to government. The Bill simplifies collection of government revenues from the oil assets, increases the share of royalties in the case of high oil prices, etc. 5. Create a commercially viable National Oil Company: The Bill provides for the full commercialisation of NNPC and the creation of other institutions that will ensure a restructuring of the sector for improved efficiency. 6. Deregulate petroleum product prices: The Bill proposes the full deregulation of the downstream oil sector. A number of the institutions will be responsible for developing the infrastructure to the sector, funding concessionaires and facility management operators. The Petroleum Equalisation Fund will be phased out in line with the development of the infrastructure. 7. Create efficient regulatory entities: The Bill provides for the creation of eight institutions to drive greater transparency and ability. 8. Create transparency: The Bill makes public the of the licenses, leases, contracts and payments in the petroleum sector. When ed, the legislature will transform Nigeria from being one of the most opaque oil industries in the world to one that sets the standards of transparency. 9. Promote Nigeria content: The PIB has far‐reaching local content components. No project will be approved without a comprehensive Nigeria Content Plan including obligations of the investor to purchase local goods and services, engage local companies, employ Nigerians,

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ensure knowledge transfer and encourage Research and Development. The Nigeria Content Monitoring Board will regularly compliance. Through the local content provisions in the Bill and the opportunity to develop small indigenous oil and gas companies, Nigerians will begin to participate more actively in the industry and jobs will be created. 10. Protect health, safety and environment: Every company requiring a license, lease or permit in the upstream and downstream petroleum industry in Nigeria shall conduct their operations in accordance with internationally accepted principles of sustainable development which includes the necessity to ensure that the constitutional rights of present and future generations to a healthy environment is protected. Controversies in the PIB 2011 Different stakeholders have raised concerns about certain provisions of the Bill. Below is a list of the most controversial issues. 1. Fiscal provisions may increase cost of doing business: The Bill provides for multiple taxes (Nigeria Hydrocarbon Tax, Company Income Tax), higher rents and royalties, and levies (Niger Delta Commission Levy, Petroleum Host Community Fund, Education Tax). This is most noticeable in the deep offshore operations. 2. Retroactive reversal of contracts: The PIB advocates reversal of provisions of prior agreements and contracts, and introduces new fiscal regimes even for old Petroleum Sharing Contracts. 3. Relinquish acreage: The PIB provides for the revocation of acreage that is yet to be developed by the allocated owners. Opponents of this provision claim that it is an infringement on earlier agreements while its proponents argue that it is required to bringing new investment to the industry. 4. Calculating payments: The Bill advocates that oil companies will pay for quantities produced instead of quantities exported. The oil companies have argued that solving the security challenge and fixing sabotage of logistics infrastructure is the core responsibility of government. 5. Duplication of roles: There are overlaps of roles and responsibilities with a number of the institutions created under this Bill. For instance, the Nigerian Petroleum Inspectorate, Petroleum Products Regulatory Agency, and Petroleum Infrastructure Development Fund have conflicting responsibility for funding the development of infrastructure especially for the downstream sector of the petroleum industry. 6. Deadline for Gas flaring: According to the PIB (HB.54), December 31st 2012 is the deadline for gas flaring. The integrity of this date is questioned given that the Bill is yet to be ed. 7. Too much power to Minister of Petroleum: The Bill provides the Minister of Petroleum too much power to grant, revoke and reallocate licenses. 8. Lack of Regulatory Independence: Regulators need to be fully independent and not under the supervision of the Minister of Petroleum. 9. Potential delays in ing the Bill and its Consequences on Nigerian economy: Can the 7th National Assembly continue debates from where the last Assembly stopped? This is possible according to Rule 111 of the Senate but there are voices in the Senate that dissent to this interpretation and want the Bill to be reintroduced and for the process to be started all over again. There is also the challenge of harmonizing the different versions of the Bill (Executive, Senate, and House). Failure to the PIB has and will lead to a reduction of investments in the Nigeria petroleum industry. To date, most of the oil companies have ceased investments in the sector until there is clarity as to what provisions will be contained in the final Bill and how it

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will affect the industry. With the rise of other attractive petroleum industries in Africa (Angola, Ghana, etc), Nigeria must understand that investments are fungible and will eventually flow to alternative countries that are more receptive. 2. Oil and Gas Drilling, Cost Classification and Reserves Valuation 2.1 Oil and Gas Drilling Oil and gas drilling is highly capital intensive, requiring a large number of technocrats with fantastic remuneration, thus necessitating pre-drilling operations, before actual drilling. Drilling operations basically comprised of: (i) staking (locating oil well site after dues consideration of a number of natural surface attributes-terrain, body of water, marshy environment, etc) (ii) compliance with regulatory requirements on spacing of oil wells (iii) providing access road to the drilling location, leveling of drill site for placement of working equipments and erection of field offices, and increasing permeability through fracturing, acidizing and thermal process. Two methods of drilling have been used in the oil and gas industry, namely rotary-rig drilling and cable-tool drilling. The cable-tool method is one of the oldest mechanical means known for drilling into the earth's surface. Cable-tool rigs have long been used for drilling water wells and salt brine wells. Cable-Tool Drilling In the cable-tool method of drilling, a heavy piece of forged steel is lowered into the hole. The bit, which weighs several hundred pounds, is raised and then dropped in the hole, literally pounding a hole in the earth. Water is pumped into the hole to float the cuttings of rock away from the bottom of the hole. Rotary Rig Drilling Rotary drilling is by far the most widely used method of drilling for oil and gas today. In rotary operations, the hole is drilled by rotating a drill bit downward through the formations. The usual oil and gas drilling practice entails the engagement of an independent drilling contractor, who can do the drilling more effectively, efficiently and economically because of experience. Drilling contracts may take the form of (i) footage rate contract (requiring installment payment per foot of hole drilled until the required depth is reached), (ii) day rate contract (requiring daily payment of specified amount respect of the number of feet drilled) or (iii) turnkey contract (where the contractor is paid only after satisfactory drilling of well to the required depth and other conditions specified in the contract). Presently, footage rate contracts are the most popular although day rate contracts are also common, while turnkey contracts are less common. Some of the major problems encountered in oil and gas drilling may include the following: 1. the excess of formation pressure which may lead to blowout which is dangerous to the ecosystem. For example on 22 April 2010 estimated 550-900 kb of oil leaked into the sea in US very significantly affecting local economic activities like fishing, farming and tourism. Similarly, in 1982, a high profile blowout at Amoco Canada killed 2 workers and hundreds of cattle. 2. twisting off of part of drill string which may lead to the abandonment of oil well and the drilling of another well; 3. collapse of part of the drilled hole may be experienced, leaving the pipe trapped in the depths; and

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4. the formation may exude hydrogen sulphide, which is a gas with a very foul odour, thereby necessitating abandonment of well. For example In 2003, 243 people in China were killed, and 3 workers of Abu Dhabi Company operating at Shah Oilfield in Iran were killed by the toxic hydrogen sulphide gas emitted from crude oil. The gas is heavier than air, and even at low concentrations it can cause respiratory failure and brain damage. 2.2 Types of Oil and Gas Wells There are different types of oil and gas wells and the drilling methods and logistics usually depend on the type of well to be drilled. Eight types of oil and gas wells can be identified. These are: (1) Wildcat (exploratory) well (an oil well that is drilled to establish the presence or otherwise of oil and gas, which may result in proved reserves or dry hole); (2) discovery well (this is a wildcat well in which hydrocarbons is discovered in commercial quantity); (3) appraisal well (this is a well that is drilled after successful exploratory drilling, to provide information about the volume-customarily measured in acre-feet- and its commercial viability); (4) development (production) well (this is a well that is drilled with a view to obtaining access to proved reserved and to produce oil). Other types of oil and gas wells include: (5) deviated well (a well that is progressively digresses from the vertical due to inability to access the site selected with a view to meeting the location that is most likely to yield oil); (6) injection well (a well that is drilled to injecting subsurface water or gas for the purpose of using secondary drilling methods; (7) observation well (a well that is drilled in order to permit further survey and study of a reservoir as production continues); and (8) obligatory well (an exploratory well that is obligatorily drilled as part of the conditions for granting a mineral licence). However, it is important to note that the volume of oil-in-place can be estimated after determining the (i) thickness the oil zone (also called the pay zone), (ii) the porosity and permeability. This estimate will provide the basis for the desirability of further investment or the plugging or the abandonment of the well. If indications show that further investment is justifiable because revenues will exceeds the additional cost of completion, the operator would go ahead to complete the well. Well completion refers to the preparations and installations made in a well in order to get it ready for oil and gas production. Thus, at the completion of the drilling operations, the hole drilled is cased to ensure that it does not collapse and that it does not flow to the surface or to other formations. The flow of oil and gas to the surface is made possible with the help of reservoir’s Bottom Hole Pressure (BHP). However, if the flow of oil and gas is not possible due to low BHP, installation of artificial pumps may be necessary. In order to control the flow at the surface, a number of valves, fittings, choke and pressure gauges are mounted on the wellhead. A flow line is connected to the pressure gauges through which the oil is evacuated to a storage and processing centre. As a single well will not permit timely and economical extraction of oil, development wells will have to be drilled, after the successful drilling of exploratory wells. Because the fluids from the wells may contain oil, gas, water, sand and other impurities such as hydrogen sulphide, the crude oil must have to be cleaned to remove all impurities before it is piped to the refinery or gas plants. Equipments found in oil storage centre are test separators, production filters, tank batteries, circulating pumps, gas metres, and salt water disposal pits, etc. Crude oil is sold or transmitted to refineries and gas is piped to gas plant. BHP that enables oil and gas to flow to the surface diminishes as the reservoir is depleted. 29

Recovery of hydrocarbons that occur by BHP or simple artificial lift is known as primary recovery. When the oil can no longer flow to the surface due to diminishing BHP, more complex techniques known as secondary and tertiary recovery methods may have to be applied to enhance recovery from the reservoir oil. The enhancement techniques used may be broadly grouped in to two, namely injection projects (which include water flooding, high pressure gas drive, enriched gas drive, etc) and thermal processes (which include fire flooding and steam heating). In 2007,2008 and 2009 improved recovery increased oil volumes by 20, 37 and 86 million barrels worldwide, respectively. In 2009, the largest addition was related to improved secondary recovery in Nigeria. 2.3 Classification of Costs in the Oil and Gas industry In the oil and gas industry, costs are classified either by nature and function of the costs (namely (i) acquisition cost, (ii) exploration and appraisal costs, (iii) development costs, (iii) production costs and (iv) ing facilities and equipments costs) or by the physical characteristics of the assets acquired (namely (i) tangible and (ii) intangible costs). Acquisition Costs: These are incurred to purchase, lease or otherwise acquire a property (whether proved or unproved). Example includes the cost of signature or lease bonuses, options to purchase or lease properties, brokerage, legal fees, etc. Exploration and Appraisal Costs: These are cost incurred to prospect for oil, before oil reservoir is developed. Examples include costs associated with geological, geophysical and other pre-drilling costs, including remuneration of personnel involved. It also include costs of drilling, dry hole and bottom hole pressure enhancement. They also include depreciation, amortization and allocated operating costs of equipment facilities. Development Costs: These are costs incurred to gain access to proved reserves and provide facilities for drilling, lifting, treating, gathering and storing oil and gas. They include depreciation and allocated operating costs of equipment facilities. Production Costs: These are costs incurred in lifting, treating, gathering and storing oil and gas. They include costs of personnel engaged in operation of wells and related equipment facilities, repair and maintenance of production facilities, materials, supplies, insurance, services and fuel consumed in such operations. They also include allocated operating costs of equipment facilities, but do not include DD&A of license acquisition, exploration and development costs and cost of decommissioning. ing Facilities and Equipment Costs: These are cost relating to trucks, drilling equipments, workshops, warehouses, camps division and field offices. Usually, these facilities and equipment serve one or more activity relation to acquisition, exploration, development and production. These costs are therefore capitalized and apportioned to the different activities. Tangible and Intangible Costs Tangible costs are cost of assets, like machinery, equipment, vehicles, which have physical properties (including the costs of labour to install them even though those costs do not result in a physical asset). On the other hand, intangible cost is cost that result in assets that have no physical properties, or assets that have physical properties but that cannot be salvaged at the end of an operation e.g. cost of drilling paid to contractor, labour for clearing services such as acidizing, fracturing and thermal processes.

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2.4 Estimation and Valuation of Oil and Gas Reserves Despite the large figure for property, plant and equipment that the balance sheet of an oil and gas companies usually show the true value of an oil and gas company is its proved oil and gas reserves in the ground. The assets may not be worth much without the reserves. Therefore, the value of oil and gas reserves is critical for the evaluation of financial position and results of oil and gas company’s exploration and production activities. Oil reserves can simply be defined as the value of oil and gas recoverable from oil-in-place. Oil-in-place is defined as the oil and gas in the earth, the presence of which is confirmed by drilling. It is an estimation of the original volume of hydrocarbons that occupied the reservoir before production. The importance of proper understanding of reserves and reserve estimates includes the following: (i) serves as a basis for financing or investment decision; (ii) serves as a basis for computing the depreciation, depletion, and amortization rates; (iii) it is an important item of disclosure in annual reports and s (SAS 14); (iv) serves as a basis for managements estimate of internally generated cash flows and better operational decisions; and (v) serves as a basis for determining cost ceiling (in companies using full cost method of ing) and finding cost (for all companies either using full cost and successful effort method of ing). However, oil and gas reserves estimates are usually imprecise due to inherent uncertainties and limited nature of information on which reserves estimation is based. Two or more petroleum reservoir engineers, using the same data about a producing field may arrived at widely dissimilar estimates of the reserves. Hence, the use of outside consultants by most large oil and gas companies to carry our reserve audit with a view to adding credibility to estimates prepared internally. Usually, the reliability of reserves estimation will increase after reservoir has been fully developed and the field goes into production. However, in developing estimates of reserves the following information is essential. These are: (a) area and thickness of the productive zone; (b) porosity of the reservoir rock; (c) permeability of the reservoir rock to fluid; (d) oil, gas and water saturation, i.e. the portion of the pore space that is filled with oil, gas and water; (e) physical characteristics of oil and gas, i.e. the shape and size of oil-bearing formation which affects both porosity and permeability; (f) depth of the producing formation; (g) reservoir pressure and temperature; (h) production history of the reservoir; and (i) ownership of the oil and gas property. After petroleum reservoir engineers have estimated reserve quantity, it must then be valued in monetary . The following are the factors that may affect reserve valuation: (i) projected rate of inflation and expected future price changes; (ii) political stability of host countries; (iii) Macro economic conditions. (iv) Prospective changes in legislation and taxation. (v) Contractual obligations. (vi) Crude oil prices, especially OPEC Prices; and 31

(vii)

Discount rate and cost of capital

2.5 Classification of Reserves Classifications of reserves are usually based on the professional judgments of petroleum reservoir engineers and geologists arising from a range of geological and geophysical studies carried out. Oil and gas reserves may be classified into (i) primary, (i) secondary and (iii) tertiary reserves. Primary reserves are reserves that are recoverable using any method possible where the oil and gas enters the well bore by the action of the natural reservoir pressure (BHP). Primary reserve may be classified based on: (i) degree of proof (comprising of proved, probable and possible reserves); Proved reserve is further subdivided into proved developed and proved under-developed reserves. Proved developed oil and gas reserves are reserves that can be recovered through existing wells with existing equipments and operating methods. While, proved underdeveloped reserves are oil and gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where relatively major expenditure is required for completion. Probable reserves are estimated quantities of commercially recoverable oil and gas reserves that may be estimated or indicated to exist based on geological, geophysical, and engineering data. Possible reserve are estimated quantities of commercially recoverable oil and gas reserves that are less well defined than probable reserves and that may be estimated or inferred largely on the basis of geological and geophysical evidence. (ii) development status (comprising of developed and under-developed reserves); and based on (iii) production status (comprising of producing and non-producing reserves). However, secondary and tertiary reserves are reserves that are recoverable through secondary and tertiary recovery methods, involving injection projects and thermal processes. The world's reserve values by country are not publicly disclosed, but estimated reserve volumes are. Table 2 summarizes the world's proved oil and gas reserves, production, and oil wells by country. Over 92 percent of the world's proved oil and gas reserves are found in the 17 countries listed in Table 2. The top ten countries have nearly 80 percent of the world’s oil and gas reserves and the majority of the world’s current production. Sixty-four percent of the world's proved oil reserves are in five Middle East countries, and the majority of the world's proved oil and gas reserves are in only four countries—Saudi Arabia, Canada, Iran and Iraq.

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Table 4: Summary of Top 17 World Reserve Data as at Dec.,2008 Reserve Reserves Production Life Country 109 109 106 years bbl m3 bbl/d m3/d Saudi Arabia 42.4 10.2 1,620 72 267 Canada 28.5 3.3 520 179 149 Iran 21.9 4 640 95 138 Iraq 115 18.3 2.1 330 150 Kuwait 104 16.5 2.6 410 110 United Arab Emirates 98 15.6 2.9 460 93 Venezuela 87 13.8 2.7 430 88 Russia 60 9.5 9.9 1,570 17 Libya 41 6.5 1.7 270 66 Nigeria 36 5.7 2.4 380 41 Kazakhstan 30 4.8 1.4 220 59 United States 21 3.3 7.5 1,190 8 China 16 2.5 3.9 620 11 Qatar 15 2.4 0.9 140 46 Algeria 12 1.9 2.2 350 15 Brazil 12 1.9 2.3 370 14 Mexico 12 1.9 3.5 560 9 Total Top 17 Reserves 1,243 197.4 63.5 10,080 54 Source: NNPC Newsletter, December 11, 2009

3. Arrangements, Agreements and Contracts in the Nigerian Petroleum Industry The (i) high risk, technology and capital intensiveness of oil and gas operations often require that negotiations are made between the host country and foreign oil company for hydrocarbon exploitation, disposal, risk sharing and pooling of capital. Similarly, because of the (ii) international politics of oil and gas, as well as, (iii) its strategic position in the economy of the producing countries in particular and the world at large, most Government prefer to work out participation arrangements with multinational oil and gas company rather than just overseeing the operations. The conditions and term of the agreements result in operating agreements, with varied modus operandi among countries. 3.1 Types of operating contracts in the petroleum industry There are at least seven basic types of operating agreements in the international oil and gas industry. These are (i) concession, (ii) t venture, (iii) production sharing contract, (iv) service contract with or without risk (v) indigenous contracts, (vi) direct exploration and (vii) hybrid contract. 3.1.1 Concession: In a concession agreement, a country grants to an oil company or a group of oil companies the exclusive right to carry out certain types of petroleum operations within a given oil area of its territory for a specified period of time for payment of royalties. This agreement, which was type of agreement in many host nations, has the least advantages to the host government as it relinquishes its sovereignty to operating oil company and its fiscal returns, state participation, and training of nationals is at lowest level. As explained earlier, Shell D’Arey which was the first oil company to discover oil in commercial quantity in Nigeria operated under a concession arrangement

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and an exclusive exploration right. Others like Mobil, Gulf (now Chevron), Safrap (now Elf), Tenneco and Amoseas (now Texaco) also operated under the concession agreement. 3.1.2 t Venture (JV): A JV is defined as a situation where one or more foreign oil companies enter into agreement with the host government (through its agent like the NNPC) for t development of tly held oil mining licenses and facilities. Each partner in the t venture contributes to the costs and shares the benefits or losses of the operation, in accordance with its proportionate equity interest in the venture. One company is designated as the operator and is responsible for the day-today running of the venture, and all budgets, work programmes and any contract awarded must, however, be agreed by all parties. t ventures are the agreements in place for shallow water and onshore exploration and for downstream ventures. Production from JV s for approximately 95 percent of the Nigeria’s crude oil production. The largest JV operated by Shell Petroleum Development Company of Nigeria Ltd and NNPC, produces nearly half of Nigeria’s crude oil, with average daily production of approximately 1.1 million bpd. In JV arrangement, the government (NNPC) is a non-operating partner with the oil company as the operator of the concessions. The Government contributes proportionately to the costs of carrying out the oil and gas operating and lifts its equity share of the crude oil won. In addition, Memorandum of Understanding (MOU), governs the manner in which revenues from the venture are allocated between the partners, including payment of taxes, royalties and industry margin. The income derived from the operations is also shared in proportion to the equity interests of the parties to the JV, with each party bearing the cost of its royalty and tax obligations in the same proportion. Allocations are also made from the revenue to take care of operating cost. Some of the constraints associated with JV are namely (i) poor funding and consequential loss in revenue; (ii) allegations of gold plating of operating costs by the non-operators of the venture leading to mutual suspicious; and (iii) pressure on the operator to meet incessant demands by oil producing communities. However, the emergence of offshore oil and gas operations in Nigeria has witnessed a shift from JVA regimes to Production Sharing Contracts (PSCs). This shift is attributed to a number of factors ranging from the complexity of operations in the offshore terrain to (which makes regulations under the JVA more difficult); to dwindling resources of the country (which makes funding under JVAs precarious for the government).

3.1.3 Production Sharing Contract (PSC): Production sharing contract (PSC) on the other hand, focuses on the sharing of the output of oil and gas operations in agreed proportions between the Oil company, as a contractor to the Government, and the NNPC as the representative of government interests in the venture. This form of contract which originates from Indonesian in 1996, was modeled along the lines of share cropping in agriculture, where the landlord grants a farmer the rights to grow crops on his land and shares the proceeds with the farmer in agreed proportions after the harvests. This type of agreement was first signed in Nigeria with Ashland oil in June 1973. From the proceeds, up to 40 percent was set aside to amortize the company’s investment and pay royalties (cost oil), and about 55 percent was set aside for the payment of Petroleum Profits Tax (PPT) (Tax oil). The remaining proceeds of 5 percent called profit oil are then shared between the Government and the company in crude oil in a ratio of 65:35 respectively. There was a proviso for the Government’s percentage share of profit oil to increase to 70 percent when production reaches 50,000 or more barrels per day. A barrel is a measure representing 35 Imperial gallons or 42 US gallons. Companies engage in PSC in Nigeria include Statoil, Snepco, Elf, Model, Chevron etc. 34

In PSC, host government (through its agent) engages a competent contractor to carry out petroleum operations Government’s wholly owned acreage (oil block). The contractor undertakes the initial exploration risks and recovers his costs only when oil is discovered in commercial quantities. If no oil is found, the company receives no compensation. Under the PSC, royalty oil is a first-charge item assigned to the government free of any exploration, development and production costs. Thereafter, the contractor has the full right to only cost oil (i.e. oil to guarantee return on investment). He can also dispose of the tax oil (oil to defray tax obligations) on Government’s behalf. The residual oil is the profit oil, if any, and the company shares with the concession holder in some agreed percentage. The main law which regulates the operation of PSCs in Nigeria is the deep Offshore and Inland Basin Product Sharing contracts Act N0.9, LFN, 1999. This law provides for payment of a flat rate of 50% tax on petroleum profits by PSC operators, and sets different royalty regimes, depending on the water depth in which the operation is carried out, ranging from 12% for water depths of 200500m, to 10% for water depths in excess of 1,000m. PSCs in inland basins attract a flat rate of 10%. Some of the advantages of PSC include relative flexibility in the management of the operations, no financial burden on the host country, payment to the contractor is made in oil after a commercial find, reliance on the technical know-how and experience of the contractor oil company, etc. some of its drawbacks include risky nature of operations due to non-transferability of costs from now acreage to another when no oil is found and the allegations of gold plaiting costs by the host country. 3.1.4 Service Contract with or without Risk: Service contract (SC) is an operating arrangement similar to PSC whereby service contractor provides all the funds for exploration, development and production activities, while the title to the oil is owned by the NNPC. Like in PSC, the initial duration of the contract is usually 5 to 6 years and the contract terminates automatically of no commercial discovery is made. In the event of such termination both the NNPC and the contractor owe each other no further obligation with respect to the contract. If exploration is successful and production commences, the contractor’s Exploration and development (E&D) costs are recovered in accordance with the conditions stipulated in the contract. Usually the E&D costs are paid installmentally over an agreed period of time, usually 5 years. Unlike PSC, the contractor has no little to any of the portion of the crude oil produce, but may be allowed the option to be given reimbursement and remuneration in oil as an additional incentive for the risk taking. Similar, the contractor has the first option to purchase certain fixed quantities of crude oil produced from Sc areas. At a point in time there was only one SC in place in Nigeria between the NNPC and Agip Energy and natural resources, which covers only one oil mining lease. Service Contract without risk is a contract agreement whereby an oil company carries out exploration, development and production activities on behalf of and on of the national oil company, with the state bearing all risks and the exclusive right to all resources discovered. While, service contract with risk is similar to service contract without risk, except that if no discovery is made, the contractor is negated and the oil company loses all its investments. Similarly, if oil is located, the contractor oil company receives monetary compensation, usually payment in crude oil. 3.1.5 Indigenous Contracts: Indigenous Contract is an arrangement whereby concessions are owned by the NNPC but allocated to indigenous companies to operate. The NNPC regulate and approve technical aspects of the operations and make no financial contribution to E&D activities. Unlike JV or PSC where the NNPC is entitled to crude oil in one form or the other, the indigenous companies only pay royalties and petroleum profits tax to the Government. It is a step taken by the Government to encourage indigenous participation in the E&P of oil and gas in the country. There are an upwards of 38 companies that are engage in this arrangement, among which are Summit oil, 35

consolidated oil, General, Sufra, Union dubri and Amni Petroleum development Company. Some of the companies have made commercial discoveries and are already producing oil, while others are at various stages of exploration and production. 3.1.6 NNPC’s Direct Exploration: The NNPC through its subsidiaries (NAPIMS and NPDC) carry out all operations associated with the search, development and production of oil and gas resources in Nigeria. 3.1.7 Hybrid Agreement: It is usually common to find a hybrid agreement that combine elements of different agreements. For example NNPC worked out an alternative funding arrangement with the oil companies known as PSC hybrid NNPC carry arrangement, due to the inability of the Nigerian Government to fund JVAs as a result of dwindling revenue. In this arrangement, which is a hybrid of JV and PSC, the oil companies in the JV carry the NNP share of capital costs while the NNPC continues to be cash called for operating expenses. 3.2 Financial and Fiscal Monitoring Mechanisms in the petroleum Industry Monitoring mechanism can be defined as the procedures and controls (both internal and external) put in place by the Government with the of the operating partner with a view to ensuring that exploration, development and production activities are hitch-free and are carried out efficiently and effectively in the upstream sector. The monitoring mechanisms for the various types of contract arrangements (i.e. JV, PSC and SC) are similar in nature and can be grouped into three broad categories, as follows: (i)istrative Monitoring Mechanism (AMM); (ii)Technical Monitoring Mechanism (TMM); and (iii)Financial and Fiscal Monitoring Mechanism (F&FMM) istrative monitoring mechanism is mainly about ensuring due process, mutually beneficial negotiations, appropriateness of contractual arrangement and appointment of the right contractor. Technical monitoring mechanisms are meant to ensure that the production and development of oil is done efficiently and is carried out in a hitch-free operating upstream sector. While financial and fiscal monitoring mechanisms are instituted to ensure financial and fiscal ability of oil and gas operations, through the following measures: (i) Yearly Budget Preparation and Approval: Yearly budgets are prepared and submitted for scrutiny and approval of the management committee, which is made up of representatives of the operators, the Government and other parties that are involved, based on the participating agreement. The committee is responsible for betting the budget, recommending for approval (after amendments if any suggested by the committee), providing supervisory control and monitoring on the implementation of the budget and comparing the actual budget results against the standard at the end of the budget period. While the NNPC appoint the committee’s chairman, the operator appoints the secretary. The committee is responsible for creating sub-committees to take care of finance, budget monitoring and other similar issues. (ii) Book-keeping, Financial Reports and Returns: The operator or contractor is responsible for keeping proper books of s in line with modern petroleum industry ing practices and procedures and reports such information in accordance with stipulated format of reporting in the industry. of the management committee have the right to access such books and s which must be kept at the ed office of the contractor in Nigeria, along with the statement of in the stipulated format, within 60 days from the end of each month and each quarter and 90 days from the end of the financial year. The operator must not omit or amend any item of the budget 36

without a written approval of the management committee and its relevant subcommittee(s). (iii) Internal Audit: The operator is obligated to establish an effective system of internal audit base on well establish internal control system in respect of operations. of the management committee have right of access to all the internal audit reports and replies to audit queries raised by the internal auditor in respect of the operations. (iv) External or Statutory Audit: The operator’s financial statements with respect to the operations must be audited by the operator’s statutory auditors as examined and verified by each of the non operators appointed auditors. (v) Non-Operators Right of Audit: A non-operator may carry out or course to be carried out, periodic audit of the books of s and all ing records relating to the operation. Any discrepancies in the must be queried within 36 days from the date of receipt of the by the non-operator. This time limit does not apply in the case of fraud. The NNPC today carry out value for money audit with a view to ascertaining the effectiveness, economical and efficiency of all JV operations in which it is a partner. (vi) Cost Oil Approval: In the case of PSC petroleum won from operation are classified into royalty oil, cost oil, equity oil, tax oil and profit oil. While profit oil stipulates the percentage of allocation of profit oil base on monthly average production, the contractor cannot recover any cost oil unless there is prior approval by the NNPC. (vii) Over Expenditure of Work Programme and Budget: When it is necessary to carry out agreed work programme, an operator may during any calendar year over-expend any budget line item by an amount not exceeding: (a) 10% of the amount budgeted; (b) In case of JV operation, either 10% of’ the amount budgeted or 2 million US Dollars, whichever is less. However, the foregoing shall not authorize the operator to over-expend the total amount of the budget for any calendar year by more than 5%, without informing the other parties to obtain approval, as soon as the over-expenditure is foreseen by the operator. 4. ing Principles and Standards in the Oil and Gas industry 4.1 Petroleum ing and Generally Accepted ing Principles (GAAPs) ing principles could be defined as those rules of action or conduct, which are adopted by the ants universally while recording ing transactions. IAS I defined ing principles as “a body of doctrines commonly associated with theory and procedures of ing, serving as an explanation of current practices and as a guide for selection of conventions or procedures where alternatives exist”. The principles that impact most on oil and gas ing practices can be classified into two categories, namely: a) ing concepts; and b) ing conventions. 4.1.1 ing Concepts This refers to those basic assumptions or conditions upon which the science of ing is based. They are usually rules and conventions that lay down the way in which activities of a business are recorded. These are: 1) Entity Concept: According to the standard, “every economic entity regardless of its legal form of existence is treated as a separate entity from parties having propriety or economic interest in it”. In ing, business is considered to be a separate entity from the proprietor(s). This concept is applicable to all forms of business organizations, including the oil and gas companies. 37

2) Going-Concern Concept: This is the assumption that a business will continue to operate indefinitely into the foreseeable future; that is, the business is not expected to liquidate in the near future. The economic environment of oil and gas industry is highly political and the risk of nationalization is high. Also, companies may be nearing the expiration of their lease periods without any hope for renewal of the lease or obtaining another lease. Such events must be taken into in determining their going concern status. 3) Periodicity Concept: According to this concept, the life of the business should be divided into appropriate segments for the purpose of determining its financial performance. In ing, such a segment or time interval is called ‘ing period”. It is usually a period of twelve months, which can start any time and end any time, without necessarily required to be in line of a calendar year, which must start January and end 31st December. In the oil and gas industry, the financial year is line with government fiscal year which must starts January 1 and ends December 31st and companies do not mostly have the discretion to vary it. 4) Realization Concept: This concept states that revenue is recognized when a sale is made. Sale is considered complete at the point when the property in the goods es to the buyer and he becomes legally liable to pay. The specific application of this principle is that in the petroleum industry, crude oil is deemed sold as produced and therefore revenue may be recognized on crude oil produced. However, on the basis of this principle, revenue cannot be recognized on oil and gas reserves. 5) Matching Concept: According to this concept, the earned revenue and all the incurred costs that generate that revenue must be matched and reported for the period with a view to determining the net financial performance of a business. The term “matching” means appropriate association of related revenues and expenses. This concept applied in oil and gas ing more especially in ing for impairment and in computation of depreciation, depletion and amortization. 6) Historical Cost Concept: This concept states that the basis for initial ing recognition of all assets acquisitions, services rendered or received, expenses incurred, creditors and owners’ interests is the actual cost for the transaction(s). This principle is greatly applied in computing depreciation, depletion and amortization, allowances for impairments, and recognition of gain or loss on conveyances. An extension of this principle in oil and gas ing is the ceiling test concept, which stipulates that the total capitalised cost in the oil and gas company books should not exceed the estimated value of reserves at the reporting date, since the oil reserves are the most important economic assets own by the company. The whole essence is to ensure that cots are not capitalized in the books that are not backed up by economic assets. 7) Money Measurement: ing is only concern with those activities that can be measured in money with fair degree of accuracy and objectivity. The peculiar nature of oil and gas ing is that its major economic asset, oil and gas reserves are not reflected in the balance sheet, yet the final s provide a true and fair representation of the financial results. 8) Dual Aspect Concept: This states that there are two aspects of ing; one represented by the resources owned by a business and the other, by the claim against them. Double entry is therefore meant to uphold this concept. This concept is applicable to all forms of business organizations, including the oil and gas companies. 4.1.2 ing Conventions These are customs or traditions, which guide the ant while preparing the ing statements. In other words, ing conventions are approaches to the application of ing concepts. These include: 38

1) Conservatism/Prudence: This states that greater care in the recognition of profit should be exercised whilst all known expenses, even those that cannot be accurately calculated with fair degree of accuracy and objectivity should be adequately provided for by way of provision. Prudence runs through the whole gamut oil and gas ing and should be effectively applied because oil operations are particularly more risky and has higher potentials for loss. Prudence in oil and gas ing requires that reserves should he estimated objectively and only the latest reserve estimates should be used. It is also prudent to recognize impairment in the cost of unproved properties and ensure that only valuable costs are retained in the books. 2) Materiality: The principle holds that only items of material values are accorded their strict ing treatment. This means that perfect ing treatment may not be applied to transactions that are of insignificant value both in amount, intention and effect on the . In this respect, a purely capital item may be expensed if it is not material. This convention applies to oil and gas ing. 3) Consistency Concept: This concept holds that when an enterprise has adopted an ing method of treating transactions, it should continue to use that method in subsequent periods so that comparison of ing figures overtime could be made possible. Oil and gas ing principles accommodate different practices based on defined assumptions, though the consistency principle states that once an oil company adopts FC or SE, it should stick to the method, and disclosure is required when change in an ing method becomes inevitable, and the consequences of such change on the financial statements should also be disclosed. 4) Substance over Form: This convention states that business transaction should be ed for and presented in accordance with their substance and financial reality and not merely with their legal form. This convention applies in the oil and gas industry. 5) Objectivity/Fairness: According to this convention, data presented on the financial statements should be ed by verifiable evidence and demand the independence of judgment on the part of the ant preparing the financial statements. Similarly, it is required that ing reports should be prepared not to favour any group or segment of society. Because of its peculiarities, financial statements of oil and gas companies require far more disclosures than that of other industries. These disclosures are expected to corroborate the statements, provide ing information and provide details for the numbers on the financial statements. 4.2 Method of ing in the Oil and Gas Industry Two methods of ing are now generally accepted for the oil and gas industry. These are Successful Efforts Method (SEM) and Full Cost Method (FCM). SEM is the method where all exploration costs (namely acreage cost, costs of geological and geophysical surveys, cost of dry holes etc) are charged to expenses, while those that lead to discovery of reserves are capitalized. It gives due cognizance to the ing concept of conservatism/prudence. On the other hand, the FCM is a method in which all acquisition, exploration and development costs are capitalized whether they lead to the discovery of oil reserves or not. Proponents of FCM are of the view that finding commercially producible hydrocarbons is an overall objective that should not be evaluated on well by well basis, as such all costs incurred are part of the cost of whatever reserves are found, because the good must the bad. While advocates of successful efforts method held that any drilling effort that proves to be unsuccessful is a loss that must be expense immediately.

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Prior to 1950, most oil and gas companies used some form of SEM to for oil and gas exploration, development and production. Generally, the practice was to expense dry hole costs and intangible drilling costs on productive wells and capitalizes the costs of property acquisition, wells and equipment. These capitalized costs are amortized if reverse were found or charged to expense if reserve were not discovered. However, with emergence of more sophisticated exploration technology in the 1960’s a new method of ing oil and gas activities know as full cost method, in which all cost incurred in exploration and development of oil and gas reserves were capitalized in a cost centre regardless of whether reserves were discovered or not. While controversy raged, practical application of each of the two methods varied from company to company. Some s of SEM capitalized all geological and geographical exploration costs, others expense them. Similarly, while some s expense dry exploration wells, others capitalize dry development wells, etc. In an attempt to ensure a decision-relevant financial reporting, the FASB issue an explore draft in 1977 titled: Financial ing and Reporting by Oil and Gas Producing Companies: which indicated the need for all companies to use the SEM in their reports. However, the FASB’s effort was scuttled by US SEC and other government agencies; and their argument were simply on the fact that; not until the viability of the SEM over the FCM is proved, the call for adopting the SEM was uncalled for. Therefore, oil and gas reporting practice has been a source of concern to stakeholders since the 1970s and the recent ing scandals of the 1990s have once again brought the issue into the limelight. One of the major issues bedeviling the industry is the fact that the conventional cost ing does not cater for the information needs of various stakeholders. The non appearance of the most valuable assets i.e. oil reserves, on oil and gas companies’ financial reports is unique to the industry. Consequently, since such assets constitute the basis for determining the company’s performance and the fact that the cost of such assets are ed for, differently by different companies puts the value-relevance of the reports into question. The two methods used to for costs in the industry result to a number of inconsistencies: thus ensued the debate on which of the methods is most suitable to be used by the oil and gas companies. Unlike many other industries, costs here are classified based on the nature of operations rather than the nature of a particular cost itself. As such the costs that characterized the operations of the industry are basically incurred at four stages which include (i) the costs incurred in acquiring the mineral interest in property (leasing), (ii) exploring the property (drilling), (iii) developing the proved reserves, and (iv) producing (lifting) the oil and gas. However, the fundamental ing issue lies at the exploration stage, i.e. whether to capitalize or expense the exploration cost which do not result to proved reserves. Since all other costs are treated alike by all companies, companies that capitalize only the exploration cost which result to proved reserves are called SE companies, whereas companies that capitalize all exploration costs, even those that do not result to proved reserves, are called FC companies. This is obviously a source of concern, since the two methods used to for exploration costs differ significantly. Consequently, ing standard setters are faced with a serious challenge that bedeviled the profession for decades. The choice of either of the methods generated a heated debate amongst stakeholders; including the following; 1. Economic Perspective The proponent of the FCM argued that because the FC companies are smaller than the SE companies, switching from SEM would reduce their reported earning; increase the possibility for them to default on their loan servicing; making it difficult for them to assess capital which will 40

reduce the companies competitiveness. Also, they contend that the FC companies are most aggressive in exploration activities. Hence, the method offers higher value-relevance than the SEM. On the other hand, the need for the adoption of the SEM is based on the fact that the method better reflects the realities (risk and failures) associated with the industry’s operations. Hence, the method would eliminate the inconsistencies bedeviling the industry, offer better means for comparison among the oil and gas companies, and provide reliable economic information to all stakeholders. 2. ing Perspective SEM can be justified based on its adherence to matching and conservatism concepts hence, the debate seems to carry weight on its side compared to FCM which does not adhere to any of the two concepts. ing principles are not adhered to in the case of FCM. FC companies have flagrantly ignored the fundamental ing principles that ought to be observed by all and sundry by matching cost with an income that does not exist. More so, from the asset point of view, asset capitalization under the FC methods is flawed, because the so-called ‘asset’ capitalized does not possess the features of an asset i.e. there is no future benefit from it; because it (the so-called asset) does not even exist. Hence, the fundamental ing concepts have been, temporarily, discarded by companies in an attempts to gain investors confidence. Overall, since the controversy centres on either capitalizing or expensing cost and based on the fact that expenditure ought to be capitalized only if it meet the definition of an asset; then the FCM is fundamentally flawed. This is because companies reports should not purport to show the companies value, but rather provide stakeholders with all the necessary information for them to determine the company’s performance over a specific period of time and the value of the companies at a particular point in time. 3. Political Perspective In an attempt to ensure a decision-relevant financial reporting, FASB issued an exposure Draft (ED) in 1977, titled: Financial ing and Reporting by Oil and Gas Producing Companies: where indicated the need for all companies to use the SEM in their reports. However, the FASB’s effort was scuttled by US SEC and other government agencies. Politics and lobbying played a big role in this decision, as different stakeholders responded to the ED in the way it would serve their interest the most. Although, it is difficult to attribute the decision of SEC, for overriding the outcome of the ED, as a single factor, but it is aptly argued that the problem was a consequence of the political clout of oil and gas producers and dissention among ing standard setters. Indeed, oil and gas industry operations have been influenced by politicking for long and this has been one of the factors for failure to agree on a single acceptable method of ing in the industry. 4.3 Reserve Recognition ing (RRA) Some concerned ing practitioners were against the recommendation of FAS 19, which allow companies to use either FCM or SEM. This made SEC to propose the development of a new method of ing for oil and gas known as RRA, with a view to remedy, the inherent weakness of SEM and FCM. Under the RRA, companies would be allowed to recognize the value of proved oil and gas reserves as assets and changes in such reserve values as earnings in the financial statement. Just like FCM or SEM, RRA came under severe criticisms, because it ignore the fact that measurement of oil and gas reserves are imprecise and merely an estimate, and the projected revenue and cost may not materialize. Similarly, RRA is criticized for ignoring the realization concept, thereby recognizing revenue before receiving it. 4.5 Development of ing Standard in the Oil and Gas Industry An ing standard is a statement issued by the appropriate standard-setting body locally or internationally on a specific area or topic in financial ing, the acceptance/application of which is mandatory for preparers and s of financial statements. Criticisms of FCM and SEM and 41

RRA, triggered SEC to search for solution, thus culminating in FAS 69 by FASB in November, 1982. Similarly, the UK Oil industry ing Committee published four statements of recommended practice (SOR) to be used by oil and gas companies. These statements are: (1) Disclosures of oil and gas E & P activities; (2) ing for oil and gas E & D activities (3) ing for abandonment costs; and (4) ing for various financing revenue and other transactions of oil and gas E & P companies. The Nigeria ing Standard Board (NASB) followed suit by issuing SAS 14 (ing in the Petroleum Industry: Upstream Activities) through Chief R.U. Uche’s Committee. The standard came into effect from January 1, 1994. Similarly, through the effort of the same committee, NASB issue SAS 17 (ing in the Petroleum Industry: Downstream Activities) which came into effect on January 1, 1998. The standards which are applicable in Nigeria are Statement of ing Standards (SAS) issued by the Nigerian ing Standards Board (NASB), International ing Standards (IAS) issued by the International ing Standards Committee (IASC) and the International Financial Reporting Standards (IFRS) issued by the International ing Standards Board (IASB). All the standards, IAS, IFRS and SAS are applicable in Nigeria except that if an IAS/IFRS is inconsistent with an SAS, the IAS/IFRS would be inapplicable to the extent of the inconsistency. This implies that on any matter on which an IAS/IFRS and an SAS make conflicting pronouncements, the SAS shall supersede the IAS/IFRS in Nigeria. However, with effect from first January 2012, when Nigeria adopts IFRS in financial reporting, the reverse is the case. In other words, with effect from first January, 2012, IAS/IFRS will be adopted in Nigeria, and SAS will only be applicable where no IAS or IFRS is issued on the same item. Sequel to this, SAS 14 and 17 are still applicable in Nigeria. 4.5.1 Required Practice and Disclosure by SAS 14 1. Method of ing for cost incurred and the manner of disposing capitalized costs. 2. Policy on ing for restoration and total amount relating to each. 3. Method of ing use either FCM or SEM, which should be consistently applied and disclosed. 4. Cost should be classified by nature and function of cost element e.g. mineral interest in proved and unproved properties, wells and related equipment and facilities, wells and equipment in progress etc. 5. For FC companies: (i) initial costs incurred relating to mineral rights acquisition, exploration, appraisal and development activities should be capitalized; (ii) all capitalized costs (on country-wide basis) are to be depreciated on unit of production basis, using proved reserves; (iii) ceiling tests should be conducted (using discounted values for revenue, costs, taxes and future development costs) at least annually at balance sheet date, on a country-wide basis, using proved reserves and price ruling as at the date of the balance sheet; (iv) where s are prepared in US Dollars cash flows shall be discounted at 10%, otherwise if Naira is used, the CBN rediscount rate should be used; (v) if net discounted revenue is lower than the capitalized costs, the difference should be written off. 6. For SE companies: (i) initial costs incurred prior to acquisition of mineral rights not specifically directed to an identifiable structure should be expensed in the period they are incurred; (ii) all costs incurred relating to mineral rights acquisition, exploration, appraisal and development activities should be capitalized initially on the basis of wells, fields or exploration cost centres, pending determination and written off later if the well is dry; (iii) maximum of 3 years in offshore and 2 years in onshore are allowed as retention period for further appraisal cost pending determination; (iv) capitalized costs should be amortized over the remaining life of the licence and the balance should be reviewed annually for impairment 42

on wells basis, and any impairment should be written off; (v) drilling costs are to be amortized using unit-of-production basis using proved developed reserves. 7. Cost of providing amenities for communities in areas of operation should be written off as incurred. 8. Treatment of carrying interest and amount of carried expenditure to date. 9. Treatment of farmouts and similar arrangements. 10. Treatment of unitization and redetermination arrangements. 11. Treatment of t venture 12. ing for over-lifts and under-lifts 13. Provision for restoration and abandonment cost 14. Recognition of gains or losses under conveyances/surrender/sold of unproved property. 15. Information on proved oil and gas reserve quantity. 16. Disclosure of standardize measure of discounting future net cash flows relating to proved oil and gas reserves. 4.5.2 Required Practice and Disclosure by SAS17 The ing Standard comprises paragraph 44-59 of this statement covers the provisions as follows: ing policies 44. All companies engaged in downstream activities in the petroleum industries shall state in their financial statement all significant ing policies adopted in the preparation of those statements. 45. The ing policies should be prominently disclosed under one caption rather than as notes to individual items in the financial statements. Refining and petrochemicals operations Catalysts 46. Costs of short life catalyst should be expensed in the year in which they are incurred while costs of long life catalysts should be capitalised and written off over the life of the refinery. Where long life catalysts are generated, the costs of regeneration should be capitalised and amortised over the life of regeneration. Turn-Around Maintenance 47. Turn-around maintenance costs should be capitalised and amortised over the expected period before the next turn around maintenance will be due. Stand-by Equipment 48. Stand-by Equipments should be depreciated over the expected useful life of similar equipment in use. Depreciation of plants and Equipment 49. The costs of refining or petrochemicals plants and equipments should be depreciated on a straight line basis over the useful life of the assets or, if operating at normal levels of production, on the basis of expected throughput. The method used should be disclosed and consistently applied. Debottlenecking, Major Plant Rehabilitation and Replacement of Major Components 50. Where major plant rehabilitation, debottlenecking or replacement of major components result in a significant and identifiable increase in output or betterment of the plant, the cost should be capitalised and amortised over the period over which the benefits is expected to last. In any other case, it should be expensed as incurred. 43

Marketing and Distribution Operations Bridging Costs Claims 51. Bridging costs which are recoverable from government through NNPC should be set up as claims receivable. Where they remain outstanding for an unreasonable length of time, adequate provision should be made for them. Claims not recovered within two years should be fully provided for. ATK Overbilling Claims 52. ATK overbilling claims should be set up as a receivable. Where they remain unpaid for an unreasonable length of time, they should be provided for claims not recovered within two years should be fully provided for. Liquefied Natural Gas Operation Take or Pay Contracts 53. Where a purchaser is unable to take his entitlement under a take or pay contract, with a right of make-up, the purchaser should treat the amount paid as receivable. Conversely, the supplier should treat the advance received as deferred revenue. The deferred revenue should be recognized when the makeup right is exercised by the purchaser. 54. Where a supplier is unable to deliver the quantity contracted, the amount received from the purchaser should be treated as a liability by the supplier while the purchaser should treat the amount paid as prepayment. Disclosures 55. In addition to the disclosures requirements of SAS 2 Information to be Disclosed in Financial Statements, companies operating in the downstream sector of the petroleum industry should disclose the following the following as they relate to their activities; (a) Refining and Petrochemical Companies (i) Processing fees from third parties (ii) Any amount of turn-around maintenance capitalized and or expensed split into material costs and lab our costs and where capitalized the rate of amortization (iii) Debottlenecking, major plants rehabilitation and replacement of major components costs incurred, capitalized or expensed and, where capitalized, the rate of amortization (iv) The cost of research and developments (v) Basis of valuation of products and intermediates (vi) For an integrated plant, revenue earned for each class of activities (b) Marketing and Distribution Companies (i) Bridging claims and related provision made (ii) ATK overbilling claims and related provision made. (c) Liquefied Natural Gas Companies Details of Take or Pay contracts not yet fulfilled and the related deferred revenue or

prepayment.

Packaging and Non-core Businesses 56. The operating results of packaging and other non-core businesses owned by companies operating in the downstream sector of the petroleum industry should be separately disclosed. Transfer Pricing 57. The transfer pricing methods adopted should be disclosed.

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58. The requirements of this standard are complementary to any ing and disclosure requirements of the companies and Allied Matters Decree, 1990 and relevant laws and regulations 5.0 Procedures in Oil and Gas ing 5.1 Impact of Order of Drilling on Petroleum ing Methods There are two methods of ing used in the oil and gas industry. These are SEM and FCM. The SEM and FCM of ing give significantly different results based on purely chance factors like the order or chronology of successful and unsuccessful wells. Assuming that, a company in an attempt to develop an oil reservoir, drills a total of four wells. The first two wells (A and B) are successful while the last two wells (C and D) are unsuccessful. Under the SEM, the four wells will be capitalized as wells C and D are now development wells. The income statement will show a buoyant picture. However, if the first two wells drilled are unsuccessful and the last two wells are successful, the cost of wells A & B will be charged to expense while the cost of wells C & D will be capitalized. Thus, merely changing the order in which wells are drilled will result in a vast difference in the financial statements. With increased exploration drilling, net income drops under the SEM when compared to the full cost ing method. When there is an increased rate of’ discovery, that is, a greater percentage of successful wells rather than dry holes, this result in increasing net income under the SEM as fewer dry holes are written off. However, all these have no effect on FCM companies. 5.2 Similarities and Differences between SEM and FCM Two of the very few similarities between the two methods are in the treatment of development costs and production costs. Development costs in both cases are capitalized whether successful or not while production costs are expensed. Table 5: Comparison between SEM and FCM and Compliance with GAAPs Basis of S/No. Comparison 1 Presenting a true and fair view of the result of the operations of the business. 2 Return on assets

3

Share values

4

Investment Lenders.

Successful Efforts Method As all exploratory costs that are Successful are charged to expense, financial statements present a true and fair view of the result of operations. The ing rate of return of the business is higher as only productive assets are capitalized.

Full Cost Method Capitalizing the monetary values of unsuccessful exploration costs impair the true and fair view of the financial statements of the company.

The ing rate of return of the business is lower because both productive and non-productive assets are capitalized. This may result in takeover bids. The share value may be higher The low rate of return may adversely because the ing rate of affect the share value. return is higher. and Net profit figures are generally Financial statements are more stable lower and fluctuate drastically thereby attracting investors and especially in years where huge write lenders into the business. offs are made, This discourages investors and lenders from providing funds for the business.

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Basis of S/No. Comparison Successful Efforts Method 5 Survival of the new New entrants and growing entrants and growing companies cannot afford the huge companies. write offs of the exploration losses of initial years and their corporate survival is threatened. 6 Production of Information on the performance of information for individual wells is more readily managerial decision available to managerial making. decision making. 7 Performance Enables the performance of evaluation of managers to be evaluated. managers 8 Comparison of Because of the erratic movement of financial statements. the net profit results, meaningful comparison of the financial performance over years is impaired. 9 Dividend decisions Since all losses are recognized before the net profit results are arrived at, dividend decisions are more prudent. 10

Compliance GAAPs

with

This method is more in accord With the prudence and matching concepts of ing. 11 Record keeping and Relatively simple to operate and associated costs. record keeping is less expensive as only one set of records are kept.

12 13

Ceiling Test Ceiling test is not mandatory. Exploration and Potential effect-of writing off dry drilling activities hole expenses may affect exploration and drilling activities.

Full Cost Method New and growing companies can thrive better under this method because most of costs incurred are capitalized. Information on individual wells is concealed in a country pool. Costs of inefficiencies are therefore not easily identified for managerial action. Managerial performances cannot be accurately determined as the costs of inefficiencies are capitalized. Because results are more stable, performance comparisons are enhanced. Exploration losses not written off may cause published profits to be overstated, which, may lead to dividends being declared on them. The enterprise may be de-capitalized. Full cost method does not strictly accord with the ing concepts of prudence and matching. Method is complicated, especially the calculation of ceiling tests. Record keeping is more expensive as memorandum records have to be maintained in order to provide information for each well. Ceiling test is mandatory. Potential effect on exploration and drilling activities is minimal as dry holes are not charged to expenses in the income statement.

Figure VI and VII give the ing procedure of FCM and SEM.

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Figure VII: Full Cost ing for Costs

47

Figure VIII: Successful Efforts ing for Costs

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5.3 Differences in Balance Sheet and Profit & Loss of FCM and SEM FCM SEM Balance Sheet (Capitalized amounts) Geological and geophysical costs xx --Carrying costs and overhead xx --Surrendered and impaired leases xx --Unimpaired leases xx xx Exploratory wells Successful xx xx Unsuccessful xx -Development wells xx xx DD& A xxH xxL FCM SEM Profit And Loss (Expensed amounts) Geological and geophysical costs -xx Carrying costs and overhead -xx Surrendered and impaired leases -xx Unimpaired leases --Exploratory wells Successful --Unsuccessful -xx Development wells --xxL DD & A xxH xxH Comparably higher xxL Comparably lower 5.4 Differences between Tangible Costs and Intangible Costs Tangible costs relate to costs of assets that have physical properties. Tangible is said to have been derived from the Latin word “tangere” meaning to touch, impling that such assets can be touched or felt. They include machinery, equipment vehicles etc. Tangible costs also include labour to install equipment etc. even though such costs do not result in a physical asset. Intangible costs relate to costs that result in an asset that has no physical properties. Examples are contract costs paid to a contract driller for drilling a well, mud pits etc. In oil and gas operations and ing, a distinguishing feature between classification as tangible and intangible is salvageability. If the property can be salvaged at the end of operations, such properties are usually classified as tangible whereas those properties (the underlying costs) that cannot be salvaged at the end of an operation are classified as intangible. The distinction between both types of costs is usually important for tax purposes. Examples of Intangible Drilling Costs Drilling contractors’ charges Site preparation, roads, pits Bits, reamers, tools Labour Fuel, power and water Drill stem tests 49

Coring analysis Electric surveys and logs Geological and engineering Cementation Completion, fracturing, acidizing, perforating Rig transportation, erection and removal Overhead Other services Examples of Tangible Drilling Costs Casing (production and surface) Tubing Well head and subsurface Pumping units Tanks Separators Heater-treaters Engines and automotives Flow line Installation costs of equipment Sundry equipment Question One Janguza Oil Company, a t venture operator, incurred the following costs in drilling an oil well: N i. Drilling (on footage basis) 675,256 ii. Cost of clearing and grading unpaved roadways to the drill site 23,560 iii. Construction of overflow mud pits 56,700 iv. Surface casing used in the well 675,908 v. Services such as acidizing and testing 246,200 vi. Cementing services for casing 17, 890 vii. Tubing and control valves 57, 500 viii. Flow lines, tanks and treaters 116, 700 ix. Labour to install lines and tanks 26, 500 Solution to Question One

I Ii Iii Iv V Vi Vii

Drilling (on footage basis) Cost of clearing and grading unpaved roadways to the drill site

Intangible Drilling Costs (IDC) 675,256

Tangible Drilling Costs (TDC)

23,560

Construction of overflow mud pits Surface casing used in the well Services such as acidizing and testing Cementing services for casing Tubing and control valves

56,700 675,908 246200 17, 890 57, 500

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viii Flow lines, tanks and treaters Ix Labour to install lines and tanks 1,001,716

116, 700 26, 500 675,908

5.5 ing for Depreciation, Depletion and Amortization Oil and gas companies classify costs incurred on oil and gas properties into two broad categories, namely mineral acquisition costs and wells and related equipment and facilities costs. These capitalized costs are written off to the profit and loss through depreciation, depletion and amortization (usually abbreviated as DD&A). Depreciation is associated to the decrease in the values of physical or tangible assets, amortization is associated with the expiration of the cost of intangible assets, while depletion refers to the reduction in the costs of natural resources of wasting nature resulting from the diminution in the value of the resources. However, emphases here would be on amortization and depletion, as depreciation is perhaps well known in other aspects of financial ing. 5.5.1 Basis for Amortization The most commonly used method of computing amortization of oil and gas properties is the “unit of production” method. This is in line with the provision of SAS 14 and 17. The unit of production method assigns a pro-rata portion of capitalized costs of oil and gas properties to each unit of reserves. The oil company then expenses the pro-rata assigned amount as it produces each unit of reserves. These are explained below: 1. Unit of Production (UOP) Method The formula for the unit of amortization method is: (C - AD – S) P R Where: C= Capital cost of equipment AD= Accumulated DD&A S= Salvage Value P= Production during the year (in barrels) R= Reserves remaining at the beginning of the year This concept may be expressed as follows: Unamortized cost at end of the period X Production for the period Reserve at beginning of period An alternative form of the above formula is: Production for the period X Unamortized cost at the end of period Reserves at beginning of period Question Two Kabuga Petroleum Company PLC had the following data at end of its financial year ended 31st December, 2011. You are required to calculate the DD&A for that year. Capitalized cost at the end of year N 1,700,000 Accumulated amortization N 100,000 Reserves estimate at beginning of the year 5,000,000 bbls Production during the year 250,000 bbls

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Solution to Question Two Amortization would be calculated as follows: 250,000 bbls X (1,700,000- 100,000)= N 80,000 5,000,000 bbls 5.5.2 Revision of Reserve Estimates Reserves of oil and gas companies are frequently revised and, in any event, should be reviewed at least annually. This is in line with SAS 14. When the estimate of reserves is reviewed and a revision becomes necessary at the end of a period, the estimate of reserves originally made at the beginning of the period is ignored. In other words, the amortization rate per barrel may change due to revision of valuation of oil reserves. Such changes in rates are made prospectively, affecting current and future periods, but necessitating no adjustment in the accumulated amortization of prior periods. Question Three Kabuga Petroleum Company PLC had the following data at end of its financial year ended 31st December, 2011. You are required to calculate the DD&A for that year. Capitalized cost at end of the year N 1,700,000 Accumulated amortization in prior years N 100,000 Reserves estimate at the beginning of the year 5,000,000 bbls Production during the year 250,000 bbls Reserves estimate at the end of the year 4,000,000 bbls Solution to Example Three DD&A =

DD&A =

=

Production during the year X Unamortized cost (year end) [Reserves estimate (year end) + Production during the year] 250,000 (1,700,000 – 100,000) 4,000,000 + 250,000

250,000 X 1,600,000 N 94,118 4,250,000

It should be noted that this question uses identical figures as the preceding illustration except for the revision of the estimate of reserves carried out at the end of the year. This additional information changes the reserves at the beginning of the year, the amortization rate, and consequently, the DD&A for the year from N 80,000 to N 94,118. 5.5.3 Nature of Cost Centre Amortization amount is also affected by the nature of the cost centre i.e. whether it is carried out on a well-by-well, field-by-field, or countrywide basis. This is clearly illustrated in Question four below. Example Four Assume the following data are in respect of the entire leases owned by BUK Oil Company in Nigeria. You are required to calculate the DD&A for the year Ended 31st December, 2011 on (i)property-by-property basis and (ii) countrywide basis. Concessions Lease 1 Lease 2 Lease 3 Total

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N

N

N

N

Capitalized cost - end of the period (Net)

600,000

1,000,000

2,000,000

3,600,000

Estimated reserves - end of the period (bbls)

4,000,000

3,000,000

6,000,000

13,000,000

Production during the period (bbls)

1,000,000

500,000

1,200,000

2,700,000

Solution to Question Four Computation of DD&A for BUK Oil Company For the Year Ended 31st December, 2011 (i) Property-by-property Basis Lease 1:

1, 000, 000 bbls X 600,000 = N120, 000 4,000,000 + 1,000,000 bbls

Lease 2:

X 1,000,000 = N 142, 857 500,000 bbls 3,000,000 + 500,000 bbls

Lease 3:

1, 200, 000 bbls X 2,000,000 = N 333, 333 6,000,000 + 1,200,000 bbls . N 596, 190

Total Amortization

(ii) Country-wide Basis 2, 700, 000 bbls X N 3, 600,000 13,000,000 + 2,700,000 bbls

2, 700, 000 bbls X N 3, 600,000 = N 619, 108 15,700,000 bbls 5.5.4 Amortization under SEM and FCM of ing Amortization of capitalized costs under SEM of ing is broadly similar to the FCM. Under both methods, DD&A is usually based on the unit of production method. Acquisition costs of proved properties are amortized on the basis of total estimated units of proved (both developed and undeveloped) reserves. If significant development costs (such as offshore production platforms) are incurred in connection with a planned group of development wells before all of the wells have been drilled, a portion of such development cost is excluded until the additional development wells have been drilled. Similarly, the proved developed reserves that will be produced only after significant

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additional developed costs are incurred, such as enhanced recovery systems, are excluded in computing the DD&A rate. When a property contains both oil and gas reserves, the units of oil and gas used to compute amortization are converted to a common unit of measure on the basis of their relative energy content, known as the BTU (British Thermal Units). Despite the broad similarities mentioned above, DD&A under the full cost and successful efforts method of ing differs fundamentally. The differences may be summarized as follows: Successful Efforts Method (SEM) 1. Wells and related facilities costs are amortized using proved developed reserves. 2. The amortization must be on the basis of unit of production. Unit of revenue method is not permitted. 3. Future development costs are considered in the amortization computation. 4. Costs are accumulated for each cost centre. For the purpose of capitalizing costs and amortization, the “centre” is essentially the individual lease, block, licence area, concession or field. Full Cost Method (FCM) 1. Costs are accumulated separately for each cost centre. For this purpose, each country or continent is considered a separate cost centre. 2. Costs are amortized using proved reserves (i.e. both developed and undeveloped). 3. Costs to be amortized include: (a) Capitalized costs (net of previous depreciation, depletion and amortization); (b) Future development costs to develop proved reserves are included in amortization base; (c) Future dismantlement and restoration cost. 4. Unit of revenue method may be used. 5. A “cost ceiling” based on a standardized measure of underlying value of assets is mandatory. 5.5.5 Computation of Depletion As earlier stated, both full cost and successful efforts companies deplete mineral acquisition costs using proved reserves. However, a successful efforts company amortizes capitalized costs, other than acquisition costs, using proved developed reserves, whereas a full cost company amortizes such costs using proved reserves. This is because the mineral acquisition costs apply to all recoverable reserves in the field or property whereas wells and related equipment relate only to the portion of reserves recoverable from the wells already drilled-proved developed reserves. Question Five (i) Calculate DD&A for New-Site Oil and Gas Nigeria Limited, a “full cost” company, assuming the following: Abandonment costs N 15,000,000 Development costs N 5,000,000 Capitalized costs N 30,000,000 Proved reserves 5,000,000 bbls First year production 500,000 bbls (ii) Calculate DD&A for above company for the second year, assuming that production is 300,000 bbls. (iii) Calculate DD&A for New-Site Oil and Gas Nigeria Limited, a “succesful cost” company, assuming the following: Abandonment costs N 15,000,000 Development costs N 5,000,000 54

Capitalized costs: Wells and equipments N 20,000,000 Acquisition costs N 10,000,000 Proved reserves 5,000,000 bbls Proved developed reserves 3,00,000 bbls Production 500,000 bbls Solution to Question Five (i) Abandonment costs Development costs Capitalized costs

N 15,000,000 N 5,000,000 N 30,000,000 N 50,000,000

DD&A 500,000 X N50,000,000 = N 5,000,000 5,000,000 (ii) Second year DD&A 300,000 X [50,000,000-5,000,000] [5,000,000 - 500,000] 300,000 X 45,000,000 = N 3,000,000 4,500,000 (iii) DD&A on Acquisition costs = 500,000 X 10,000,000 5,000,000 DD & A on wells & equipt. 500,000 X N20,000,000 3,000,000 Total DD&A (1,000,000 + 3,333,333)

= N l,000,000 = N 3,333,333 = N4,333,333

5.5.6 t Production of Oil and Gas For properties that produce both oil and gas, the units of oil and gas used to compute amortization are converted to a common unit of measure on the basis of their relative energy content known as the BTU, except: (a) the relative proportion of oil and gas are expected to continue throughout the life of the property, in which case, the DD&A should be based on any one of the two minerals; or (b) oil or gas is clearly dominant in both reserves and production, in which case, the unit of production may be based on the dominant mineral. Usually, one barrel of oil contains six million BTUs and one mcf of gas contains about one million BTUs. Accordingly, it is generally accepted that six mcf of gas is equal to one barrel of oil in determining the relative energy content for conversion. This ratio continues to be used despite the fact that the market no longer reflects the relative energy contents in prices of oil or gas. For instance, based on this ratio, a barrel of crude oil should sell for six times the price of one mcf of gas but in most cases, this is not the case. The ratio may be as much as almost 20 times. Furthermore, because oil and gas are differentiated products, their energy contents vary from reservoir to reservoir or even within different strata of the same reservoir. An oil company may therefore have reasonable justification for using a conversion factor that more precisely reflects the energy equivalencies of both minerals.

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5.5.7 Exclusion of Significant Development Costs When significant development costs are incurred in connection with a planned development plan, a portion of such costs should be excluded in computing amortization until such additional development wells have been drilled. This is in order to avert distortions that may occur where large development costs are incurred on assets that will be used to produce both proved developed and proved undeveloped reserves. If a compensating adjustment is not made, the matching of costs with related reserves will not be achieved. Portion of development costs to be excluded is usually based on the ratio of proved developed reserves to total proved reserves or number of wells not yet drilled compared with total of all wells (drilled and to be drilled). . 5.5.8 Revision of Reserve Estimates and Interim Financial Statements It is sometimes necessary to revise the estimate of reserves because of new information, changes in technology etc. The effects on amortization rates of such reserve revisions are usually adjusted prospectively. Changes in reserve estimates impact significantly on companies that prepare interim financial statements say on a quarterly or semi-annual basis. 5.5.9 DD&A through Addition and Disposal on Production Equipment Changes often occur in the capitalized cost of production equipment after the initial investment. Addition may be made through new purchases and transfers, while disposal may be made through sales, retirements, catastrophic loss or transfer to another property. Additions to production equipment are treated for ing purposes the same way as the initial investment. When production equipment is disposed, the difference between the book value of the equipment and disposal value i.e. fair market value or sale price is adjusted through the accumulated amortization. No gain is to be recognized in this transaction but a loss may be recognized, in compliance with the concept of conservatism.

5.5.10 Dismantlement, Restoration and Abandonment Costs When oil and gas reserves are fully depleted or production falls to an uneconomically low level and it is no longer feasible to produce minerals even under enhanced recovery techniques, equipments are salvaged and operations are abandoned. Oil and gas operations regulations require that wells be plugged, all facilities and equipment removed and the terrain restored, as much as possible, to its natural state. Dismantlement and restoration costs can be quite enormous and sometimes may even exceed the cost of the original installations, especially when is taken of inflation and the time interval between the commencement of production and abandonment of property. Some companies assume that the amount realized from dismantled facilities less salvage costs, will offset dismantlement and restoration costs. Accordingly, such companies either ignore making any provisions for such terminal costs or make the provision in the year in which abandonment occurs. Clearly, by not making accruals, such companies would not be achieving the matching of revenues with related costs. Sound ing principles require that estimated dismantlement, restoration and abandonment costs, if material, be included in the cost pool in determining amortization rates. The amortization relating to dismantlement, salvage and reclamation is usually charged to DD&A (or a profit and loss titled dismantlement, salvage and reclamation costs) and credited to a contingent liability . When the company abandons the property and incurs the dismantlement and restoration costs, the costs incurred are charged to the liability . Any difference between actual dismantlement and restoration costs and the liability is charged or credited to income. 56

5.6 Ceiling on Capitalized Costs In addition to capitalizing all acquisition costs, exploration costs (including G,G& costs) a full cost company carries development dry holes as an asset. There is therefore a distinct danger that the value of proved reserves and other mineral assets in the cost centre may not be adequate to recover the unamortized costs in the full cost pool. Consequently, a full cost company is required to perform a ceiling test annually. A ceiling test is a determination of the upper limit of the total amount of costs that can be capitalized in the books by taking into consideration an estimation of the value of underlying reserves. For each cost centre, capitalized costs less accumulated amortization and related deferred income taxes should not exceed the estimated fair market value of the reserves. Where the capitalized costs exceed the ceiling, any excess over the ceiling is charged to expense and disclosed separately in the financial statements. In accordance with the prudence concept, if in a subsequent year, the capitalized cost is higher than the estimated value of reserves (ceiling), no write back is permitted. 5.7 ing for Unproved Properties 5.7.1 Mineral Properties In Nigeria, the right over surface area of land and its subsurface locations are separated. In other words, even if a famer owns the land, he does not own the minerals that lie underneath it. Section 1 of the Petroleum Act, 1969 vests the entire ownership and control of petroleum resources in all land within Nigeria and its territorial waters and continental shelf in the Government. The Minister for Petroleum Resources may, on behalf of the Government, grant any of the following: a) Oil Exploration Licence (usually covers a period of 1 year) - to explore (discover) for petroleum. b) Oil Prospecting Licence, which usually covers a period of 3 to 5 years (to prospect/search for petroleum); and c) Oil Mining Lease, which usually covers a period of 20 to 30 years (to win, work, carry away and dispose of petroleum) to a licensee or lessee. The grant of a licence or lease notwithstanding, the licensee or lessee is obliged to pay fair and adequate compensation to the lawful owners and occupants of the land. Reasonable compensation must also be paid to land owners for specific damages done by felling of economic trees and interference with fishing rights. Typically, an oil and gas company acquires mineral properties in one of the following ways: (a) After a company determines the lessor of the property on which it desires to drill, the company evaluates any seismic data available on the area. If an individual or oil company owns the property, such may be approached for a negotiation that may either take the form of an assignment, outright purchase or t venture agreement provided the required legal provisions are met and the consent of the Minister is obtained. (b) Periodically, Government offers some blocks to the public for bidding. Each interested oil company submits a sealed bid to the Government together with the stipulated bidding fee for each block to be leased. Although the blocks are usually awarded to the highest bidder, other factors such as minimum work programme, financial resources, experience in exploration and production, track

57

record in international operations, payable, signature bonus payable and political factors are also taken into . Acquisition costs for licences, concession or leases, yet to have proved reserves discovered in them, are classified and referred to as Unproved Properties. Although the basic provisions in leases and licences are similar, each lease and/ or licence may contain unique provisions. Basic provisions for Oil Prospecting Licence (OPL) and Oil Mining Lease (OML) are as follows:

Signature Bonus The signature bonus is the cash or other consideration paid to the lessor (property-owner) by the lessee (leaseholder) in return for the lessor granting the 1essee the rights to explore for minerals, drill wells, and produce oil. The bonus is computed at per-acre basis. Duration The Minister for Petroleum Resources determines the duration of an Oil Prospecting Licence (OPL) or Oil Mining Lease (OML). In the case of an OPL the duration may not be more than 5 years including any renewals, whereas an OML may not have a term of more than 20 years but may be renewable. Rent The agreements typically provide for rentals to be paid on concessions. Such rentals are based on acreage or hectare granted by the lease. Royalty Provisions Lease contracts provide for royalty to be paid to the lessor of a mineral concession. Royalties are based on the quantity of oil and gas produced. The Federal Government of Nigeria fixes royalty rates, which may vary from time to time. Right to Assign Interest The lease contract grants the lessee the right to assign, subject to approval by the Minister for Petroleum Resources, any part or all of its rights and obligations. Drilling The lessee or licensee is required to commenced exploration using accepted geological and geophysical techniques within six months and to commence drilling operations in eighteen months of the grant of the relevant concession. 5.7.2 General Principles of ing for Acquisition Cost of Unproved Properties Successful Efforts Method In successful efforts ing, costs associated with the acquisition of unproved properties are initially capitalized when incurred. These consist of costs incurred in obtaining a mineral interest in a property such as signature bonuses, options to lease, brokers’ fees, legal costs, stamp duties and other similar costs in acquiring property interest. Unproved .properties should be assessed at least once a year to determine if there is any loss in value (impairment). If there is any impairment, it must be recorded as a loss.

58

Full Cost Method Under the FCM, all costs associated with the acquisition of unproved properties are capitalized within the appropriate cost centre. Unproved properties that are excluded from the amortization base should be periodically assessed for impairment until it can be determined if proved reserves are attributable to them. If impairment is indicated, the amount of impairment should be included in the amortization base and not charged to profit and loss. 5.7.3 Impairment of Unproved Properties At the time an oil company acquires an interest in an unproved property, the value of the property is assumed to be equal to the cost. With the effluxion of time, certain events occur which may give rise to reassessment of the “value” of the unproved property vis-a-vis the recorded costs. Unproved properties are assessed periodically in order to determine whether they have been impaired under successful efforts ing. A property may be considered impaired if a dry hole has been drilled in a part of it or nearby property and the company has no intention of further drilling on the property. Also, as the expiration of the lease term approaches and the company has not commenced drilling on the property or ading properties, the possibility of partial or total impairment of the unproved property may increase. Basis of Impairment Impairment may be assessed either on individually significant properties or on group of properties. Impairment on individually significant unproved properties is assessed on a property-by property basis. If a property is found to be impaired, an impairment provision is made and a loss is recognized. Unproved properties whose costs are not individually significant may be aggregated and assessed in groups. This is done on the basis of the experience of the company in similar situations and considering such factors as the duration of the lease, the average holding period of unproved properties, and the relative proportion of such properties that has become proved in the past. Factors such as acreage and estimated future expenditures may also be considered. Determination of what is individually significant can be a matter of individual judgement since it may not depend on relative costs or percentage of portfolios alone. A basic rule of thumb for significance is 10 percent of the net capitalized cost of the cost centre. Recovery in Value of impaired Property Occasionally, the value of a property on which impairment provision had earlier been made may exceed the original cost of such property. ing prudence dictates that, in such situations, the impairment provision previously made should not be reversed. No profit should be recorded for appreciation in value of such properties. Impairment and t Working Interests The objective of assessing a property for impairment is to ensure that assets that have no service potential are not carried in the balance sheet. Assessment of impairment is faced with subjectivity especially with t working interest property where each working interest owner can make a decision as to whether the property is significant and the amount of impairment that may be allowed. Impairment and Post Balance Sheet Events It is also to be noted that impairment events occurring after the balance sheet date but before the issuance of audit report should be taken into in evaluating conditions that existed at the balance sheet date. 59

Transfer to Proved Properties If a successful well is drilled on an unproved property on which individual impairment has been previously recorded, the net book value of the property is transferred to Proved Properties , and subjected to amortization. It should be noted that unproved property cost remains in the at net carrying value until the result of the first successful well has been determined. Surrender and Abandonment of Unproved Properties The licensee or lessee of a concession (OML/OPL) may terminate or effect a partial surrender of the concession by giving the Minister of Petroleum Resources three months notice to that effect. Furthermore, the Minister may revoke the lease or licence under certain conditions, which are stated in paragraphs 23 and 24 of Schedule 1 to the Petroleum Act, 1969. When an unproved property on which individual impairment has been recorded is surrendered or terminated, a successful efforts company should write-off the net carrying value of the property to profit and loss , while full cost company should not write off the book value to expense as above; it should merely increase the costs subject to amortization. 5.8 ing for Drilling and Development Costs ing for exploration, drilling and development costs can be quite complex especially where the lessee or the original working interest owner has assigned fractional interests to other oil companies. The practice in most oil companies today is to contract drilling to independent contractors. Even where the oil company decides to perform the drilling and equipping of a well by itself, it is still customary to engage the services of outside specialists for such services as electric logging, cementation, perforating, acidizing and fracturing. Preparation for Development and Drilling As earlier stated, investments in oil and gas assets can be quite enormous, requiring various levels of approvals. Typically, an oil company plans and controls investment in oil and gas assets by requiring that request for authorization to drill and equip oil wells be prepared and approved for each new well. Such authorization is referred to as an “authorization for expenditure” (AFE). AFE includes an estimate of costs to be incurred, by service or asset category and in total, whether the company itself or an outside contractor is to conduct the drilling and development operations. An AFE procedure assists in rational allotment of funds available for capital expenditure and provides an effective cost control mechanism, through the comparison of budgets with actual costs and investigation of variances. Where it becomes apparent that actual costs will exceed budgeted amounts, it may be necessary to prepare a supplementary AFE. Most oil companies will require preparation of a supplementary AFE when budget will be overrun by a specified percentage e.g. 10 percent. For drilling and development AFE’s, expenditure subheads may include: Intangible Expenditure Drilling contractors’ charges Site preparation, roads, pits Bits, reamers, tools Labour Fuel, power and water Drill stem tests Coring analysis Electric surveys and logs Geological and engineering 60

Cementation Completion, fracturing, acidizing, perforating Rig transportation, erection and removal Overhead Other services Tangible Expenditure Casing (production and surface) Tubing Well head and subsurface Pumping units Tanks Separators Heater-treaters Engines and automotives Flow line Installation costs of equipment Sundry equipment Additional Information Apart from details of estimates and actual costs under the above subheads, AFE’s contain the following additional information: (i) AFE number and date; (ii) approvals required both from company and t venture parties; (iii) purpose of expenditure i.e. whether exploratory drilling or development drilling; (iv) location of project or well; (v) well number; projected total depth; and (vii) type of well i.e. whether oil, gas, or condensate. 5.8 ing for Exploration and Drilling Costs Examples of exploration and drilling costs are: a) Costs of topographical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, those are sometimes referred to as or “G&G” (geological and geophysical) costs. b) Costs of carrying and retaining undeveloped properties, such as delay rentals, tax on the properties, legal costs for title defence and the maintenance of land and lease records. c) Dry hole contributions and bottom hole contributions. d) Costs of drilling and equipping exploratory wells e) Costs of drilling exploratory-type stratigraphic tests wells. ing treatment of exploration and drilling costs depends on whether the enterprise uses the successful efforts method or full cost method of ing. 5.8.1 Successful Efforts An oil company which adopts the SEM of ing will expense all G&G costs and carrying costs of undeveloped properties, regardless of whether exploration activities led to discovery of reserves or not. All other exploration and drilling costs such as costs of drilling wells and exploratory- type stratigraphic test wells are charged to expense if they result in dry holes and capitalized if reserves are discovered in them. The reason for the divergent treatment of G&G costs and other exploration and drilling costs is 61

because a successful efforts company treats G & G costs as cost of obtaining information, similar to research and development costs (R & D) which generally must be charged to expense as incurred. The costs that may be capitalized are held temporarily in a well in progress until a determination is made as to whether the wells are productive or not. If an exploratory well is determined to be dry, the costs accumulated in work in progress, less salvage value, are written off as expense. 5.8.2 Full Cost Under the FCM, all exploratory and drilling costs are capitalized. The work in progress is used temporarily to accumulate costs of wells being drilled in the same manner as a successful effort company, until the outcome of the well is known. If the well proves successful, the accumulated cost in the wells in progress is transferred to Wells and Related Facilities and amortized. The work in progress can either be included or excluded from the amortization base. However, as soon as the outcome of the well is known, it must be reclassified to wells and related facilities and included in the amortization computation. 5.9 ing for Development Costs Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of equipment and facilities and other costs of development activities are costs incurred to: a) Gain access to and prepare well locations for drilling, including the survey of well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. b) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. c) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and utility and waste disposal systems. d) Provide improved recovery systems. Development costs are basically classified into two i.e. IDC (intangible drilling and development cost) and LWE (Lease and well equipment cost). Generally intangible drilling cost are down hole costs up to and including the wellhead. They include cost of preparation for drilling, drilling cost, well servicing (fracturing, acidizing) and the cost of subsurface well equipment. Equipment includes cost of well equipment and other lease equipment. An oil company capitalizes all development costs. The costs of drilling development wells are temporarily included in Wells in Progress - Development Wells until drilling is complete. Upon completion, the costs are re-classified to wells and related equipment and amortized. In effect, development well costs are capitalized whether or not they result in discovery of hydrocarbons. This is because development wells are regarded as costs incurred to produce reserves already located by an exploratory or discovery well. ing for development costs is the same under both full cost and successful efforts method. It is clear from the foregoing that a proper distinction must be made between exploratory wells and development wells since the ing treatments are not the same. An exploratory well is a well

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drilled to find and produce oil in an unproved area, to find a new reservoir in a field previously found to be productive. Question Six First Hydrocarbon Company Limited incurred the following costs for a development well drilled during 2011 in a recently acquired concession. N Site survey 150,000 Bush clearing 500,000 Road building and bridges 2,500,000 Tubing and casing pipes 1,400,000 Well head assembly and valves 2,100,000 Flow lines 4,000,000 Separators 10,000,000 Treaters and heaters 2,000,000 Desander 1,500,000 Required: a) Prepare journal entries to record the cost of the development well, assuming BUK Hydrocarbon Company uses successful efforts method of ing. b) Prepare journal entries to record the development well assuming that the full cost method of ing is used. c) Would it make any difference if the development well were dry or productive? Comment. Solution to Question Six (a) Successful Efforts Company General Journal Particulars Wells and related facilities (Intangible) Wells and related facilities (equipment) Bank Being cost of development wells incurred. (b) (c)

Dr 3,150,000 21,000,000

Cr

24,150,000

Entry for full cost company is the same as for successful efforts company above. It would not make any difference. Both full cost and successful efforts companies are required to capitalize costs of development dry holes and producing development wells.

5.10 Production ing Production ing is the process of identifying and measuring the revenues, expenses and net income or loss attributable to the operation of petroleum producing properties. Production ing provides a basis for sound property management and evaluation of profitability. A typical oil company may have several producing properties with varying acreages, working and nonworking interests. It is essential that revenues and expenses (production or lifting costs) of individual properties be determined in order to provide an effective measure of the profit margin on all wells. 5.10.1 Types of Economic Interests in Oil and Gas Properties

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For a proper understanding of revenue ing it is necessary to explain the various types of economic interest in oil and gas property. The particular types of economic interest owned by the parties involved in a property determine how the benefits and obligation of the property i.e. costs and revenue is shared. Economic interest consists of ownership of minerals in place that gives the owner the right to share in the mineral produced or in the proceeds from the sale of minerals produced. Basic types of ownership interests are as follows: Royalty Interest (RI) This is basic type of interest in production that is retained by the mineral interest owner when he leases the property to another party. It is a non-working interest and the owner is entitled to receive a fraction of the oil produced in form of royalty.

Working Interest (WI) This is the interest remaining after deduction of all non-working interest. t Working Interest (JWI) This is a situation in which two or more parties own undivided fractions or percentage of the working interest. Pooled Working Interest (PWI) This situation is the result of combining two or more working interest with or without the same ownership interest. It may be mandatory by State regulation or as the option of the lessees. Unitized Working Interest Unitization is similar to pooling except that it is on a large scale and always involves the combination of working interest owned by two or more parties. 5.10.2 Revenue from Oil Broadly, revenue from oil and gas operating interest may be revenues from oil, revenues from gas and miscellaneous revenue. Revenue from oil may or may not include inventory in tank batteries. Revenue from gas is usually limited to revenue from gas sold. Miscellaneous revenue consists of such incidental income as ullage fees, rentals, power sales, management fees etc. An important step in ing for revenue from oil is the determination of the volume lifted. Although field personnel such as gaugers, perform the actual measurement of volume, the ant must be familiar with measurement procedures in order to meaningfully record revenues in the books of s. Oil is usually produced in association with gas as only few reservoirs produce gas or crude oil only. Therefore, after oil is produced from an oil well, it is ed through a separator to remove gas from liquids (crude oil) or remove liquids (condensate) from gas. The oil is also ed through a heatertreater to remove water and other impurities from the oil. The gas removed from the oil is referred to as casinghead gas. The treated oil is then usually stored in large stock tanks, collectively referred to as tank farms or tank batteries. At the time a tank battery is put into operation each stock tank is strapped or measured. This measurement or strapping determines exactly how many barrels of oil can be held in the tank for each fraction of an inch of oil contained in the tank. Because the tanks have been strapped, it is possible to determine the volume lifted by tankers or transferred to refineries through pipelines by using tank tables. Usually, the task of recording the lifted volume rests with a gauger who records it 64

on a run ticket. By the use of a device known as a thief, samples of crude oil are taken at various levels from the tank, centrifuged and measured to determine the B.S. & W content i.e. Basic Sediment (BS) and Water (W) content. Other information included in the run ticket are the tanker or pipeline names, the lease or well identification, tank number, the observed temperature, the observed gravity, B.S & W content, signatures of the gauger and other witnesses such as Customs, Petroleum Inspectorate, Nigeria Port Authority personnel and other interested parties. All of the foregoing data are necessary because the volume, and consequently the value of a barrel of oil, can be significantly affected by a change in the oil’s gravity, temperature, pressure, or, basic sediment and water content. The specific gravity of oil is expressed in degrees API. The thinner (less viscous) the oil, the higher the API gravity, and the higher the API gravity of the oil, the more valuable the oil. This is because higher gravity oil usually produces a higher yield of white products and requires less complex operations to refine into useable products. API gravity is related to specific gravity and oil with 10o API gravity will have a specific gravity of 1, the same as the specific gravity of water. The formula for API gravity is: 141.5 APIo =

-131.5 Specific gravity

Temperature has a dual effect on the measurement of crude oil. Not only can temperature change the gravity of oil, it can also change the volume. The gravity changes because oil will become lighter (less viscous and thinner) when it is heated. Obviously, if no adjustment were made, the change in gravity would affect the price of oil. The effect of temperature on volume can be appreciated when one considers that 10,000 barrels of oil at 40°F could increase to as much as 10,300 barrels at 90°F. This is an increase of 12,600 US gallons of oil. The standard unit of measurement of crude oil is a barrel of 42 US gallons at a temperature of 60°F. The composition of oil itself can also affect the volume of oil sold. Most purchasers of crude oil set limits on the percent of B.S & W they will allow. Where B.S. & W exceeds 1%, the price is usually discounted. The efficiency of production measurement has been enhanced by automated techniques using Lease Automatic Custody Transfer (LACT) units to measure the volume and quality of crude oil adjusted for temperature, gravity, compression and B.S & W content. After the adjusted volumes of oil have been calculated or determined, they are valued on a property-by-property basis in accordance with the sales contract with the purchaser. Each lifting is then valued for each purchaser, summarised for the month, and billed. 5.10.3 Revenues from Gas ing for revenue from gas is similar to ing for revenue from oil in that it involves measurement, pricing and formal recording of values. The difference is that quantitative measurement and pricing are more complex. The volume of gas delivered from a well (or the point at which oil and gas are separated) is calculated from orifice meter charts and accumulated by months. An orifice meter is a device in which the pressure differential between the two sides of an opening or construction called an orifice is used as a factor for determining the volume of flow. Gas Sales Contracts Take - or - Pay Provision 65

A gas sales contract normally provides that if the purchaser does not take the specified delivery, he must pay for the shortfall (deficiency) even if not taken. However, the purchaser is usually entitled to make-up for the deficiency payment in future supplies. Minimum Royalty Under this arrangement, the purchaser agrees to pay to a minimum amount for a stated period. The excess of the minimum payment over the value of the gas taken for a given period may or may not be deductible from the shortage arising in any future period. The essence of both the take-or-pay provision and the minimum royalty provision is to compel the purchaser to live up to the of agreement both in quantity and value. 5.11 ing for Production Costs Production cost consists of the costs of gathering, field processing, treating and field storage of oil and gas. Production commences with the lifting of oil and gas to the surface and terminates at the outlet valve on the field production storage tank. However, sometimes due to operational factors, the production function is regarded as terminating at the point at which oil or gas is delivered to a trunk line, a refinery or marine terminal. Production costs are the cost of producing oil and gas. Accordingly, they should be charged to expense. Although DD&A of capitalized acquisition, exploration and development costs form part of the cost of oil and gas produced, they are usually not classified as production costs. The practice is to disclose them separately in the financial statements. 5.11.1Classification of Production Costs Production costs may be classified in many ways. One basis of classification is by the nature of the object of the expenditure, e.g. salaries, taxes, materials and supplies. Another is by the nature of operational function served, e.g., pumping and gauging, sub-surface maintenance, secondary recovery operations. The various types of production costs classified as to their nature are as follows: Salaries This category includes salaries and wages of pumpers, gaugers, roustabouts, maintenance crews, welders etc. It also includes the salaries of the tank farm’s superintendent and production foremen. Where such supervisors have responsibility for more than one lease - as is often the case - the practice is to allocate their salaries to individual leases or wells. Contract Services Services such as pump maintenance, recompletion and workover, catering, casing repairs, paraffin control and desanding may be contracted out by an oil company. Insurance Typical insurances that may affect production costs are medical, workmen’s compensation, fire and windstorm, boiler explosions, etc. Fringe Benefits Fringe benefits are part of total compensation of labour and should be allocated to individual leases. Repairs and Maintenance Costs incurred in repairing lease equipment such as tank farms, separators, desanders, desalters, flow lines, lease cabins, engines, motors, pumps and other surface production equipment are classified as repair and maintenance and form part of production costs.

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Royalties Royalties are based on quantities produced, valued at posted prices and levied at various rates. Overhead and Supervision This category usually includes an allocated portion of the expense of operating the district office. In some companies, general and istrative expenses are allocated to district offices and thus become part of the district expenses allocated to individual leases. Two of the allocation bases most commonly used are: (a) Number of wells served, and (b) Barrels of crude oil produced. 5.11.2 Functional Classification of Expenses Company practices vary with respect to functional groupings or classification of production costs. The following functional groups or subgroups are typical: Pumping and gauging Subsurface maintenance: Pumps Tubing Casing Workovers and recompletions Treatment of oil Gas Dehydration Saltwater disposal Gathering Surface maintenance: Lease and well equipment Roads Cutting of grass and weeds Secondary recovery operations 5.11.3Direct and Indirect Expenses Production costs of oil and gas companies are classified as either “direct” or “indirect”. Direct production Costs are generally regarded as those expenditures that are absolutely essential to the production operation. Costs of gauging and pumping, sub-surface maintenance, heating and treating costs of oil and/or gas are typical direct production costs. Indirect production costs are those that facilitate or are incidental to petroleum production but do not directly contribute to it. Some examples are taxes, royalties, insurance and overhead and superintendence. If the productivity of a well is restored or enhanced, it would seem logical that since such costs will benefit future periods, they should be capitalized and amortized to those periods. Industry practice, however, is to expense workover costs. They justify the treatment on the basis of immateriality (for large companies). Although prevailing practice may result in a more “conservative” financial statement, proper matching of expenses with related revenues may not have been achieved. Well workover costs that involve drilling to a deeper horizon or plugging back to a shallower producing formation are referred to as recompletions. Since recompletions increase the production potential of reserves, such costs are capital in nature and should be capitalized as intangible costs and amortized to future periods. Although generally accepted ing principles require that production cost, being part of the cost of oil and gas produced, should be allocated to cost of goods sold and inventory, very seldom do oil companies value the oil in pipelines and tanks at cost. Inventories in pipelines and tanks are generally ignored or are valued at selling prices. The oil in the tank is viewed as a fungible good, with an assured market and therefore presumed sold as produced. Thus a portion of the revenue is realized before actual sale, a practice contrary to the realization concept. Proponents of this method 67

argue that it does not materially distort income. Clearly, two principles - the matching principle and realization principle — had not been fully complied with, as costs would not have been matched with revenues. 5.12 Financial Statements Disclosures The oil and gas industry, in fact the extractive industry as a whole, differ from companies in other industries in one significant respect - their most important economic asset, oil and gas reserves are not recorded in the balance sheet. This uniqueness posed a peculiar challenge in financial reporting, especially in reporting the financial position of oil companies without the real substance of the enterprise. In an attempt to make up for this limitation and meet the financial reporting requirements of investors, oil companies have been disclosing information on reserves by way of footnotes and supplemental information to the financial statements. It was in response to this need that the in April 1986, the U.K Oil Industry ing Committee issued Statement of Recommended Practice (SORP) No. l to provide guidance on disclosures. Also, paragraph 134 in Part IV of SAS No. 14 issued by the NASB stipulates certain disclosures, including the following: i. Method of ing ii. Capitalized costs relating to oil and gas producing activities iii. Costs incurred iv. Disclosure of the results of operation for oil and gas producing activities v. Proved oil and gas reserve quantity information vi. Disclosure of a standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Broadly, the disclosure rules apply to quoted companies with significant oil and gas producing activities. A company is deemed to have significant oil and gas producing activities if it meets any of the following three tests: i. The revenue from oil and gas producing activities (including transfers to other activities of the company) is 10 percent or more of the combined revenue from all the company’s industry segments. ii. The assets identified as related to oil and gas producing activities are 10 per cent or more of total assets of all industry segments. iii. Income after taxes (before extraordinary items) from oil and gas producing activities is 10 percent or more of the consolidated net income before extraordinary items. 5.13 ing for Refining and Petrochemical Operations Operations in the oil and gas industry are broadly divided into two, namely upstream and downstream. Refining and petrochemical production are therefore part of the downstream. Crude oil, which is the major raw material of a refinery, is a mixture of a family of organic chemical compounds made up of hydrogen and carbon in various proportions called hydrocarbons. The nonhydrocarbon materials that are usually present in crude oil are sulphur, nitrogen, nickel, vanadium, and other metals or salt which is usually in quantities less than one in a thousand. The distinguishing feature of a mixture (as distinct from a compound) is that in a mixture the components retain their individual characteristics and can be separated fairly easily. Crude oil almost has unlimited possibilities as a raw material. 2.13.1 Key Drivers of Refining Economics and Profitability The key drivers of profitability of refineries are:

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1. Quality of Crude: A company that buys light crude will be more profitable. Light crude is crude oil with API gravity that yields a high proportion of the lighter, more valuable products after refining. 2. Conversion Capacity of Refinery Plant: A more complex refinery will produce a higher total value of products from a given crude oil even though the total quantity will be reduced through the greater use of fuel for process heating. 3. Other factors that affect refinery yields are (a) Direct costs and yields (b) Lead times for receipt of crude oil (c) Storage considerations (d) Spot markets considerations etc.

5.13.2 Types of Refineries The quality of crude is a factor that most refineries have limited control over. Refiners compete among themselves to buy the best quality of crude available, but the reality is that high-quality crude is not abundantly available in sufficient quantities and in the final analysis refiners must buy what they can get. Conversion capacity is however within the control of the refiners. The higher the conversion capability of the plant, the higher the possibility of producing desired products from the available crude. Refineries are classified according to their conversion capability. Refineries consisting of atmospheric distillation units, reforming and hydro-treating units are often referred to as hydro-skimming refineries. Those with any substantial units for changing the basic yield pattern of crude oil barrel through catalytic or hydrocracking are referred to as complex or conversion refineries. 5.13.3 Petroleum Refining Processes Refining may be defined as a means of producing fuels and lubricants, among others. Basically it involves vaporizing crude oil by heating it to a high temperature, collecting the resulting gases and condensing them back to a liquid state. Crude oil refining comprises of a series of interrelated processes, all involving heating, and each producing several products. Some of these products can be put to end use without further processing while others have to undergo considerable postproduction refining, further cracking, reforming, synthesis and molecular arrangement. Refinery operations are carried out in different processing units that follow one another in processing sequence. Basic refining processes are: i. Primary process or physical separation process (Crude distillation) ii. Secondary or conversion processes iii. Treating processes iv. Blending Primary Process (Crude Distillation) The objective of distillation is to separate the many compounds contained in crude oil into groups of similar compounds. The principle underlying this process is the fact that different liquids vaporize at different temperatures (called boiling points). The separation of low and high boiling points materials in this way is called fractional distillation (fractionation). The process is accomplished by running the crude oil through a number of pipes lining a brick furnace (heater/boiler). The crude oil is heated to a temperature of approximately 800o F after which it rises to the top of the furnace as vapour and is then transferred to the fractionation tower. The points at which they start to boil are called Initial Boiling Points (IBP) and where they stop boiling is called End Boiling Points (EBP). At the EBP, the product would have been completely vaporized. 69

The fractions produced from this atmospheric fractionation towers can be used in their new state, blended with other substances or further processed to make useful products. The maximum temperature at which hydrocarbons can be separated in the atmospheric tower is 900oF. Steam keeps the oil hot and low pressure allows the hydrocarbons to vaporize at temperatures below their cracking points enabling them to be separated into fractions. The light and heavy gas oils are separated from the heaviest residue. The primary process separates the various fractions, which may serve as inputs for the secondary process. These inputs are otherwise known as “charging stocks”. The term “charging stock” refers to unfinished products that are to be further processed in some secondary refining operation. These secondary processes either result in new products or bring primary products to required quality standards. The intermediate products, in order of increasing boiling range, are listed below. (a) Fuel gas -to refinery fuel gas - below 100°F (b) Light straight run gasoline - to sweetening and then to gasoline blending (Boiling range 100°F-200°F). (c) Heavy straight - run gasoline -to hydrogenation, to catalytic reforming and then to gasoline blending (Boiling range 200°F-400°F). (d) Middle distillates — to kerosene, jet fuel, furnace oils, diesel fuels (Boiling range 350°F600°F). (e) Catalytic cracking charge — to fluid catalytic unit charge (Boiling range 450°F -750°F). (f) Fuel residue — vacuum distillation unit. (Boiling range about 700°F) Secondary or Conversion Processing The primary process can only separate crude oil into its natural components as they exist and cannot alter the mix of the components. It is therefore necessary to use some form of conversion (or yield shift or upgrading) process in order to change the proportions of the various products that can be obtained from crude oil. Secondary or conversion processing consists of cracking and non-cracking processes. Cracking Cracking is the most common form of conversion. Cracking involves breaking up of large molecules to form smaller ones. Cracking can either by thermal cracking (which involves heating the feedstock to very high temperatures, which cause the large molecules of heavy feedstock to decompose into the smaller molecules of gas oil and motor spirit), or fluid catalytic cracking (which involves the use of chemicals known as catalysts that break hydrocarbon molecules at a high reaction temperature into smaller molecules. Oil is mixed with fresh catalyst and run ‘through the reaction several times in order to enhance the yield and turn all the cycle oil to useful petroleum products), or hydro-cracking (which involves the use of extra hydrogen to saturate the chemical bonds of the cracked hydrocarbons, thus resulting in reduction of the molecular size), or visbreaking (which is a refinery upgrading process that lowers (i.e. breaks) the viscosity of residues by cracking at fairly low temperatures) Non-cracking Conversion Processes This is achieved through delayed coking (a more specialized process that normally uses the residue from low-sulphur crude to produce electrode-grade coke used in the production of aluminum, gas, motor spirit and gas oils), or fluid coking (a development of the coking process in which the yield of the more valuable lighter products from the residue feedstock is maximized), or blending

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(process that involves the selective mixing of basic components to give a wide range of individual grades of the same product). 5.13.4 Petrochemicals A petrochemical is a chemical substance produced commercially from feedstock derived from crude oil or natural gas. Petrochemical plants are usually integral parts of large refining complexes and often subsidiaries of major oil companies. Their function is to turn outputs of the refining process either in form of crude oil fractions or their cracked or processed derivatives into feedstock that will ultimately be used in the manufacture of a host of other products e.g. plastics, resins, synthetic rubbers, printing ink, paints, acid, fertilizers, detergents, etc. Petrochemical feedstock falls into three main classes based on the chemical structure and composition of each. The three main classes are: (a) aliphatic compounds, (b) aromatic compounds, and (c) inorganic compounds.

5.14 ing for Refinery Operations ing for refinery operations begins with the costs incurred from the receipt of crude oil, to the costs incurred in various refining processes, the cost of additives, investments in plant machinery and other operating costs. The ing treatment of costs incurred in a refinery operations are discussed under various headings below: 5.14.1 Basis of Capitalization Any amount expended in order to improve the earning capacity of the refinery is capitalized while any expenditure incurred in order to maintain the earning capacity of the business is charged to the operations of the particular period. However, the assistance of engineers may be required in determining which expenditure is capital or revenue. 5.14.2 Crude Oil Purchasing In an integrated oil company, it is more often than not the case that the quantity, timing and mix of crude oil produced do not match with the requirements of the refinery. 1t is a practice in the refinery to strike a balance between the crude oil available in quantity, timing and mix and crude oil required in quantity, timing and mix. This is achieved by crude exchanges with other companies, purchases of crude oil and sale of crude oil. Crude oil exchanges are recorded in the ing books by memorandum entries only. Purchases of crude oil are ed for in the cost of sales while sales of crude oil are recorded as sundry income. 5.14.3 Transfer Pricing As stated earlier, a refinery is frequently an integral part of an integrated oil company. It follows therefore that, as in other integrated companies, inter-departmental transfers are common, hence, the need to determine transfer price. It is also important to determine what the transfer prices of gasoline and other products of the refinery transferred to the company’s marketing division will be. Fixing of transfer prices is a function of the management who rely heavily on the information supplied by the ant. It is important that transfer prices are fixed in order to ensure that: i. the performance of the transferring divisions, departments or subsidiaries can be evaluated; ii. goal congruence within the organization is enhanced; iii. the autonomy of each division, department or is maintained; iv. the overall organization is put at a tax advantage; and v. the cost of inefficient operations or decision-making would be revealed for necessary corrective action. The following transfer pricing methods are frequently used . (1) Market based pricing 71

(2) Cost based pricing (3) Negotiated pricing (4) Free market prices for both inputs and output (5) Cost plus margin for value of services rendered 5.14.4 Processing of Crude Oil Belonging to Outsiders Where the refinery receives crude oil belonging to third parties for processing, only memorandum records are to be kept to control the quantity. The consideration received inform of processing fees should however be treated as a deduction from operating costs. Cost of Catalysts The ing treatment of the cost of acquisition of expensive catalysts in refinery operations is to capitalize the costs of the initial supply and depreciate them in accordance with normal ing practices. The costs of reprocessing and replenishing them are however charged to the operation of the period. Cost of Periodic Turnaround Maintenance Costs incurred in the periodic maintenance of the refinery are initially capitalized. A provision for turnaround costs is then made monthly to operating expense. Depreciation Depreciation is computed on a composite straight-line basis for the entire plant. Total depreciation is then distributed to production and other units on the basis of investment in the units. Standby Equipment Refineries have a considerable investment in standby equipment which may be used in case of emergencies or when production operations increase. There are many ways f treating depreciation on these equipments. The most acceptable treatment is to make periodic provision for standby wear and tear on these equipments and exclude them from the composite depreciation base. Inventory Valuation In accordance with normal ing practice, inventories are valued at lower of cost and net realizable value. Inter-departmental profits must be eliminated from inventory. . Sundry Income Outright crude oil sales and other incomes are included in sundry income. 5.15 Accumulation and Classification of Costs Costs are generally classified and accumulated by object and by function. The object classification is the normal classification in financial ing where costs are classified as wages, salaries etc. For managerial ing purposes however, this classification will not provide adequate information. Functional classification of costs means that costs are segregated by areas of managerial responsibility for the purposes of cost control. All costs, including depreciation, are classified by areas of managerial responsibility and segregated according to the various products and service units except the following: i. Cost of crude oil - This cost is charged to the purchases and transferred to the manufacturing at the end of the period. ii. Cost of materials and supplies in inventory - This cost is adjusted before determining the amount consumed in operations and then treated as current assets in the balance sheet.

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5.16 Allocation of Costs Total production cost must be determined and spread over units produced in order to determine unit product costs and selling prices. Costs of service unit must be spread over production units before unit product costs are determined. Costs also have to be allocated to t products. 5.16.1 Service Department Cost Allocation Three methods are used to allocate service department costs to production costs and subsequently to production units. They are: (1) Direct method (2) Step method (3) Simultaneous method 5.16.2Allocation of Cost to t Products: When the allocation of service costs to production units is completed, there still remains the task of allocating costs to t products. The methods commonly used for this allocation are: (i) physical method (ii) market method (iii) relative sales value method (iv) replacement cost method (v) alternative use method, and (vi) by-product method.

DISCUSSION EXERCISES Question One During the first quarter of 2012, BUK Oil Company Nigeria Limited produced 50,000 barrels of crude oil from field New-Site oil field, which is located onshore. 5,000 barrels out of the total production were re-injected into the well to enhance crude oil recovery from an ading lease. The power generators used for field operations consumed 1,000 barrels during the quarter and 500 barrels were lost through evaporation. Assuming that posted price for the crude stream is US$21.00 per barrel and exchange rate of US$1 is equal to N152.00 You are required to compute royalty liability for the quarter, assuming that the applicable rate of royalty is 20 per cent. Solution to Question One BUK Oil Company Nigeria Limited Computation of Royalty Liability for the First Quarter, 2012 Gross production of crude oil Less: Quantity of crude oil re-injected into the formation 5,000 bbls Production used for field operations 1,000 bbls Quantity lost through evaporation 500bbls

50,000 bbls

6,500 bbls 43,500 bbls $21

Net production Posted price per barrel

73

Chargeable value of crude oil in Dollars Conversion to Naira ($1=N152) Chargeable value of crude oil in Naira Applicable rate of royalty Royalty payable

$ 913,500 N 152 138,852,000 20% N27,770,400

Question Two Ramat Oil Company Limited is an integrated oil company whose operations include exploration, production, refining, petrochemicals and transportation. During the year ended 31 December 2011, the company produced and transported 1,000,000 barrels of crude oil through its network of pipelines. Out of the quantity produced 400,000 barrels were transferred to the company’s refineries in Nigeria. The posted price of the crude oil transferred to the refinery was $22.00 per barrel and the standard and actual API° of the crude stream were 40° and 42° respectively. The pipelines cost was N 95,000,000 and are depreciated on a straight- line basis at the rate of 5 per cent per annum. N 8,000,000 were spent on repair and maintenance of the pipelines during the year. Exchange rate of Naira to the Dollar is $1.00 = N 150.00 Required Calculate the value of crude oil delivered to the refineries during year 2011, assuming that posted price of crude oil are escalated or de-escalated by $0.03 for every API° difference between standard and actual API degree. Solution to Question Two Ramat Oil Company Limited Computation of Value of Oil Delivered to Refinery For the Year Ended 31st December , 2011 Quantity of oil transported to refinery 400,000 bbls Posted price of crude oil per barrel Standard API gravity 40° Actual API gravity 42° Difference 2° Escalation rate $0.03 Escalation Adjusted posted price per barrel (in Dollar) Adjusted posted price per barrel (in Naira)

$22.00

$0.06 $22.06 N3,309 N

Value of oil for royalty purposes: 1,000,000 bbls @ N3,309/bbl =

3,309,000,000

Value of oil delivered to refinery 400,000 bbls @ N3,309/bbl =

1,323,600,000

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Cost of extraction of oil deducted in determining posted price: Cost of maintenance of pipeline N 8,000,000 Depreciation of pipeline ( 5% of N 95,000,000) N 4,750,000 N 12,750,000 Add: Cost of transportation 4/10 X 12,750,000 Total cost of crude oil delivered to the refinery

5,100,000 N 1,328,700,000

Question Three The following information relates to Gwarzo Oil and Gas Nigeria PLC for the year ended 31 December 2009. Trial Balance as at 31st December, 2009 Particulars Dr. Cr. N' 000 N' 000 Crude oil Inventory at 1/1/2009 6,700,000 Export Sales 50,000,000 Local Sales 10,000,000 Production Cost 9,000,000 Transportation cost 1,500,000 Intangible oil and gas assets 117,000,000 Salaries and wages 300,000 Proved oil and gas properties 13,500,000 Unproved oil and gas properties 8,300,200 Accumulated DD&A: Oil and Gas Assets 5,200,500 Loan Interest 3,500,000 Bank interest 1,700,000 Geological and geophysical costs 800,000 Carrying costs and overhead 135,000 Surrendered and impaired leases 230,150 Unimpaired leases 1,500,000 Exploratory wells: Successful 15,672,000 Unsuccessful 2,250,000 Development wells 20,567,000 Wells in Progress 11,570,000 Expenditure for purchase of seismic data 683,650 Royalties 1,500,000 Derivative financial instruments 500,800 Loss on exchange 1,450,000 Trade and other receivables 3,500,000 Derivative financial instruments 2,503,200 75

Cash and cash equivalents Trade and other payables Investments in subsidiaries Other current assets Share capital Share Other reserves

500,000 12,500,000 14,500,000 50,250,100

289,111,300

200,500,000 9,850,000 560,000 289,111,300

The following additional information are also available (all the Naira figures are in thousand N'000): (i) Closing stock of oil and gas as at 31st December, 2009 N1,200,000 (ii) Accrued expenses as at 31st December, 2009 amounted to N3,500,700 (iii) Provision for decommissioning amounting to N564, 2000 is to be provided. (iv) DD& A is to be provided on proved oil and gas properties. Production during the year was 500,000 of oil and 600,000 mcf of gas. Reserves estimates of oil and gas at the beginning of the year (i.e. 1st January 2009) were: oil 5,000,000 bbls and gas 1,800,000 mcf, and the relative proportion of oil and gas is not expected to continue throughout the life of the property. (v) All capitalized costs and intangible oil and gas assets are to be amortized at the rate of 10% per annum. (vi) The Director's proposed a dividend of N2, 000,000 on shares and Petroleum Profit Tax is to be calculated at the rate of 70%. (vii) All workings are to be made to the nearest Naira. You are required to prepare the final s of the company in Horizontal form for use of the Company's management for the year ended 31st December, 2009, using (i) Full Cost Method, and (ii) Successful Efforts Method. Solution to Question Three (i) Full Cost Method

Gwarzo Oil and Gas Nigeria PLC Trading, Profit and Loss for the Year Ended 31st December 2009 N'000 N'000 Opening stock 6,700,000 Export Sales 50,000,000 Production Cost 9,000,000 Local Sales 10,000,000 Transportation cost 1,500,000 Royalties 1,500,000 18,700,000 Less closing stock 1,200,000 17,500,000 Gross income from operations c/d 42,500,000 76

60,000,000 Accrued expenses Provision for decommissioning DD&A on proved properties Salaries and wages Loan Interest Bank interest Purchase of seismic data Loss on exchange Amortization: Intangible assets Other capitalized costs Net income from operations c/d

PP Tax 70% Proposed dividend Balance c/d

60,000,000

Gross income from 3,500,700 operations b/d 5,642,000 939,566 300,000 3,500,000 1,700,000 683,650 1,450,000 11,700,000 4,115,415 8,968,669 42,500,000 Net income from 6,278,068 operations b/d 2,000,000 690,601 8,968,669

WORKINGS (i) DD&A on proved properties

Production of oil and gas in bbls Gas in bbls 600,000 X 1/6 = Oil in bbls Production of oil and gas in bbls

100,000 500,000 600,000

Opening reserves of oil and gas in bbls Gas in bbls 1,800,000 X 1/6 = bbls of oil Opening reserves of oil and gas in bbls

300,000 5,000,000 5,300,000

Unamortized cost at the end of the year (13,500,000-5,200,500) = 8,299,500 DD&A

600,000

8,299,500=

N 939,566

5,300,000 (ii) Other Capital Costs Geological and geophysical costs Carrying costs and overhead Surrendered and impaired leases

N 800,000 135,000 230,150 77

42,500,000

42,500,000 8,968,669

8,968,669

Unimpaired leases Exploratory wells: Successful Unsuccessful Development wells Total

1,500,000 15,672,000 2,250,000 20,567,000 41,154,150

Balance Sheet as at 31st December, 2009 N' 000

Share capital

Reserves Share Other reserves P&L a/c balance Shareholders' fund Long Term Liability Long Term Borrowings Current Liabilities Accrued expense Provision for decommissioning Derivative financial instruments Trade and other payables Petroleum profit tax Proposed dividend

N'000 N'000 Accumlatd Cost DD&A NBV 13,500,000 6,140,066 7,359,934

Fixed Assets 200,500,000 Proved properties Unproved properties 8,300,200 ----8,300,200 Intangible assets 117,000,000 11,700,000 105,300,000 Other capitalized 9,850,000 costs (ii) 41,154,150 4,115,415 37,038,735 560,000 Wells in Progress 11,570,000 ----11,570,000 690,601 191,524,350 21,955,481 169,568,869 211,600,601 Investment Derivative financial instruments Investments in subsidiaries 27,500,00

2,503,200 14,500,000

Current Assets 3,500,700 Stock

1,200,000

5,642,000 Trade and other receivables

3,500,000

500,800 Cash and cash equivalents Other current 12,500,000 assets 6,278,068 2,000,000 242,022,169

500,000 50,250,100

55,450,100

242,022,169

(i) Successful Efforts Method

Other Capital Costs

N'000

N

78

Unimpaired leases Successful exploratory wells Development wells

1,500,000 15,672,000 20,567,000 37,739,000

Gwarzo Oil and Gas Nigeria PLC Trading, Profit and Loss for the Year Ended 31st December 2009 N'000 N'000 Opening stock 6,700,000 Export Sales 50,000,000 Production Cost 9,000,000 Local Sales 10,000,000 Transportation cost 1,500,000 Royalties 1,500,000 18,700,000 Less closing stock 1,200,000 17,500,000 Gross income from operations c/d 42,500,000 60,000,000 60,000,000 Accrued expenses Provision for decommissioning DD&A on proved properties Salaries and wages Loan Interest Bank interest Purchase of seismic data Loss on exchange Geological and geophysical costs Carrying costs and overhead Surrendered and impaired leases Unsuccessful exploratory well Amortization: Intangible assets Other capitalized costs Net income from operations c/d

PP Tax 70% Proposed dividend Balance c/d

Gross income from 3,500,700 operations b/d 5,642,000 939,566 300,000 3,500,000 1,700,000 683,650 1,450,000 800,000 135,000 230,150 2,250,000 11,700,000 3,773,900 5,895,034 42,500,000 Net income from 4,126,524 operations b/d 2,000,000 (231,490) 79

42,500,000

42,500,000 5,895,034

5,895,034

Share capital

Reserves

Share Other reserves P&L a/c balance

Balance Sheet as at 31st December, 2009 N' 000 N'000 Fixed Cost Assets Proved 200,500,000 properties 13,500,000 Unproved properties 8,300,200 Intangible assets 117,000,000 Other capitalized 9,850,000 costs (i) 37,739,000 Wells in 11,570,000 560,000 Progress (231,490) 188,109,200

Shareholders' fund

Current Liabilities Accrued expenses Provision for decommissioning Derivative financial instruments

Trade and other payables Petroleum profit tax Proposed dividend

5,895,034

N'000 N'000 Accumlatd DD&A NBV 6,140,066

7,359,934

----

8,300,200

11,700,000 105,300,000

3,773,900

---11,570,000 21,613,966 166,495,234

210,678,510 Investment Derivative financial instruments Investments in subsidiaries Current Assets 3,500,700 Stock Trade and other 5,642,000 receivables 500,800 Cash and cash equivalents Other current 12,500,000 assets 4,126,524 2,000,000 238,948,534

80

33,965,100

2,503,200 14,500,000

1,200,000 3,500,000 500,000

50,250,100

55,450,100

238,948,534

81