The Regulation of Offshore Oil & Gas Production in Ghana

The Regulation of Offshore Oil & Gas Production in Ghana Kwame Mfodwo Offshore Oil and Gas Document DRAFT FOR INSERT OF FINAL ILLUSTRATIONS AND PROOF-READING Kwame Mfodwo T Table of Contents v Final Table of Contents Goes here vi 1 INTRODUCTION Introduction 7 WHY THIS BOOK? he discovery of petroleum of Ghana’s western coastline has raised considerable expectations in the Ghanaian community both at home and abroad, with many expecting that revenues will bring about signiicant changes in the living conditions of Ghanaians. Whilst it is unclear whether in fact signiicant beneits will be generated for the mass of the population, there can be little doubt that Ghana is now about to move squarely into the category of being a petroleum producing country once all its three major projects are all fully on stream. We refer here to the Jubilee, TEN and Sankofa projects. his monograph is not however about speciic projects or petroleum in Ghana generally, It aims to focus narrowly but in considerable depth on one aspect of the overall system by providing a comprehensive account of the current law and policy framework regulating ofshore petroleum exploration and production in Ghana. It comes soon ater Ghana’s Parliament passed a new petroleum law titled the Petroleum Exploration and Production Act (2016) Act 919, replacing the previous statute, Petroleum (Exploration and Production) Law, 1984, PNDCL 84. he new statute was passed in August 2016. It can thus in that sense be viewed as timely. his monograph although very much about law, is however not a law textbook, even though the various statutes that are at the heart of the regulatory regime are set out and explained in comprehensive detail. We have instead tried to provide a book that places the law and policies governing ofshore oil and gas in Ghana in their proper context, in particular, their technical, policy, organizational geographical and economic context. Although much could have been made out of describing Ghana’s petroleum resource base in some detail, and also setting out projected future trends and discoveries, a deliberate choice has been made to leave these matters to other authors. A deliberate choice has also been made not to discuss issues about revenue, inance and money and whether or not Ghana’s petroleum is being fairly shared out or the revenues are well managed as there are many other commentators and authors working in this area. Instead it is hoped that this book will ill a gap by providing a comprehensive and systematic account of the regulatory regime. he overall conclusion of the author is that Ghana now has what is on balance a satisfactory regulatory regime which at least on paper meets the required international standards of good governance and accountability and provides a predictable and internationally well informed framework for investment into the search for and production of petroleum. It is arguably important that all interested parties have a reference publication which explains the regulatory framework in some detail whilst tying it back to the context in which it operates. It is in that sense that this book has been produced as a contribution to improving our understanding of our prospects as a petroleum producing country - we anticipate that our lives will be improved by the country becoming a medium-sized producer and exporter of petroleum – it is useful, it can be argued if we understand the network of laws and policies that govern Ghana’s petroleum a lot better. WHO MIGHT BE INTERESTED IN THIS BOOK? It is intended and hoped that diferent groups interested in understanding this key aspect of Ghana’s ofshore oil and gas system will ind the publication useful. Lawyers should ind the comprehensive elaboration of the statutes useful whilst both lecturers and students in the various oil and gas courses taught at the various tertiary institutions should also ind the deliberate eforts to consistently place law and policy matters in their full context useful. A sound and 8 Introduction basic understanding of the technical aspects of the petroleum sector is also useful for politicians and civil society activists interested in the petroleum sector. Enough information is provided about the range of issues that are of interest those politically engaged with and involved in petroleum matters without the author taking sides. INTER-RELATIONSHIP BETWEEN OIL AND GAS Although this monograph is primarily about oil, it is perhaps useful to address matters to do with gas in some detail as Ghana has an appreciable level of gas resources. Gas and oil are generated by the same geophysical processes and are thus oten found together (Chapters 2 and the Glossary provide further technical detail on this issue and its implications for OOGP). Figure 1he relationship of Oil and Gas here is also an intermediate commodity between gas (gaseous in form) and oil (liquid in form). his is condensate (See Glossary for more detail). he bulk of the world’s gas reserves have been found in the course of drilling for oil. Gas found with oil is known as associated gas (See Glossary). here are however many areas of diference between the two as energy commodities.1 Until the commercial proile of gas begun to improve in recent times (due principally to the environmental preferability of gas - lower GHG emissions; other aspects of cleanliness – see Chapter 6 on environmental considerations) most ields were developed with a primary focus on oil. Until environmental concerns restricted laring, in most cases, the associated gas was lared. However a trend is now developing for associated gas to be used to assist with the extraction of the crude oil and condensate (gas lit/gas drive approaches – see Chapter 2) or for associated gas to be re-injected into the ground and capped for storage until gas markets are available. Condensate also has a role since it readily liqueies at normal atmospheric pressure and can be used as a high quality feedstock in oil reineries. Gas is more costly to prepare for sale at the wellhead and deliver to customers. hus while oil and condensate are relatively easy to handle and ship, gas must be dried and cleaned, the carbon dioxide must be removed and the gas compressed for transportation in pipelines or liqueied for export by ship. In overall terms, gas is more costly to transport than oil. here are also longer lead times before cash lows from the sale of oil as compared with oil and condensate – meaning it takes longer to recoup costs. his is due to gas markets having to be found, contracts requiring negotiation and the need to pre-establish transport systems either fully or in part. Gas prices have to be negotiated with one or a very small group of buyers. Introduction 9 END USES OF OIL AND GAS he range of products that can be obtained from crude oil and natural gas is shown below: Figure 2 Uses of Oil and gas: a detailed proile Source: OPEC, What is Oil, 1983, 6 For Ghana, it is this wide range of end-uses that presents a real opportunity, not just the fact that revenues will be earned from the sale of crude oil to the marketplace. Prudent exploitation of the petroleum resources and master plans to utilise both petroleum and gas locally should provide the basis for industrialisation based in part on the many uses of oil and gas. Sound regulation of exploration for and production of petroleum is of course a key input into this process of achieving industrialised status. THE PETROLEUM VALUE CHAIN A supply chain or value chian is the network of all the arrangements (countries of origin, raw materials, intermediate products, places, factories, organizations, labour force, owners, physical resources, production processes and technologies) that are brought together to create and sell a commodity or product, in this case petroleum and what is derived from petroleum. Ghana now has a place in the global network supply or value chains for petroleum as one of the world’s most valuable commodities. Figure 1 below provides an idea of the value chain for petroleum products as end uses from petroleum in its natural state in a generic way. 10 Introduction Figure 3 he Value Chain for Petroleum2 It shows that the industry value chain in the petroleum sector includes development, production, processing, transportation and marketing of petroleum . As Tordo points out:3 he value chain starts with the identiication of suitable areas to conduct exploration for oil and/or gas. Ater initial exploration, petroleum ields are appraised, developed, and produced. hese activities are generally called exploration and production (E&P) or referred to as “upstream” oil and gas. Oilield services include a number of auxiliary services in the E&P process, such as geological and geophysical surveys and analysis drilling, equipment supply, and engineering projects. hey form an important part of the overall oil and gas industry and are central to E & P. Infrastructure, including transport (such as pipelines and access to roads, rail, and ports) and storage, is critical at various stages in the value chain, including the links between production and processing facilities and between processing and inal customer. hese parts of the value chain are usually referred to as “midstream”. Oil reining and gas processing turn the extracted hydrocarbons into usable products. he processed products are then distributed to wholesale, retail, or direct industrial clients. Reining and marketing (R&M) is also referred to as “downstream”. his book provides a discussion of the regulation of the upstream part of the global network of supply or value chains that is physically located in Ghana focusing in detail on the regulatory dimension accompanying the following matters: Introduction 11 Stage in the Life Cycle of Key elements of this stage the Petroleum Project4 Exploration During the exploration phase, geological and geophysical surveys (such as seismic surveys and core borings) are acquired. he data so acquired are processed and interpreted and, if a play appears promising, exploratory drilling is carried out. Depending on the location of the well, a drilling rig, drill ship, semisubmersible, jack-up, or loating vessel will be used. Appraisal If petroleum is discovered, further delineation wells are drilled to establish the amount of recoverable oil, production mechanism, and structure type. Development planning and feasibility studies are performed and the preliminary development plan is used to estimate the development costs. If the appraisal wells are favorable and the decision is made to proceed, then the next stage of development planning commences, using site speciic geotechnical and environmental data. Once the design plan has been selected and approved, contractors are invited to bid for tender. Normally, ater approval of the environmental impact assessment by the relevant government entity, development drilling is carried out and the necessary production and transportation facilities are built. Once the wells are completed and the facilities are commissioned, production starts. Workovers must be carried out periodically to ensure the continued productivity of the wells, and secondary and/or tertiary recovery may be used to enhance productivity at a later time Development Production Decommssioning At the end of the useful life of the ield, which for most structures occurs when the production cost of the facility is equal to the production revenue (the so-called economic limit), a decision is made to abandon. Planning for abandonment generally begins one or two years prior to the planned date of decommissioning (or earlier, depending on the complexity of the operation). ACTORS AND PARTICIPANTS IN THE PETROLEUM VALUE CHAIN he core interests and stakeholders involved in OOGP in Ghana and elsewhere can be characterrised as follows: • governments owning the natural resource • national oil companies ( Petrobras, Saudi Aramco (Saudi Arabia); National Iranian Oil Company (Iran); China National Petroleum Corporation (China); Petroleos Mexicanos (Mexico) ; Kuwait Petroleum Company (Kuwait); Nigerian National Petroleum Corporation (Nige12 Introduction • • • • • • ria) he super-majors – extremely large highly integrated transnational petroleum production and distribution companies divided into super-majors: BP plc (United Kingdom); Chevron Corporation (United States); ExxonMobil Corporation (United States); Royal Dutch Shell plc (Netherlands and United Kingdom); Total SA (France) ; he majors – also internationally diversiied but with a much smaller capital base - ConocoPhillips Smaller companies operating mainly in the exploration sector and known as independents – Kosmos, Tullow, Anadarko highly specialised transnational service and supply companies – Schlumberger, Baker Hughes governments of consuming countries afected publics and interested NGOs in many countries, including Ghana General objectives sought by governments include: • • • • • • • • Rapid and thorough exploration Rapid and efective development of commercially signiicant discoveries OOGP at rates and using methods which will ensure maximum ultimate recovery Pricing and marketing of O & G products to ensure that maximum beneit accrues to the national economy Transfer of technology and skills to nationals Maximisation of overall beneit to the economy – local, regional and national Minimum negative ecological impacts – minimal negative corporate footprint Minimum negative social and other impacts – minimal negative corporate footprint Corporate objectives are to ensure • Proitability • Market-share • Access to reserves UNIQUE FEATURES OF OFFSHORE OIL AND GAS PRODUCTION Compared to other production sectors, OOGP is fairly unique with much of this uniqueness related to risk and uncertainty. Some of the ways in which OOGP is relatively unique are as follows: 1. he physical environment for production is generally diicult and poses major risks for both equipment and personnel (winds, weather, distance from shore, extreme events, sabotage, terrorism etc.). In general, the physical environment getting harsher and harsher given that most of the O & G close to shore5 has already been found leaving deepwater developments as the main source of opportunity ofshore. Chapters 6 and 7 show that Ghana now has a robust regulatory regime with respect to environmental and safety matters. 2. here is a progressively reducible but never completely eliminated uncertainty with respect to the amount, relevance and accuracy of data on which to base decisions to explore for and produce petroleum. Chapter 3 also shows that Ghana has a robust regime which requires the oil companies to provide information to Ghana on an ongoing basis so that the stock of information about Ghana’s resources is constantly increasing. 3. here is a progressively reducible, but never completely eliminated uncertainty as to the Introduction 13 best ways in which to economically recover petroleum in a technically and environmentally sound manner. Chapter 2 discusses this further. Chapter 3 also shows that Ghana has a regime which permits the Government to implement a lexible production strategy. Environmental obligations set out in law are also very robust. 4. he price of O & G luctuates remarkably and in an unpredictable manner. Price uncertainty and unpredictability makes it diicult for inancially interested parties (extraction companies; governments; investors and lenders) to assess future proits with any degree of certainty. 5. here is a signiicant time lag between the commencement of commercial development and production of O & G and the time of discovery of commercial inds. (See generally Chapter 2 and Glossary). High levels of capital expenditure (CAPEX) are thus made with no prospect of return for quite a few years. Chapters 3, 4 and 5 set out the regulatory response to this issue within the Ghana framework. 6. Competition between prospective use of funds for O & G and funds for alternative uses is quite intensive and within the O & G sector itself, there may be quite intense competition between alternative projects. Chapters 3, 4 and discuss this issue further. Ghana’s new laws deal with this factor to some degree. 7. Additionally the scale of operations that is required or alternatively the technical and other forms of diiculty requires irms to diversify their risk by entering into joint-venture agreements. hese agreements may themselves create extra risk. A good example is where partner in a joint venture may become insolvent (due to diiculties elsewhere in its operations globally or locally) and solvent partners may need to carry the costs properly allocable to the insolvent partner. Where mergers and acquisitions occur these may also impact on joint ventures with new owners oten attaching less importance to previously agreed joint operations. Chapters 3, 4 and 5 addresses this issue in more detail. 8. Tax liability may not be fully known until well into the life of the project, although prospects can be modeled. Chapter 4 discusses this issue further. 9. OOGP takes place in a context of multiple resource use with no automatic guarantees of priority for OOGP users over other users of the marine zone. Chapter focuses on this issue in more detail. 10. Environmental concerns and the political, economic and technical uncertainties of this arena create further risk6 as shown by Chapter 5. 11. he full extent of material scope as well as liability with respect to decommissioning of facilities and remediation of vacated sites may also not be known with certainty until well into the life of a ield, although requirements can be modeled. Chapter 6 discusses this further. . UNCERTAINTY AND RISK IN OOGP Uncertainty and risk are central features of OOGP. hey can be viewed as being multi-layered and almost pyramid like in character. As Chapter 2 shows, exploration related uncertainty comprises: mapping uncertainty; seismic uncertainty and luid contacts uncertainty (Chapter 2 discusses the concept of luid contacts and its importance to OOGP in considerable detail). Assuming that petroleum is discovered, these uncertainties continue but are now joined by a related uncertainty – the issue of the size of the accumulations of petroleum within the ield and uncertainty as to the best ways in which to capitalize on the natural energy of the ield to best produce its resources (see Chapter 2 for further discussion on how oil and gas are produced using natural drives or energies within the ield). he types of geological or petrological uncertainty operating at this stage include: the permeability of the rock containing the oil (see Chapter 2); the strength of the cap rock holding the oil in place; the size of the oil, gas and water accumulations and their relationship with each other (Chapter 2 explains the technical aspects of these matters in more detail). 14 Introduction Figure 4 Risk Factors in OOGP7 he other layers of uncertainty which need to be matched to the petrological and geological uncertainties are the political-economic ones: (1) namely what the future demand for oil and/ or gas will be, a matter tied also to demand for other forms of energy and other factors; (2) how demand will translate into price and inally (3) uncertainty with respect to government and other stakeholder behaviour during the life of the proposed or actual project. Currently NGO concerns and behaviour are an overriding consideration for many projects together with the interests of persons and groups directly afected by the company footprint. he preferences, prejudices of pre-judgments of end-consumers of oil products may also impact on the project due to concerns over health and safety, environmental impacts and/or protection of the rights and interests of local groups and peoples. Reducing and Managing Risk – The Techniques and Tools of OOGP Tools to deal with the scientiic-technical as well as economic-inancial aspects of uncertainty are legion with the OOGP having created its own composite tools and techniques relying in insights and principles from mathematics, physics, chemistry, statistics, inance, economics and other disciplines which study probabilities and risks. Reducing Uncertainty: Industry Division of Labour and Transactional Response Ramsey8 suggests that risk and uncertainty are key drivers of the transactional forms in use by OOGP irms. He argues that irms tend to pool their activities so as to improve their information and reduce risk to the extent that pooling helps manage risk in a variety of ways. his is one of the basic reasons for the importance of the joint venture as an important transactional form in OOGP. Additionally, as Ramsey suggests, irms tend to specialize in the types of exploration in which they engage. As he describes it: he large majors use capital-intensive and time-extensive methods looking for the large ields … the smaller independents use less capital intensive and less time-extensive methods to look for ields (in the middle) whereas the wildcat promoters use the smallest amount of capital input (almost all of which is concentrated in drilling expenditures) in order to explore by drilling methods areas near those being examined by the other irms, but which are not worth consideration by the larger irms; in short, wildcatters ill in the Introduction 15 “holes in the exploratory search pattern” let by the larger companies9. Hallwood10 also views risk and uncertainty as contributing signiicantly to the forms of contracting that production companies enter into with service and supply companies. here is a pre-disposition to re-engage well-known co-transactors together with a structured system of periodically contracting in “unknown” companies so as to beneit from whatever innovations they might bring to the OOGP process. DESCRIPTION OF CHAPTERS It is against this background that this book looks closely at how the local segment of this global value chain is regulated with a speciic focus on Ghana. he monograph is structured into 8 chapters. Chapter 1 (this Chapter) provides a brief introduction to the overall context. Chapter 2 addresses the technical aspects of exploration and production for oil and gas through a simple non-technical review of the key features of exploration, production and decommissioning. Chapter 3 addresses the regulatory regime for the ive separate but inter-related aspects of OOGP. It addresses these issues both generally but with speciic reference to Ghana’s regulatory regime. It is the heart of the monograph as it extensively discusses PEPA 2016 and how it applies to all stages of the life-cycle of a petroleum project, namely: exploration; appraisal; development; production and decommissioning. he competing interests of Host Governments and companies are discussed throughout the Chapter together with areas of shared interest or compromise. Ghana’s comprehensive regulatory coverage of the key issues is clearly demonstrated. Chapter 4 discusses the range of iscal instruments in use generally and currently in Ghana. An extensive policy based discussion is provided of all the key taxation and iscal instruments. he simpler ones (royalties and bonuses) are explained together with the more complex instruments like the progressive income taxes; additional oil entitlements and resource rent taxes or taxes on super-normal proits. hese taxes which are tied more directly to project proitability (R-factor or rate of return, RoR) are diicult to design and administer and their current use in Ghana is comprehensively explored. he special considerations that apply to corporate income taxation are also addressed, including in particular the concept of ring-fencing to ensure that companies pay taxes ield by ield rather than organizing arrangements in which losses on one ield are booked against gains in another leading eventually to low or zero rates of tax payment. he regime for controls over transfer-pricing is discussed as well as the use of an arms-length standard to regulate and tax transactions. Chapter 5, titled “Contracting in Hydrocarbons” discusses the diferent types of arrangements that companies in the petroleum sector use amongst themselves. Such contracts include joint operating agreements that govern the operations of the consortia for large projects and farm-ins and farm-outs which are core arrangements in which a inancial partner joins the active operator in bearing exploration (or less typically, development and production) risk. hese contracts govern horizontal relations between the actors in the sector, whilst the vertical relationship between Host State and international oil corporation is governed by the concession agreement, production sharing contract; licence contract; service contract as the case may be. It is the agreements discussed in this Chapter which give efect to the master contract between Host State and international oil company. It is for this reason that governments oten seek to approve these ancillary contracts or require that OOGP companies disclose such contracts where relevant. Governments do not however signiicantly shape or inluence the contents of such contracts. 16 Introduction he ecological protection dimension of OOGP has emerged as an extremely important issue globally due to the localised, regional as well as globalised impacts of emissions associated with OOGP. here are many dimensions to the ecological aspects of OOGP and an enormous amount has been written. Each facet of the interaction between OOGP and environmental considerations is a scientiic-technical arena in its own right and has its own speciic policy, economic, societal and legal dimension. Chapter 6 narrows the focus and addresses the following issues: environmental management issues associated with the production and post-production phase of oil and gas ields; the environmental issues associated with ofshore oil and gas pipelines; issues in broad-scale environmental management of ofshore oil and gas regions; regulatory regimes in Ghana; contextual considerations of an economic, geographical and other character. Chapter 7 addresses the management of safety and security of the personnel and installations associated with ofshore industrial areas. It is conducted from the point of view of speciic platforms or facilities as well as from the point of view of the entire ofshore area. he task is made more diicult by the fact that the safety threat in OOGP is increased by more and more intensive multiple use of coastal space as well as the search for oil and gas resources in deeper waters. A closely related but distinct issue is that of the security of ofshore installations from intentional attacks or threats to their security. Chapter 7 addresses this issue in detail both internationally and with reference to Ghana. he monograph is completed by a Glossary providing guidance to all the technical aspects of this specialized ield. Introduction 17 Endnotes 1. his discussion draws from the following publications: Daniel Johnston, Current Developments in Production Sharing Contracts and International Petroleum Concerns 18 Petroleum Accounting and Financial Management Journal Fall 1999 48-66; Leanne Holmes, Sally L Mander and Brian S Fisher, Competitive access to Australian Gas Markets – Implications for Exploration and Development APPEA Journal 1994 862-871 especially at 862-864. 2. Tordo, 2009, 2. 3. Tordo, 2009, 1-2. 4. Tordo, 2007, 56. 5. From a production proile point of view, resources close to shore are in many cases well under production or less positively have already begun to show a decline curve (see Glossary). Ofshore provinces which are already seriously mature are the Gulf of Mexico (GOM) and the North Sea. 6. See for instance, Friends of the Earth International, Exxon ’s climate footprint - the contribution of exxonmobil to climate change since 1882 7. http://www.foe.co.uk/resource/reports/exxons_climate_footprint.pdf 8. Source: Behrenbruch, Source: Monash University, Development of Ofshore Oil and Gas Fields, 9 9. James B. Ramsey, Bidding and oil leases , Greenwich, Connecticut JAI Press, (1980), 7. 10. James B. Ramsey, Bidding and oil leases , Greenwich, Connecticut JAI Press, (1980), 7. 11. Paul Hallwood, Transaction costs and trade between multinational corporations: a study of ofshore oil production, Boston : Unwin Hyman, 1990, Chapter 4. 18 Introduction 2 2 PRODUCING OIL AND GAS1 TECHNICAL ASPECTS & REGULATORY IMPLICATIONS Producing Oil and Gas - Technical Aspects & Regulatory Implications 19 INTRODUCTION & OBJECTIVES OF CHAPTER As set out in Chapter 1, the discovery and exploitation of petroleum reservoirs/ields takes place in a number of phases, namely exploration, discovery, delineation, development, production by primary, secondary and tertiary means. Abandonment or decommissioning eventually follows2. Geological, engineering, technological and economic considerations are intermixed in decision-making within the enterprise and government arenas. In this Chapter the regulatory afairs analyst is provided with a basic overview of the geological, engineering and technological dimensions inluencing the recovery of hydrocarbons. Its overall objective is to give the reader a sound picture of the technical issues underlying the law, policy and regulatory matters discussed in the other parts of the book. Satter and hakur3 in a recent inluential book have described the matters discussed in this Chapter as essentially falling under the title “reservoir management”. hey argue this concept as set out in the graphic below more accurately describes contemporary approaches to the technical aspects of OOGP than previous terms such as reservoir engineering and ield engineering. Components of Reservoir Management Source: Satter and hakur, Integrated Petroleum Reservoir Management (1994), 2. Using this concept as a starting point, the Chapter explores the technical considerations, especially those of a scientiic-technical character which underlie reservoir management. It should be borne in mind that economic considerations play a major part in shaping the technical considerations. However detailed consideration of matters of economics and inance are let to Chapter 4. It can be stated at this stage though that the economic considerations which shape the various stages are: (1) the criteria of the particular operator and developer of the prospect; (2) the rules set out by the government as well as the expectations of that government; (3) the various models of economic returns examined by the operator; (4) analyzing the risks and uncertainties that apply. 20 Producing Oil and Gas - Technical Aspects & Regulatory Implications PRODUCTION PHASES IN OOGP: AN OVERVIEW he typical production sequence for an OOGP project is as follows: Source: Paul Hallwood, Transaction costs and trade between multinational corporations: a study of ofshore oil production, 1990, 31. OOGP: THE CORPORATE PERSPECTIVE Approached from the corporate or strategic management point perspective (but bearing in mind that this is a conceptualization only) the key features of the various stages of OOGP can be characterized as follows: Stage Phase 1 Pure Exploration Activity • During this phase data of a geological and geophysical sort are gathered and analysed to identify potential hydrocarbon accumulations as targets or prospects for exploration drilling . Judicious exploratory drilling also takes place Producing Oil and Gas - Technical Aspects & Regulatory Implications 21 Stage Phase 2 Discovery Activity • Petroleum deposit or ield is discovered and well-testing is undertaken Phase 3 – Appraisal and Delineation • he phase of petroleum operations that immediately follows suc cessful exploratory drilling. • During appraisal, delineation wells might be drilled to determine the size of the oil or gas ield and how to develop it most eiciently. • he objective is to appraise the commercial prosepectivity of the ield and delineate all its essential features. • A thorough appraisal by drilling concludes this phase but also lays the groundwork for the next phase which is the Development Phase • More discovery wells or less are drilled depending on various criteria including economic and corporate strategic criteria. • Data from Phase 1 may be completely discarded or signiicantly altered Phase 4 Development Phase • During this phase the ield is more fully deined by sinking a variety of wells and further testing these wells • he ield may be developed on the basis of (1) the appraisal drilling; (2) inancial and other considerations, especially the current and projected level of the oil price; (3) the overall strategy of the company in the context of the regulatory regime and government requirements and constraints • Production follows technical and economic appraisals of a reservoir • Production from a particular well is initiated by perforating the well casing. his involves lowering a device – perforating gun – down the Production casing until it is level with the producing formation, when the gun is Phase then ired. he special bullets used ly out sideways to form openings (primary, secthrough which crude oil can low from the reservoir into the well. ondary, tertiary • Production is undertaken using primary mechanisms or enhanced re+ transportacovery mechanisms tion and stor• Transport and storage of crude oil before reining occurs either near the age) location of the well/wells; at other gathering points. • Transportation is by pipeline or by shuttle tanker. Storage is either in storage tankers on site or near the site and increasingly also on the seabed itself pending further piping to other points Phase 5 Phase 6 Abandonment Or Decommissioning • Removal of production facilities and rehabilitation of all aspects of sites at the end of ield life (typically 10-25 years) • he methods used to decommission individual facilities are selected on a case-by-case basis. Wells are plugged with concrete; Floating installations are towed away, potentially to a new location for reuse and associated risers and seabed anchor points are removed. Similarly subsea manifolds are removed. Pipelines are considered for removal on a case-by-case basis. 22 Producing Oil and Gas - Technical Aspects & Regulatory Implications Another perspective on the process is ofered by the graphic below. he emphasis here is on grant of a licence to access resources by the government and the technological aspects – choice of platforms and facilities as well as their design and procurement. WHO DOES WHAT INSIDE THE CORPORATION? he key disciplines and professions involved in reservoir management are shown below: Components of Reservoir Management 2 Source: Satter and hakur, Integrated Petroleum Reservoir Management (1994), 13. In terms of practical activities and operations, the corporate aspect breaks down to this set of operations and activities: Producing Oil and Gas - Technical Aspects & Regulatory Implications 23 OOGP: Day to Day Activities and Operations4 Strategic management issues are dealt with in more detail in a later Chapter. As Chapter 1 has explained there is signiicant lexibility in how companies decide to undertake these transactions: contract, in house or through hybrid forms. EXPLORATION: BASIC GEOLOGICAL & GEOPHYSICAL CONSIDERATIONS The Petroleum System Concept5 he concept of a petroleum system is a meta-concept which seeks to describe the ensemble of geologic components and processes necessary to generate and store hydrocarbons in a given large-scale spatial situation. By deinition, a petroleum system must have a mature source rock from which the hydrocarbons emerge, migration pathway towards the reservoir rock, reservoir rocks to receive migrating petroleum and efective traps and seals to hold accumulations of petroleum. Petroleum systems theory and veriication tries to assess the relative timing with respect to diferent elements of a postulated system and the processes of generation, migration and accumulation within that system. he components and critical timing relationships of a petroleum system can be displayed in a chart that shows geologic time along the horizontal axis and the petroleum system elements along the vertical axis. Exploration plays and prospects are typically developed in basins or regions in which geologists and petrologists working at a meta-level argue that a complete petroleum system has some likelihood of existing. Basin A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin. 24 Producing Oil and Gas - Technical Aspects & Regulatory Implications Field An accumulation, pool, or group of pools of hydrocarbons or other mineral resources in the subsurface. A hydrocarbon ield consists of a reservoir in a shape that will trap hydrocarbons and that is covered by an impermeable, sealing rock. Typically, the term implies an economic size. he graphics below show (1) a ield containing both oil and gas; (2) a ield containing only gas. Oil and Gas Field Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Gas Only Field Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Reservoir A subsurface body of rock having suicient porosity and permeability to store and transmit luids. Sedimentary rocks are the most common reservoir rocks because they have more porosity than most igneous and metamorphic rocks and form under temperature conditions at which hydrocarbons can be preserved. A reservoir is a critical component of a complete petroleum system. Reservoir rock, cap rock and migration of petroleum Crude oil and natural gas are generally located within reservoir rock. Generally, unless halted by an obstacle the tendency of both oil and gas is to seep up towards the surface from the original source rock – primary migration - as shown in the two graphics below. However, in some situations a seal or cap rock layer overlies the reservoir rock creating a pocket in which the liquids and gases may accumulate. Producing Oil and Gas - Technical Aspects & Regulatory Implications 25 Upward Migration of Oil and Gas 1 Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Upward Migration of Oil and Gas 2 Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 26 Producing Oil and Gas - Technical Aspects & Regulatory Implications he most common cause of a pocket is where the reservoir rock is capped by impervious or impermeable rock known as seal or cap rock (see below). Analytical Diagram Oil and Gas Pockets Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Cap Rock Cap rock is an impermeable layer of clay or rock which lies above reservoir rock, reservoir rock being rock which contains petroleum and other luids. Buoyant, migrating luids remain trapped in the reservoir, held back by the cap rock unless deformation, drilling or erosion breaches the seal. Salt and shale commonly have excellent sealing properties. he task in OOGP is to ind cap rock which can be drilled through to release the petroleum sealed underneath. he more impervious a rock layer is, the more likely it is that a dry well will be the outcome of the drilling process. Source: Schlumberger Oilield Glossary Reservoir Rock Porosity his concept refers to the percentage of pore volume or void space within rock that can contain luids. Porosity comes either from the primary phase of formation of that rock (primary Producing Oil and Gas - Technical Aspects & Regulatory Implications 27 porosity) or from changes to the rock (secondary porosity). With primary porosity, the process of rock formation took a form such that grains within the rock ended up being incompletely compacted together, whilst with secondary porosity changes to the rock have occurred living signiicant pore spaces such as when feldspar grains or fossils are preferentially dissolved from sandstones. Efective porosity is the interconnected pore volume in a rock that contributes to luid low in a reservoir. It excludes isolated pores. Total porosity is the total void space in the rock whether or not such void space contributes to luid low. hus, efective porosity is typically less than total porosity. All these aspects need to be calculated and veriied at various stages in the OOGP process. Permeability his concept refers to the ability of a rock to transmit luid. Permeability is typically measured in darcies or millidarcies. he science and practice of petrology and for that matter OOGP is based signiicantly on the fact that rock formations which transmit luids readily tend to have many large, well-connected pores. Permeable rock is therefore an important building block for successful OOGP. In contrast, impermeable rock is rock that is incapable of transmitting luids because of low permeability. Shale has a high porosity and therefore easily contains hydrocarbons but it has a low permeability given that its pores tend to be iner grained or have a mixed grain size, with smaller, fewer, or less interconnected pores. Shale is thus oten found as a sealing rock (underneath) or cap rock (above) a reservoir. he prediction and ongoing assessment of permeability (using well-testing, modelling, laboratory analysis and extrapolation from other ields) is one of the most important tasks of exploration, ield delineation and ield development. Predictions of permeability are then veriied or disproven during the production phase. Absolute permeability is the measurement of permeability with respect to a single luid, or phase of hydrocarbon (oil, gas, condensate) within the rock. Efective permeability is the ability of rock to preferentially transmit a particular luid when other immiscible (non-mixing) luids are present in the reservoir (for example, efective permeability of gas in a gas-water reservoir). he relative saturations of the luids (extent to which they are cross-mixed with each other) as well as the nature of the reservoir afects efective permeability. Calculation of permeability is important since it allows for comparison of the diferent abilities of luids to low in the presence of each other given that the presence of more than one luid generally inhibits low. Trap Types O & G can be found trapped in a variety of combinations (oil and gas together; gas alone; other combinations) within diferent kinds of traps. here are many complex classiications of traps. In this Chapter, attention is paid to two broad categories which taken together are the most important: structural traps and stratigraphic traps. Structural traps are formed by signiicant geological upheavals. whilst stratigraphic traps are formed by discontinuities or changes in the characteristics of otherwise generally similar strata. Structural Traps he most common types of structural traps are anticlines, faults and domes whilst stratigraphic traps are formed by discontinuities or changes in the characteristics of otherwise generally similar strata. 28 Producing Oil and Gas - Technical Aspects & Regulatory Implications Anticlines An anticline is an arch-shaped fold in rock. Anticlines were formed by folding of the strata into a dome as the result of an upthrust from below. Anticlines provide an excellent trap with reservoir-quality rocks in their core and impermeable seals in the outer layers of the fold. he anticline was illed by an upward migration of luid movement through the porous strata until migration was halted by the cap rock. Anticline Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Faults A fault structure results from signiicant movement in the earth’s crust. Prior to the faulting, the various strata were continuous. he process of faulting shits the rock strata such that a porous bed holding hydrocarbons becomes sealed of by a non-permeable formation creating a fault based trap. Simple Fault6 Producing Oil and Gas - Technical Aspects & Regulatory Implications 29 Complex and Normal Faults7 Domes he Ekoisk oilield is a classic example of a salt dome reservoir. Ekoisk Salt Dome – North Sea – Norwegian Continental Shelf Source: Schlumberger Oilield Glossary 30 Producing Oil and Gas - Technical Aspects & Regulatory Implications he geology of salt domes is due to the relative buoyancy of salt when buried beneath other types of sediment. It lows upward to form structures which trap hydrocarbons due to (1) the abundance and variety of traps created by salt movement; (2) the association of salt with other minerals such as halite, gypsum and anhydrite limestone and dolostone that have excellent sealing capabilities due to their low porosity. he inter-relationship of salt dome, reservoir rock, hydrocarbon luids/phases, water and cap rock is shown below: Structure of a typical Salt Dome Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Stratigraphic Traps Stratigraphic traps manage to seal in oil because of diferences in rock strata. he hydrocarbon becomes trapped because Strata A is porous and peremeable whilst adjoining Strata B and C are either less porous or less permeable. It is this discontinuity or non-conformity within various related strata which provides the seal or trap. In the graphic immediately below, porous sand formations containing oil are surrounded by non-permable or signiicantly less permeable rock. Stratigraphic Trap 1 Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Producing Oil and Gas - Technical Aspects & Regulatory Implications 31 Stratigraphic Trap 2 - Limestone Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 EXPLORATION: OPERATIONS AND ACTIVITIES With these basic geological considerations explained it is now possible to discuss exploration as a distinct phase in OOGP. Exploration terminology refers to two terms: play and prospect. A prospect is an area of exploration in which hydrocarbons have been predicted to exist in economic quantity. A prospect is commonly an anomaly, such as a geologic structure or a seismic amplitude anomaly, that is recommended as a good site for drilling a well. Justiication for drilling a prospect is made by assembling evidence for an active petroleum system, or reasonable probability of encountering reservoir-quality rock, a trap of suicient size, adequate sealing rock, and appropriate conditions for generation and migration of hydrocarbons to ill the trap. A group of prospects of a similar nature constitutes a play. When the play or prospect is proved, a discovery has been made. he initial phase in petroleum exploration operations includes the generation of a prospect or play or both through surveys and interpretation of data supported by drilling of exploration wells. Viewed as a set of operations or activities, exploration consists of a number of interlinked and sequential stages, which involve increasing expenditure and decreasing risk: Activity Conceptual planning Operations Identiication of areas with possible O & G potential through literature searches and also through a review of available data from other companies or from governments. he process may be based on or linked to operator participation in a programme of promotion of prospective petroleum acreage and the bidding for such acreage8. Field-oriented his entails detailed further literature review and broad area visits or surveys planning with the purpose of selecting smaller targets for subsequent examination Reconnaissance his aspect examines selected areas and within these seek to identify smaller exploration targets for subsequent detailed examination. his phase comprises a variety of techniques: marine and airborne surveys, remote sensing, regional geochemical and geophysical surveys etc. Exploration Ater location of a speciic target area exploration drilling is undertaken drilling accompanied by initial testing of bulk samples. 32 Producing Oil and Gas - Technical Aspects & Regulatory Implications The Role of Geology and Geophysics As the previous discussion of technical aspects indicates both geology and geophysics (G & G) are central to exploration. Geology studies diferent earth formations and infers meaning from such study, whilst geophysics deals with the physics of the earth. G & G methods are of two types – surface and subsurface methods. Surface techniques search for evidence that oil and gas may have seeped to the surface or for indications that oil and gas bearing formations may be underground. Surface techniques include: geological mapping, aerial photography, remote sensing, radiation sensing and topographical mapping. Subsurface methods include magnetic surveys, gravity survey and seismic surveys. Geophysical methods include gravimetric surveys deducing information from changes in gravity at various points of interest, whilst magnetic and seismic surveys measure diferences in rock formation based on magnetic readings and sound readings respectively. Highly specialised drilling known as core hole or slim hole drilling also produces geological information. Whereas previously, surface methods such as searching for areas of seepage was the most common method, today complex subsurface maps of diferent types would typically be undertaken to produce a composite proile. Subsurface map approaches that are important are: structural maps, cross-section maps and isopach maps. Structural maps provide a picture of the subsurface contour proile, with seismographic surveys being a key method of generating such maps. Mapping by cross-section is also important where the ield structure is complicated. Typically in the past, cross-section mapping was achieved through the drilling of numerous wells. Today geophysics combines with computer simulation to provide cross-sectional views. OOGP is currently characterized by increasing attention to deepwater exploration or deepwater plays, namely exploration activity located in ofshore areas where water depths exceed approximately 200 meters the approximate water depth at the edge of the continental shelf. While deep-water reservoir targets are geologically similar to reservoirs drilled both in shallower water depths as well as onshore, the logistics of producing hydrocarbons from reservoirs located below such water depths presents a considerable technical challenge. Marine Seismic Survey Source: Schlumberger Oilield Glossary Producing Oil and Gas - Technical Aspects & Regulatory Implications 33 DISCOVERY & PRELIMINARY APPRAISAL Appraisal wells If a hydrocarbon bearing reservoir is discovered during exploration drilling, one or more appraisal wells may be drilled. Appraisal wells are used to delineate the physical dimensions of the ield and calculate its development potential. Such information is important in determining: • whether it would be economically viable to develop the ield • likely hydrocarbon production rates • appropriate process and export facilities Most appraisal wells would normally include extensive logging and involve a well test. Because of the cost, as few appraisal wells as possible would be drilled, the actual number being dependent on the particular circumstances of the ield. Some appraisal wells are drilled as future potential production wells and suspended following completion for future. Well Testing during Exploration Well testing during exploration is concerned with acquiring information about relationships and broad characteristics with respect to the reservoir. To acquire this information, wells are tested by simulating production for a limited period to measure pressures and low rates and take samples of well luids (well test or drill stem test). Well luids are processed on the rig to provide information on the relative proportions of gas, oil and water. he hydrocarbons produced during a well test are either burned in a high eiciency burner or in the case of oil produced during extended well tests, contained typically in a specialist storage vessel for transport to shore for treatment. FIELD DEVELOPMENT: OPERATIONS AND ACTIVITIES Development as a phase in petroleum operations refers to the stage of much more systematic and less speculative activity which occurs ater exploration has proven successful, but before full-scale production. Production by contrast is the period during which hydrocarbons are drained from an oil or gas ield. It may last anywhere from 10-40- years. Development involves highly focused appraisal work and scenario building together with the generation of a plan to fully and eiciently exploit the ield – the ield development plan. here is typically an initial more general feasibility study and if this is approved, a much more detailed ield development plan. Additional wells are also usually drilled. Field development may last 1-3 years. It is during the development phase that maximum capital expenditure (CAPEX) occurs. By contrast, once production is in motion, the major item of expenditure is operating expenditure (OPEX). Diferentiating expenditure types is one of the ways of distinguishing the development phase from the production phase. It is also during the development phase that the type of production facility to be used is chosen and tested and choices are made as to what forms of recovery will be used. Typically most governments will want to approve the transition from exploration to development and thence to production. Options fro extraction of hydrocarbons evaluated during the development phase are many and complex as the chart below shows: 34 Producing Oil and Gas - Technical Aspects & Regulatory Implications Extraction/Recovery Option Source: Satter and hakur, Integrated Reservoir Management, 172. Estimating Recovery Factors In deciding to develop a ield, an operator must estimate how much oil and gas will be recovered and how easily this will be produced. Although the volume of oil and gas in place can be estimated from the volume of the reservoir, its porosity, and the amount of oil or gas in the pore spaces, only a proportion of this amount will be fully recovered. he amount recovered - the recovery factor - is economically critical both to the operator and to the government. he recovery factor is determined by various factors such as reservoir dimensions, pressure, the nature of the hydrocarbon, and the development plan. Appendix 1 provides a more detailed idea of the information considerations underlying estimation of the recovery factor. Generating a Field Development Plan Generating a Field Development Plan is a highly complicated process involving co-ordination of the work of multi-disciplinary teams concerned with the following key issues: Issues9 Data on initial conditions Data Type • Depth data • Pressure data • Temperature data • Data on rock formations • Fluid contact characteristics • Water salinity • Estimated initial hydrocarbon in place Formation and rock properties • • • • Area Gross thickness – gas, oil etc. Porosity Hydrocarbon saturation – gas in oil; gas in water; oil in water? Producing Oil and Gas - Technical Aspects & Regulatory Implications 35 Issues9 Fluid properties – initial conditions Data Type • Relative density of oil • Oil viscosity • Oil compressibility • Ratio of gas to oil • Gas expansion factor • Extent of oil within formation • Gas viscosity • Water viscosity Recovery aspects • • • • • • Main drive mechanism to be used Size of the water aquifer Microscopic sweep eiciency Volumetric sweep eiciency Formation permeability Oil in place Satter and hakur10 describe what must be integrated particularly well, whilst a further and more speciic perspective on the content and inputs into ield development planning is ofered by Behrenbruch in the graphic Field Development Planning11: Integrated approach to Field Development Source: Satter and hakur, Integrated Reservoir Management, (1994) 21 36 Producing Oil and Gas - Technical Aspects & Regulatory Implications Field Development Planning he Behrenbruch/BHP chart below provides further explanation of the elements of ield development: Producing Oil and Gas - Technical Aspects & Regulatory Implications 37 Inputs into the Field Development Plan: 12 38 Producing Oil and Gas - Technical Aspects & Regulatory Implications FIELD DELINEATION An early as well as ongoing aspect of ield development is using a mixture of wells to delineate the extent of the ield. he graphics below provide a conceptual picture supported by an example from the North Sea: Field Delineation 1: Conceptual13 Key D – Discovery Well B, C, E & F – Development Wells A & G – Dry holes delineating the ield Producing Oil and Gas - Technical Aspects & Regulatory Implications 39 Field Delineation: North Sea Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 FIELD DEVELOPMENT: GEOLOGICAL, GEOPHYSICAL AND GEO-CHEMICAL DRIVERS Hydrocarbon & Water Relationships In A Reservoir A particularly crucial issue in OOGP is the inter-relationship between gas, oil and water, the key luids in a reservoir since these substances are almost always found together. he inter-relationship is crucial for deciding (1) what approach is to be taken to initially develop the reservoir; (2) what approach is to be taken to enhance reservoir exploitation given that ater a period of extraction, the rate at the hydrocarbon can be extracted starts to decline – the decline curve problem (see Glossary). he issue then is to determine how the various substances (oil-gas-water) are in contact with each other throughout the reservoir and the particular ields to be exploited and whether the inter-relationship can be exploited to approach extraction of hydrocarbon in diferent ways. Physical Aspects of the Relationship Since oil loats on water and gas is lighter than either oil or water, the oil and gas in a given accumulation are found at the top with the water (aquifer) underneath. Another aspect of the relationship is that both oil and gas are merely hydrocarbon phases meaning that given the right conditions, transformation of oil into gas occurs and vice-versa. he intermediate phase – condensate is sometimes also the form in which hydrocarbons are found in a reservoir. he Oil-Gas Water Relationship Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 40 Producing Oil and Gas - Technical Aspects & Regulatory Implications he Hydrocarbon Phase Concept14 At a particular temperature solids – condensate melts into liquid and at particular pressures, the gaseous phase may occur. Manipulation of this relationship is important for extraction as well as reining but can also create signiicant problems for both processes. Conceptualising Fluid Contacts in a Reservoir he term luid contact refers to the interface that separates luids of diferent densities in a reservoir. Horizontal contacts are the norm, although tilted contacts occur in some reservoirs. It should also be noted that although conceptualization may suggest a sharp break, the reality is that contact between luids is usually gradual rather than sharp, forming a transition zone of mixed luid. A mixed-luid reservoir will stratify according to luid density, with gas at the top, oil in the middle, and water below. Production of luids oten perturbs the luid contacts in a reservoir. he basic elements as found in a typical oilield are as follows: Gas-oil-water contact 115 Source: Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 22 Producing Oil and Gas - Technical Aspects & Regulatory Implications 41 he irst aspect to understanding the GOW relationship is the concept of the Gas cap. his refers to gas that accumulates in the upper portions of a reservoir where the pressure, temperature and luid characteristics are conducive to free gas. he energy provided by the naturally occurring expansion of the gas cap as oil is removed provides the primary drive mechanism for oil recovery in many circumstances. here are many types of GOW contact relationships. All of these relationships ofer a variety of opportunities for recovery of hydrocarbons whilst imposing their own constraints. Diferent engineering approaches are used to respond to these situations. Gas-water contact A boundary zone in a reservoir above which predominantly gas occurs and below which predominantly water occurs. Gas and water are somewhat miscible (mix) so the contact between gas and water is not necessarily sharp and there is typically a transition zone between 100% gas and 100% water in reservoirs. Fluid Contact Types Fluid Contact Types Source: Schlumberger Oilield Glossary 42 Producing Oil and Gas - Technical Aspects & Regulatory Implications Gas-oil contact A boundary zone in a reservoir above which predominantly gas occurs and below which predominantly oil occurs. Gas and oil are miscible, so the contact between gas and oil is transitional, forming a zone containing a mix of gas and oil. Oil-water contact A boundary region in a reservoir above which predominantly oil occurs and below which predominantly water occurs. Although oil and water are immiscible, the contact between oil and water is commonly a transition zone and there is usually irreducible water adsorbed by the grains in the rock and immovable oil that cannot be produced. he oil-water contact is not always a lat horizontal surface, but instead might be tilted or irregular. Engineering Responses to Contact Types here are many engineering responses to these contact types as shown below: Gas-oil-water contact 116 Gas-oil-water contact 217 Producing Oil and Gas - Technical Aspects & Regulatory Implications 43 PRODUCTION: OPERATIONS AND ACTIVITIES Production takes place over a period of 10-40 years typically. he range of issues involved in production are captured by the graphic below which covers the technical aspects as well as the environmental impacts of production operations. 44 Producing Oil and Gas - Technical Aspects & Regulatory Implications PRODUCTION – GEOLOGICAL AND GEOPHYSICAL ASPECTS The Role of Pressure Essentially an oil well is the introduction of a low pressure system into ields of varying pressures with the outlow of oil and gas up the well exploiting various aspects of geophysics. he fundamental principle is that gas, oil and water respond in diferent ways once a low pressure system – the well - is introduced into the reservoir: gas expands downwards, water moves upwards and oil responds to these two external pressures in diferent ways all of which can be manipulated by reservoir engineering to assist with extraction of oil in both conventional and enhanced recovery modes provided the reservoir is properly understood. Pressures within a Petroleum Field Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Diferential Response to Pressure: Gas Oil and Water Source: Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996 Producing Oil and Gas - Technical Aspects & Regulatory Implications 45 Wells, Pressure and Recovery of Reservoir Fluids Wells drilled into the diferent strata in diferent combinations shape recovery of oil. Of the luid lows set out in the graphic below, only one situation is of no use to petroleum extraction, the drilling of a well which makes contact with the oil-water transition zone such that water mixed with oil is drawn to the surface. his is a situation known as coning and is to be avoided. Leaving situations of coning aside, wells driven into diferent parts of the reservoir provide: • crude oil as the extracted natural resource. • gas for various processes together with gas as the extracted natural resource; • water for various processes, and also crude oil as the extracted natural resource. Wells and the G-O-W Interface18 Making Use of Pre-existing Field Pressures: Natural Drive Mechanisms A reservoir which is producing oil using the pressure relationships within it is said to be using natural drive mechanisms and is in efect exploiting the relationships shown in the graphics immediately above – feeding on the natural energy of the ield. Natural drive mechanisms are of three types: water drive, solution gas drive and gas cap drive. Water Drive his mechanism is used where the aquifer or water-bearing part of the structure is as porous and permeable as the oil-bearing part. he water therefore lows into the oil bearing part, pushing the oil upwards as more oil is extracted – the greater the removal of oil and thus the reduction of previous pressure on the water, the more water drives the oil upwards. As the reservoir depletes, the water moving in from the aquifer below displaces the oil until the natural energy or drive of the water is expended or the well eventually produces too much water to be viable – the coning problem. 46 Producing Oil and Gas - Technical Aspects & Regulatory Implications Water Drive Mechanism19 Water-drive reservoirs can have bottom-water drive or edge-water drive. In a bottom waterdrive reservoir, water is located beneath the oil accumulation (see above) while in an edgewater-drive reservoir, water is located only on the edges of the reservoir. Solution Gas Drive his primary recovery mechanism depends on there being a high level of gas in solution in the oil in the reservoir. It requires manipulation of pressure levels, including the initial extraction of oil until the gas breaks out of its oil solution to drive the oil extraction process. Gas breaks out of an oil solution at a certain pressure – see graphic above. he engineering task is to create the saturation pressure point at which a phase change occurs and gas breaks out of the oil. he gas that has escaped then expands and as it does so displaces oil from the rock pores and eventually both gas and oil pass together into the producing wells. his method requires a very high level of regulation by reservoir engineers. Solution Gas Drive Mechanism20 Producing Oil and Gas - Technical Aspects & Regulatory Implications 47 Gas Cap Drive With this method, crude oil extraction is assisted naturally by expansion of the gas cap (the free gas sitting above the oil – see graphics above) downwards into the space previously occupied by the oil that has been extracted. he oil let in the reservoir is then displaced downward into the producing well by the expanding gas cap. he gas cap is sometimes exploded downwards by reservoir engineers. Again a very high level of regulation by reservoir engineer s is needed to maintain the right inter-relationship between gas and oil. Gravity Drainage his the least common primary recovery mechanism in which the force of gravity pushes hydrocarbons out of the reservoir, into the wellbore and up to the surface. Gravity force is always present in the reservoir, but its efect is greater in thick gas-condensate reservoirs and in shallow, highly permeable, steeply dipping reservoirs. Pressure & Production Decline Once cap rock has been breached and production has begun, over time the pressure naturally declines. Oil and gas low also declines with pressure decline, a process which is charted through continued plotting and monitoring of the so-called decline curve. In theory, once the internal pressure of the reservoir is equalized with the surface pressure (see graphic above) no oil or gas will low naturally. Before this point is reached however and subject to economic considerations, various forms of artiicial assistance to improve luid and gaseous low are applied – this is the concept of secondary and tertiary or enhanced recovery addressed in more detail below. he point at which enhanced recovery should be applied is determined in part by the information provided by the decline curve and also economic factors such as the current oil price and government policy. SECONDARY RECOVERY MECHANISMS Secondary mechanisms involve the injection of water or gas associated with the reservoir into the reservoir to supplement the natural drive mechanisms described above. he secondary intervention displaces the function of the naturally occurring water or gas forcing out oil which would otherwise never have been recovered. Water injection is a common form of secondary recovery and involves injecting water under pressure into the reservoir by means of injection wells drilled below the oil/water level. Gas lit is another form of secondary recovery in which provided suicient gas is available, it is injected into the reservoir using wells drilled into the gas cap. Engineering procedures are used to generate the levels of pressure which will make this injected gas efective as a drive mechanism. Sub-surface pumping is the last most common method and involves lowering a pump into the well to continue pumping the oil. ENHANCED RECOVERY MECHANISMS21 his is the third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Enhanced oil recovery can begin ater a secondary recovery process or can be used at any time during the productive life of an oil reservoir. Its purpose is not only to restore formation pressure, but also to improve oil displacement or luid low in the reservoir. he three major types of enhanced oil recovery operations are: 48 Producing Oil and Gas - Technical Aspects & Regulatory Implications • thermal recovery (steamlood or in-situ combustion); • chemical looding (alkaline looding or micellar-polymer looding); • using gases which are oil-miscible (can mix with oil)(eg. carbon dioxide; hydrocarbon gases) to achieve displacement of the oil . he optimal application of each type depends on reservoir temperature, pressure, depth, net pay, permeability, residual oil and water saturations, porosity and luid properties such as oil API gravity and viscosity. Methods of Oil Recovery Source: Satter and hakur, Integrated Reservoir Management, 172. Injection wells he principal instrument for efecting EOR is through a network of injection wells. With wells deployed in simple or complex patterns as shown by the graphics below. Gas injection operates through the use of gas separated from production wells (see graphics below) or possibly via imported gas which may be re-injected into the upper gas section of the reservoir. Water-injection wells are common ofshore, where iltered and treated seawater is injected into a lower water-bearing section of the reservoir. Producing Oil and Gas - Technical Aspects & Regulatory Implications 49 Injection Wells & Production Wells 1 Source: Monash University, Development of Ofshore Oil and Gas Fields, 31 Injection Wells & Production Wells 2 Source: Satter and hakur Integrated Reservoir Management, 235 Thermal recovery22 his category of EOR involves injecting heat into a reservoir. During thermal recovery, crude oil undergoes physical and chemical changes because of the efects of the heat supplied. Physical properties such as viscosity, speciic gravity and interfacial tension are altered. he chemical changes involve diferent reactions such as cracking, which is the destruction of carbon-carbon bonds to generate lower molecular weight compounds, and dehydrogenation, which is the rupture of carbon-hydrogen bonds.hermal recovery is used to produce viscous, thick oils with API gravities less than 20. hese oils cannot low unless they are heated and their viscosity is reduced enough to allow low toward producing wells. hermal recovery is a major branch of enhanced oil recovery processes and can be subdivided in two types: hot luid injection such as steam injection (steamlood or cyclic steam injection) and hot waterlooding and in-situ combustion processes. 50 Producing Oil and Gas - Technical Aspects & Regulatory Implications Steamlood23 his EOR technique involves injecting steam generated at the surface into the reservoir through specially distributed injection wells. When steam enters the reservoir, it heats up the crude oil and reduces its viscosity. he heat also distills light components of the crude oil, which condense in the oil bank ahead of the steam front, further reducing the oil viscosity. he hot water that condenses from the steam and the steam itself combine to generate an artiicial drive that sweeps oil toward producing wells. Another contributing factor that enhances oil production during steam injection is related to the cleansing efect of the heat as it helps eliminate residues such as parains or asphaltenes that may have been deposited during cold production. Steamlooding is also called continuous steam injection or steam drive. Hot waterlooding24 his technique involves injecting hot water into a reservoir through specially distributed injection wells. Hot waterlooding reduces the viscosity of the crude oil, allowing it to move more easily toward production wells. Hot waterlooding, also known as hot water injection, is typically less efective than a steam-injection process because water has lower heat content than steam. Nevertheless, it is preferable under certain conditions such as when the formation rock has a high sensitivity to fresh water, making this approach more efective. In-situ combustion25 A method of thermal recovery in which ire is generated inside the reservoir by injecting a gas containing oxygen, such as air. A special heater in the well ignites the oil in the reservoir and starts a ire. he heat generated by burning the heavy hydrocarbons in place produces hydrocarbon cracking, vaporization of light hydrocarbons and reservoir water in addition to the deposition of heavier hydrocarbons known as coke. As the ire moves, the burning front pushes ahead a mixture of hot combustion gases, steam and hot water, which in turn reduces oil viscosity and displaces oil toward production wells. Additionally, the light hydrocarbons and the steam move ahead of the burning front, condensing into liquids, which adds the advantages of miscible displacement and hot waterlooding. In-situ combustion is also known as ire looding or irelood. Cyclic steam injection26 A method of thermal recovery in which steam generated at the surface is injected into a well and the same well is subsequently put back into production. A cyclic steam injection process includes three stages. he irst stage is injection, during which a slug of steam is introduced to the reservoir. he second stage, the soak period, requires that the well be shut in for several days to allow uniform heat distribution to thin the oil. Finally, during the third stage, the thinned oil is produced through the same well. he cycle is repeated as long as the oil production is proitable. Cyclic steam injection is used extensively in heavy-oil reservoirs, tar sands, and in some cases to improve injectivity prior to steamlood or in-situ combustion operations. Cyclic steam injection is also called steam soak or the huf ‘n’ puf (slang) method. Gas Injection his is an EOR method that uses a variety of injected gases such as carbon dioxide, nitrogen, or complex mixtures of production associated gases. In most cases, a ield will incorporate a planned distribution of gas-injection wells to maintain reservoir pressure and efect an eicient Producing Oil and Gas - Technical Aspects & Regulatory Implications 51 sweep of recoverable liquids. he diference between gas-injection as a secondary or third stage recovery method is the complexity of the procedures. he Gas Injection Concept Source: Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Gas Injection Types Source: Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Chemical Flooding27 A general term for injection processes that use special chemical solutions to change the form in which hydrocarbons are present in the reservoir. Some substances reduce surface tension between oil and water in the reservoir, whilst are employed to improve the eiciency with hydrocarbons move. hese chemical solutions are pumped through specially distributed injection wells to mobilize oil let behind ater primary or secondary recovery. Chemical looding is a major component of enhanced oil recovery processes and can be subdivided into micellar-polymer looding and alkaline looding. he general procedure of a chemical looding includes a prelush (low-salinity water), the injection of the chemical solution (micellar or alkaline), the 52 Producing Oil and Gas - Technical Aspects & Regulatory Implications addition of a mobility bufer and, inally, a driving luid (water), which displaces the chemicals and the resulting oil and pushes it towards the entrance to the production wells. WELLS AND DRILLING During all the stages of OOGP wells are central to the enterprise. he basic features of a well are shown below. he Hartley-Anderson publication (see Book of Materials) explains wells and drilling in more detail. Basic features of a Drilling and Production Apparatus EXPLORATION FACILITIES Exploration wells are almost invariably drilled from mobile drilling rigs. Exploration rigs are self-contained with their own power generation, utilities and accommodation facilities. Supplies are brought to the rig and wastes returned to shore by supply boat. Crew are transferred on and of the rig by helicopter. For safety reasons, a stand by vessel is deployed in the ield for the duration of the drilling programme. Exploration rigs are basically of three types: jackup rigs; semi-submersible rigs and drillships. Jackup rig A self-contained combination drilling rig and loating barge, itted with long support legs that can be raised or lowered independently of each other. he jackup, as it is known informally, is towed onto location with its legs up and the barge section loating on the water. Upon arrival at the drilling location, the legs are jacked down onto the sealoor, preloaded to securely drive them into the seabottom, and then all three legs are jacked further down. Since the legs have been preloaded and will not penetrate the sealoor further, this jacking down of the legs has the efect of raising the jacking mechanism, which is attached to the barge and drilling package. In this manner, the entire barge and drilling structure are slowly raised above the water to a predetermined height above the water, so that wave, tidal and current loading acts only on the relatively small legs and not the bulky barge and drilling package. Producing Oil and Gas - Technical Aspects & Regulatory Implications 53 Semi-submersible rigs his is a particular type of loating vessel that is supported primarily on large pontoon-like structures submerged below the sea surface. he operating decks are elevated perhaps 100 or more feet above the pontoons on large steel columns. he pontoons contain ballast tanks, and the height of the deck above the sea surface can be altered by pumping ballast (sea) water in or out of the pontoons. his design has the advantage of submerging most of the area of components in contact with the sea and minimizing loading from waves and wind. Semisubmersibles can operate in a wide range of water depths, including deep water. hey are usually anchored with six to twelve anchor chains, which are computer controlled to maintain station keeping. Semisubmersibles can be used for drilling, workover operations, and production platforms, depending on the equipment with which they are equipped. Drill-ships Drill ships are based on a conventional ship’s hull adapted with a moon pool to allow the deployment of the drill though the hull. hey typically have their own motive power and are not dependent on tugs, maintaining position with DP and/or anchors. Drill-ships can operate in deep water and are the platform from which the academic Ocean Drilling Programme28 is conducted. However because of the hull shape, they are more afected by wind and wave movement than semi-submersible rigs, and as a consequence would be more likely to sufer from weather down time. Examples – Exploration Platforms 54 Producing Oil and Gas - Technical Aspects & Regulatory Implications PRODUCTION PLATFORMS29 Production platforms are of three broad types: ixed; loating/lexible; and subsea. Floating platforms are either vessels or a hybrid form of ixed platform and can be removed once work is completed, responding well to the current environmental pressure to properly decommission ields once production has been completed. Fixed platforms are thus the main target of current decommissioning eforts as discussed in later Chapters. Fixed Platforms: Steel Jacket structures30 he irst type ot production platform dating back to the 19th century and still in wide use today. Source: “Introduction to Ofshore Structures” at http://www.swan.ac.uk/civeng/Research/ ofshore/introto/ofstruct.htm; he principal structural components are (1) the jacket - a three-dimensional space-frame made from large tubular steel members; (2) the piles; and (3) the deck. he jacket is pre-fabricated on shore. It is transported to the site and is then seated on the seabed. he piles are then driven through sleeves in the jacket and are then connected to the sleeves. he deck is then inserted. he jacket is designed to respond to and carry the loads generated by activity on the deck as well as the stresses generated by the marine environment. In particular, the structure must be able to resist those hydrodynamic forces which might cause overturning. Seabed soil conditions and rough weather limit the use of the jacket platform to shallower waters. he outer limit for steel jackets is depths of 450 metres. Producing Oil and Gas - Technical Aspects & Regulatory Implications 55 Fixed Platforms: Concrete gravity structures his platform type consists of the concrete base built into the sealoor and transferring its load into the seabed utilising complex gravitational principles – hence the name. Source: “Introduction to Ofshore Structures” at http://www.swan.ac.uk/ civeng/Research/ofshore/introto/ofstruct. htm; he pre-fabricated concrete pillars are built onshore at a site which has towing access to the sea bed or in shallow water. hese pillars are then transferred to the deepwater site and installed by looding the ballast tanks which allowed it to be loated to the site in the irst place. he pillars are held down on the seabed by a variety of other structures, including steel structures. However the solidity of the core structure – the caisson – ensures that the pillars sit irmly on the seabed almost like a pad, thereby preventing overturning. he production platform is then installed on top of the concrete pillars. Concrete gravity structures have the advantage that they can be used when the seabed conditions are not suitable for piling. he large cellular base may also be used as a storage facility for recovered oil or gas.n Concrete gravity platforms have been used in waters up to 350 metres. Flexible Platforms: Tension-leg structures Tension-leg platforms are loating structures, ballasted and anchored by tensioned steel tendons to templates driven (piled into the seabed. Source: “Introduction to Ofshore Structures” at http:// www.swan.ac.uk/civeng/Research/offshore/introto/ ofstruct.htm; TLPs are relatively stable and can operate in a wide range of waters including the deepest waters in which OOGP occurs (for example up to 2100 metres). 56 Producing Oil and Gas - Technical Aspects & Regulatory Implications Flexible Platforms: FPS/FPSO his type of production system is ballasted and anchored to the seabed. It can accommodate vertical movement and can be operated in diverse conditions, including signiicant depths. Because of its relatively lower cost, it can be used to exploit marginal ields. It is also common for FPSO/FPS to be linked with sub-sea completions. Subsea Systems Subsea systems are completely automated systems comprising manifolds and pipes which are attached to a main facility. hey are used to produce from remote parts of the reservoir or more economically marginal locations. A comparative perspective on these production facilities is provided below: Source: DTI, An Overview of Ofshore Oil and Gas Exploration and Production, August 2001, 17. PIPELINES & FLOWLINES31 Pipelines are the systems of tubes used for transporting crude oil, natural gas and other luids or gaseous substances associated with OOGP. Pipelines are critical to the oil and gas industry both onshore and ofshore. here are two types of pipelines – those for transportation of luid and gases from and to ofshore ields (water, petroleum, gas slurries, eluents) - ofshore gathering pipelines - and those for distribution of product for sale over long distances known as trunklines. he comments made here refer to ofshore gathering pipelines although much of what is said here may be applicable to trunklines as well. Pipelines are built by welding individual steel pipes and/or pipes made from other materials such as plastics into a continuous line followed by various forms of coating to protect against corrosion. Pipelines may also be coated inside. he pipeline is then submerged in water and lowered onto the seabed. Pipelines and lowlines ofshore are used for transporting crude oil and gas from producing wells to crude oil terminals or gasplants; for supplying water to be used for injection and re-injection and also gas for use in gas injection. Pipeline routes are planned to be as short as possible. Slopes that could put stress on unsupported pipe are avoided and seabed sediments are mapped to identify unstable areas and to see if it will be possible to bury the pipe. Producing Oil and Gas - Technical Aspects & Regulatory Implications 57 Pipeline structure Key: 1. internal coating; 2 steel pipe; 3. external corrosion coating; 4. concrete coating Laying of Pipelines32 here are a variety of methods for laying pipelines as shown in more detail immediately below: Considerations in pipeline design and installation33 he principal considerations are: • Inner diameter – of consequence for the transport capacity of the pipeline • Wall thickness of steel pipe to deal with loads and pressures during installation, initial testing and operation of the pipeline as well as accidents • Submerged weight to address stability once the pipe is in place • Coating to protect against impacts, corrosion and abrasion • Soil stability Trenching of Pipelines34 Pipelines may be trenched, that is lowered below the seabed level. Trenching is intended to provide additional protection against: • Pressures and stresses from the water environment • Impacts form ishing gear and dropped objects • he hooking of pipelines by ship anchors 58 Producing Oil and Gas - Technical Aspects & Regulatory Implications Trenching can be done before the pipeline is laid, in which case the pipeline is laid in the gutter dug in the seabed, whilst post-pipeline trenching involves excavation and lowering of the pipeline. he method used depends on soil integrity issues principally and the regulatory regime operative in the particular zone. Pressures and stresses from the water environment he sources of water pressure are steady currents, long perid currents and short period currents. Steady currents are currents which move in one direction only either for months or years. Whilst the strength of a steady current varies, its direction does not. Design and laying would thus need to take these features into consideration. Long period currents refers to changes which are quite signiicant and which occur over periods of hours or days. he principal cause of change is tidal movements, although they can also be caused by storms. Short period pressures are caused by wind, waves and swell. Fishing Gear Accidents35 his type of pipeline accident tends to be either very high in its occurrence or very low depending on the intensity of use of the seabed area by ishing interests. hus in the North Sea for instance, ishing gear passes over pipelines over 40,000 times a year he main source of harm are diferent types of trawl. Impact of Fishing Gear on Pipelines 136 Otter Trawl Key: 1. Trawl doors; 2 – bobbings; 3 – ishing net; 4 sweepline; 5 – pipeline; 6 – warp Producing Oil and Gas - Technical Aspects & Regulatory Implications 59 Impact of Fishing Gear on Pipelines 2 – Beam Door on Pipeline Key: 1. sweep line attached to net of trawl; 2. beam door of trawl; 3. connecting lines to ishing vessel; fwp – pipeline in path of trawl equipment and doors Ship anchor Problems37 Ship anchor problems generally occur in shallow water, ship routeing or traic zone regions or in port zones. OOGP marine vessels are also major sources of accidents, although the accidents themselves are very rare. Anchor Impacts on Pipeline DECOMMISSIONING his is the inal stage in the OOGP process. It is discussed in more detail in the later Chapter on Environmental issues. he range of issues on which decisions have to be made is however neatly summarized in the graphic set out at Appendix II to this Chapter. SUMMARY his Chapter has provided a basic account of the technical factors associated with OOGP which shape both corporate strategy as well as regulatory response. It has discussed a very broad range of issues in fairly non-technical terms: introducing the reader to the key issues in OOGP, including the nature of the reservoir (rock types, traps, luids and gases) the location of the ield and the reservoir and integrated and structured ways of analyzing and understanding OOGP. 60 Producing Oil and Gas - Technical Aspects & Regulatory Implications REFERENCES Extended Glossary – Chapter 8 DTI, An Overview of Ofshore Oil and Gas Exploration and Production, August 2001 Millheim, A Vision for Drilling APPEA Journal 1995 43-49 Wright and le Poidevin, Development Options for Ofshore Oil and Gas Fields: Implications for Optimum Long-Term Recovery 391-397 APPEA Journal 1992 Behrenbruch Major Facilities Options for Ofshore Petroleum Developments – Considerations and Requirements Ofshore Oil Field Development Planning: Project Feasibility and Key Considerations Schlumbergers Oilield Glossary at http://www.glossary.oilield.slb.com/;( a highly useful reference source – but not essential). Producing Oil and Gas - Technical Aspects & Regulatory Implications 61 Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. he discussion in this Chapter draws from the following sources: DTI, An Overview of Ofshore Oil and Gas Exploration and Production, August 2001; Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme; Abdus Satter and Ganesh hakur, Integrated Petroleum Reservoir Management (1994) 1-25; Brock, Klingstedt and Jones, Accounting for Oil and Gas Producing Companies (1981) 92-93; Paul Stevens, Oil and Gas Dictionary (1983); Schlumberger Oilield Glossary at http://www.glossary.oilield.slb.com/; Petroleum Extension Service, University of Texas, A Dictionary for the Petroleum Industry, 1st edition. Austin, Texas, USA 1991; Hyne NJ, Dictionary of Petroleum Exploration, Drilling And Production. Tulsa, Oklahoma, USA: PennWell Publishing Co. Inc., 1991; Langenkamp RD, Handbook of Oil Industry Terms and Phrases, 5th Edition. Tulsa, Oklahoma, USA: PennWell Publishing Co. Inc., 1994; Langenkamp RD, Illustrated Petroleum Reference Dictionary, 4th Edition. Tulsa, Oklahoma, USA: PennWell Publishing Co. Inc., 1994; McCain WD Jr., he Properties of Petroleum Fluids, second edition. Tulsa, Oklahoma, USA: PennWell Publishing Co. Inc., 1990; Bank of Scotland, Oil and Gas Handbook, 4th edition. Edinburgh, Scotland: 1996. Decommissioning is discussed in detail in the later Chapter addressing Environmental Management. Abdus Satter and Ganesh hakur, Integrated Petroleum Reservoir Management (1994) Source: Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, 43 See generally, Magoon LB (ed): he Petroleum System–Status of Research and Methods, Washington, DC, USA: US Government Printing Oice, 1992. Source: Brock, Klingstedt and Jones Accounting for Oil and Gas Producing Companies (1981) 92-93 Source: Sclumberger Oilield Glossary at http://www.glossary.oilield.slb.com/; See for example, the Australian programme of promotionof petroleum prospective areas to be found at: http://www.ga.gov.au/oceans/projects/20010917_30.jsp Monash, 1991, 5-58 See Satter and hakur, Integrated Reservoir Management, (1994) 21 Behrenbruch, Subsurface Development Planning in Monash, 1991, Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 17 Behrenbruch, , Subsurface Development Planning in Monash, 1991, Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 12 Source: Adapted from Brock et. al. Accounting for Oil and Gas Producing Companies, (1981) 183. Schlumberger Oilield Glossary at http://www.glossary.oilield.slb.com/; Petroleum Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 46. Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 46 Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 46 Monash University, Development of Ofshore Oil and Gas Fields, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme, 126. Schlumberger Oilield Glossary at http://www.glossary.oilield.slb.com/; Schlumberger Oilield Glossary at http://www.glossary.oilield.slb.com/; Satter and hakur, 155-198. Satter and hakur, 175-189 Satter and hakur, 186-187 Schlumberger Oilield Glossary Satter and hakur, 178, 188-189. Satter and hakur, 178, 188-189 Satter and hakur, 189-192 See http://www.google.com.au/search?q=Ocean+drilling+programme&ie=ISO-8859-1&hl=en&meta= his section of the Chapter is based on: (1),Chapters 4-8 and 11 of Ben Gerwick, Construction of Marine and Ofshore Structures (1999); (2) OPL, Field Development Concepts of the World (1996/97); (3) Department of Civil Engineering, University of Wales Swansea, “Introduction to Ofshore Structures” at http://www. swan.ac.uk/civeng/Research/ofshore/introto/ofstruct.htm; (4) DTI, An Overview of Ofshore Oil and Gas Exploration and Production, August 2001; (5) “Facilities Options” in Monash University, Development of Ofshore Oil and Gas Fields,, Intensive Short Course 17-21 June 1991, Faculty of Engineering, Ofshore Engineering Progamme. Introduction to Ofshore Structures” at http://www.swan.ac.uk/civeng/Research/ofshore/introto/ofstruct. 62 Producing Oil and Gas - Technical Aspects & Regulatory Implications htm; 31. his section of the Chapter is based on (1) K, Karal “ Ofshore Pipelines” in Mazurkiewicz, B. K. Ofshore Platforms and Pipelines (1987) 299-348; (2) Ben Gerwick, “Installation of Pipelines” – Chapter 15 of Construction of Marine and Ofshore Structures (1999). 32. Karal “ Ofshore Pipelines” 301 33. Karal “ Ofshore Pipelines” 301-2 34. Karal “ Ofshore Pipelines” 315-316 35. K, Karal “ Ofshore Pipelines” in Mazurkiewicz, B. K. Ofshore Platforms and Pipelines (1987) 299-348, 315 36. Karal “ Ofshore Pipelines” 315-316 37. Karal “ Ofshore Pipelines” 319 Producing Oil and Gas - Technical Aspects & Regulatory Implications 63 3 3 THE REGULATORY REGIME GENERAL CONSIDERATIONS AND THE GHANA FRAMEWORK INTRODUCTION & OBJECTIVES OF CHAPTER he law and policy framework for OOGP has evolved into a specialised ield of study and work. In this Chapter, key matters that need to be understood and that are routinely addressed by governments and companies in the OOGP sector are identiied and discussed. he irst segment deals with law, policy and institutional matters in the interaction between companies and governments. he oten divergent but still closely related perspectives of governments and companies are highlighted with respect to each stage of OOGP. A comprehensive examination of Ghana’s new law, the Petroleum Exploration and Production Act 2016, is then provided. MATTERS OF IMPORTANCE TO GOVERNMENTS1 From the point of view of governments with commercially signiicant petroleum resources (producer governments or oil-exporting governments/States) OOGP requires attention to the following considerations or implicates the following matters: • he role of OOGP within the economy generally; • OOGP as a natural resource industry and whether is it to be managed in accordance with conventional approaches for management of such industries or in less conventional ways; • he place of OOGP within the marine zone; • OOGP as an aspect of national and regional economic development; • OOGP as a strategic sector supporting the rest of the economy (petrochemicals; provision of cheap energy for other sectors of the domestic economy; transfer of technology and upskilling of nationals and national irms); • OOGP as a source of environmental harm (especially green house emissions); • OOGP as a resource sector implicating international relations at various levels; • OOGP as an industry sector which attracts foreign direct investment and activity by transnational corporations; • Relationship between OOGp and other sectors of the economy so as to prevent, control or manage the so-called “Dutch Disease”;2 It should be noted as well that these themes have difering aspects or signiicance depending on whether the country is already highly industrialised (commonly referred to as developed country status) or is not particularly industrialised (developing country status). here are also countries with an intermediate situation where rapid industrialisation is taking place. Additionally in some instances, the petroleum sector is the only highly industrialised segment in the entire country, generating a true enclave status. How particular issues/themes emerge or come to be managed is also inluenced by whether or not the country has a well developed national petroleum capability, its own domestic irms and also whether it falls within a geological region with high petroleum prospects. In general, diferent instruments/policies/institutions/arrangements are used to address OOGP issues within the context of difering goals and objectives. Policies/instruments can be complementary or can come into conlict depending on the objectives that they support or the aspect of OOGP that the instruments/policies/institutions are directed at. Government Perspectives and Objectives3 In a broader economic sense, governments look to OOGP to: 66 he Regulatory Regime - General Considerations and the Ghana Framework • • • • create employment generate tax revenue generate internal spending generate convertible currency with some currency retained in the country In a more narrow sense producer governments typically seek: • to ensure an orderly pattern of production and consumption of O & G as a non-renewable mineral resources, taking into account the need to conserve the resource base; • to ensure that the State, as a custodian of mineral wealth on behalf of its citizens, captures a satisfactory level of the economic rent, through appropriate instruments thereby maximizing its revenues; • to ensure that OOGP is conducted with maximum eiciency (ie securing the largest possible recovery of O & G and byproducts) in accordance with the highest possible industry standards; • to ensure that OOGP enterprises minimize environmental damage, and that there is just compensation for the environmental damage resulting from OOGP • to ensure that OOGP leads to a transfer of technology and knowhow, to both personnel and businesses • to ensure that domestic sectors capable of beneiting from OOGP achieve the necessary exposure and experience to OOGP best practice and technologies and receive appropriate inancial returns with interaction with foreign OOGP irms; • to ensure that the country captures as many of the possible spin ofs and indirect beneits from OOGP as practicable - (ie encouraging greater value-added of the minerals produced), from integrated regional development and from the development of linkages with other economic sectors • to stabilize the efects of OOGP revenue lows on the economy so as to prevent, control or manage Dutch disease. To be able to achieve these objectives, producer governments need to develop and adequately implement policies/institutions/law which address: • exploration, development, production, depletion policy, abandonment and decommissioning, procurement policy, • government take (i.e. economic rent and devices for its collection); • integration of the petroleum sector into the general tax system for the country (i. e income tax, customs duties etc.) • petroleum sector speciic taxes – royalties, resource rent taxes, additional proit taxes, rate of return based taxes, bonuses etc. • forms of government participation appropriate to the regulatory authoritypacities of the country concerned (production sharing; free-carried equity; preferential participation rights etc.) • quasi-tax incentives – duty-free importation, tax holidays, exploration re-investment allowances • capturing beneits from positive feedback efects on the economy • negative feedback efects on the economy It is clear that the goals of government are multiple, covering not only aspects relating to promoting economic eiciency and maximizing revenue but also issues of distribution, welfare and the environment and that there are oten areas of divergence. he Regulatory Regime - General Considerations and the Ghana Framework 67 MATTERS OF IMPORTANCE TO PRIVATE OIL COMPANIES Finding replacement reserves constitutes the most important corporate objective for the POC. he most important issue then is the relationship between exploration and production or better still between reserves and production. his is because the most important asset for the POC from a long-term inancial perspective is its access to and control over proved oil resources in the ground. his is the basis on which inanciers lend and also investors invest4. Given that exploration seeks to ind reserves/resources to substitute for or complement those currently being depleted decision-making can be reduced to the following two elements:5 1. assessing/estimating the optimal ways in which to produce oil and gas from existing stocks; 2. investment in exploration activities to ind new petroleum and further develop it for future extraction6. To ensure an appropriate relationship between exploration and production/depletion a very wide range of factors have to be taken into account. he more globally dispersed the assets and interests of the POC are, the more complicated the requirements of strategic management are. Concentrating on discovery and production as the fundamental issue, the following matters combining elements of both demand and supply require constant attention:7 • basins having hydrocarbon potential within countries and/or regions of interest; • acreage available for exploration within each year or a relevant multi-annual time period; • appropriate Production to Reserves ratios (P/R) for each cluster of prospects/actual production scenarios8 • probabilities associated with discovery of oil and gas in each region of interest; • information which provides reliable estimates of probable discoveries of oil and gas • parameters which allow comparison of discoveries of oil as opposed to gas9 • actual discoveries of oil, gas and associated gas respectively in each basin during the year or multi-annual periods; • ratios of associated gas to oil in areas of interest • demand for crude oil; • demand for natural gas; • oil price projections and how these afect investment decisions for both exploration and production; • unit cost (dollars/meter) of metreage drilled for exploration in each area during the year; • maximum investment resources available4 for exploratory drilling during each time period; • long term interest rates; • metreage drilled in each basin during annual or multi-annual time periods; • total recoverable reserves of oil and oil equivalent of gas in areas of interest; • rate of production of oil and gas respectively in areas of interest; • quantity of crude oil and natural gas imported into countries of commercial interest in each year or in a multi-annual period; • the inter-relationship between these factors and government regulatory frameworks; • he strategies of competing enterprises; Strategy Questions10 Taking into account the activity of the company itself as well as the activity of competing interests, the strategic management questions would thus be: 1. What would be the optimal levels of metreage to be drilled across various basins, given the 68 he Regulatory Regime - General Considerations and the Ghana Framework limited amount of investible resources available? 2. How much crude oil, free natural gas and associated gas is expected to be discovered in the various basins as a result of exploration activities, given the uncertainties associated with discovery? 3. What would be the total recoverable reserve of oil and oil equivalent of gas in each basin available for extraction? 4. What would be the optimal time rate of joint production of crude oil and natural gas from the various basins? 5. What would be the total cost of supply (ex-reservoir) of crude oil and natural gas through domestic sources and imports, to meet the overall demand? 6. What would be the import requirement of oil and gas? 7. What would be the optimal levels of upgradation of: (a) Discovered but undeveloped or non-projectised reservoirs, (b) Undiscovered resources? 8. How much investible resources may be required to sustain and further augment the exploration and extraction activity and how are funds apportioned among the basins? Engineering Techniques and Economic-Financial Techniques he engineering, geological and geophysical techniques that address the scientiic-technical elements of these issues have to some extent been discussed in Chapter 2. It remains to note the diferent economic and inancial techniques available to be used to address the economic aspect of these questions bearing in mind that it is not possible to discuss them in detail in this monograph. OOGP corporate analysis and planning techniques11 Management Tools Type Working capital techniques • Projected cash budget • Breakeven analysis • Analysis of inancial and operating leverage • Sales forecasting models • Sources and uses of funds • cash management models • Inventory management model • Historical trends analysis Techniques for analysing capital expenditures • • • • • Average rate of return Payback period Net present value Internal rate of return Historical trends analysis he Regulatory Regime - General Considerations and the Ghana Framework 69 Management Tools Type Forecasting/operations research techniques • Macroeconomic modelling and simulation • Project inancial analysis and modelling • Optimal transportation modelling • Proit/volume analysis • Linear programming • PERT/CPM techniques • Just-in-time techniques • Historical trends analysis POC perspectives and objectives12 From its perspective, POC objectives are usually global or anticipate an increasingly global proile. hus in country or regional contexts companies will seek: • Maximal freedoms, including the freedom to achieve a payback of investment in the shortest possible time with a rate of return commensurate with perceived country or regional risk; • Maximisation of operational freedom, both strategic and day-to-day; • advance knowledge of the policy environment, and in particular the inancial terms, that will apply in the event of a commercial discovery before exploration is far advanced, and be conident of the stability of those terms; • Long term contractual stability; • a tax structure that supports enterprise lexibility in the allocation of resources; • freedom to be able to deal with reserves in accordance with company strategy; • freedom to be able to diversify the company asset base thereby insulating the company from negative long-term and short-term trends; • maximal freedom to rapidly enter into or exit from core OOGP transactional arrangements associated with the various phases of OOGP such as farm-ins; farm-outs and consortia/ joint-ventures to undertake exploration, development and production; • freedom from exchange control restrictions so as to be able to repatriate proits and dividends, and meet all loan and other overseas obligations promptly; • to have management control of the operations and rights over the disposal of the product • Reasonable limitation of liability; • Maximisation of equity returns; • Shared construction risks; • Minimal but politically efective environmental and other social obligations; KEY AREAS OF DIVERGENT INTEREST Key areas of major divergence between corporate interests and government interests include: • • • • • Rate and extent of exploration 13 – Rate and extent of development 14 Rate of production and level of output 15 – Extent and impact of government take or resource rent extraction 16 Protection and rehabilitation of the environment 17 70 he Regulatory Regime - General Considerations and the Ghana Framework REGULATORY CONSIDERATIONS Ownership of Petroleum and its consequences With the exception of the United States18 and South Africa, petroleum law and policy around the world is based on the principle that the State: • exclusively owns all petroleum within its territories, including maritime territories; • that the State may extract petroleum through any/entity or in any manner, with preference given to the licensing or leasing out of its exclusive ownership rights to qualiied applicants; • the State has a right to extract a resource rent/economic rent. he State typically inds an agent to undertake production either on its own account or in a joint-venture with domestic entities (production-sharing; association contract; service contract) with the transaction regulated by a form of petroleum agreement or contract which operates within the framework of a general petroleum law, supported by more detailed and speciic regulations. Another principle is that once petroleum is recovered from the subsoil, it becomes the property of the entity extracting the oil such that the petroleum can be sold by that entity. Ownership claims by sub-State entities In some States it is an issue as to whether the State needs to share its ownership of petroleum in the subsoil with some other interests or grant all or some aspect of the ownership interest to another entity. his issue usually arises where indigenous groups or local entities claim ownership of petroleum resources in their territories. his issue has become one of increasing importance in many countries and is likely to grow in signiicance. For instance in the regulatory authorityse of Nigeria, local tribal groups such as the Ogoni have laid claim to a signiicant interest in the petroleum resources produced within their areas. In New Zealand, Maori groups also lay similar claim as do Aboriginal interests in Australia. In the United States and Canada petroleum in indigenous territories are treated diferently from petroleum in non-indigenous territories. he complexities of these issues are not however explored in this Chapter. Governmental Institutions Established practice worldwide is for the authorities to manage ofshore oil and gas matters through a competent authority (in this Unit the regulatory authority), usually a government Ministry or national oil or petroleum company(NOC/NPC), with such entities having exclusive, shared or co-ordinated responsibility for petroleum matters. Such responsibility may cover both onshore and ofshore oil or it may be separated. In practice, given the greater complexity of OOGP, OOGP considerations tend to dominate over onshore considerations unless onshore resources are extensive and well-established. As Onorato points out, the regulatory authority represents the State in negotiating and contracting with petroleum companies and once such contracts are in place, the regulatory authority administers the contract and acts as the technical interface with licensees. Where there is a national oil company (NOC), the NOC may also allocate acreage by direct negotiation or tender whilst retaining or competing for such acreage, contract with selected licensees and/or act as the government partner in joint ventures with petroleum production companies. Constitution Policy/Legislation Rules/Regulations/Model Contract Petroleum Agreement between Host State and Private Oil Company Consortium he Regulatory Regime - General Considerations and the Ghana Framework 71 THE REGULATORY REGIME – COMPONENT ELEMENTS • • • • the deinition (and nature) of OOGP rights; the quantity of rights to be allocated; how these rights are to be allocated; and terms and conditions associated with the grant and use of OOGP rights. More speciically, the matters covered by the overall regime are: • the release (or supply) of exploration acreage; • issue of invitations to apply for exploration permits; • issue of exclusive exploration permits to successful applicants and determination of conditions of title, • the terms and conditions on which titles are awarded (exploration permits, retention leases, production licences, pipeline licences and proposed infrastructure licences); • the actual procedure for award of titles • the statutory rights conferred by the title • cancellation of titles for non-compliance with conditions of the title; • operational and enterprise matters associated with titles and rights granted: 1. the physical dimensions (area, depth) of the permit or licence area; 2. the criteria for assessing title applications, ield development plans, etc; 3. the duration of the titles; 4. renewal and relinquishment provisions; Other matters are: • • • • • • • • requirement for adoption of good oilield practices, completion of work program commitments; third party access; unitisation; environmental protection; occupational health and safety; speciied standards; rate of recovery and reservoir management; 1. approval of applications for the registration of legal transactions, including farm-outs and transfers of title; 2. collection, release and sale of data; 3. the transferability of titles (that is, their tradaeability). AGREEMENT TYPES IN USE GLOBALLY – AN OVERVIEW19 here are three broad categories of petroleum agreements of contracts currently in use with countries mixing and matching elements of these as they choose, namely: • the licence or modernised concession contract; • production sharing contracts • service contracts 72 he Regulatory Regime - General Considerations and the Ghana Framework The licence or modernised concession contract A concession grants an oil company (or a consortium) the exclusive right to explore for and produce hydrocarbons within a speciic area (called the license area, block, or tract, depending on local laws) for a given time. he POC assumes all risks and costs associated with the exploration, development and production of petroleum in the area covered by concession. Under a concession, the ownership of petroleum in its natural state remains with the State, until and unless petroleum is produced and reaches the wellhead, at which point it passes to the POC. he POC is thus not exposed to changes in its reserves and production entitlements when the oil price changes. Licenses are normally for a ixed time period and are usually split into exploration licences and production licences. he general law lays down certain fundamental provisions and stipulates certain minimum standards and conditions which must be satisied by applicants for the grant of the right to explore for and/or exploit petroleum resources but provides for other key issues to be settled by negotiation. he division of labour between the State and the POC, usually a foreign or non-national company is as follows: • he State through a competent authority (the regulatory authority) grants exclusive exploration and development rights to an oil title company for a contract area. • he POC provides inancing, pays taxes and royalties but receives all production, subject in some cases to a domestic market supply obligation. • he State may or may not contribute capital but under both options its main source of cash low comes from taxes and royalties. • he company pays a royalty rate on the value of production either at the wellhead or when the oil is irst landed • he State imposes an additional proits tax, economic rent tax or resource rent tax applicable only to petroleum operations • he State imposes normal income tax requirements but alters the framework to ensure that companies can only deduct costs and expenses tightly related to exploration and production (so-called ring-fencing) • he State retains lexibility in setting tax rates and royalty rates (ixed, tied to production thresholds) but in practice retains a fairly stable regime which is only altered ater extensive consultation with industry • he State may impose domestic supply requirements but generally does not receive oil production in excess of that which it purchases for its domestic supply requirements • Title to and ownership of equipment and installation permanently aixed to the ground and/or destined for the E&P of hydrocarbons generally passes to the state at the expiry or termination of the concession (whichever is earlier), and the investor is typically responsible for abandonment and site restoration. • he State retains a residual right to take over production as well as to issue directions with respect to exploration, production, development and decommissioning. Participation in the license by the State through the NOC An increasingly commonly used variant of the modern concession is one in which the State participates through two forms of interest: a carried interest and a working interest. A carried interest is an agreement under which one party agrees to pay for a portion or all of the pre-production costs of another party (the carried party) with respect to a license in which both own a portion of the working interest, and subject to contractual terms for recovering its costs. A working interest owner bears the cost of exploration, development, and production of an oil and gas ield and, in return, is entitled to a share of production from that ield. he typical format is for the NOC to be granted a carried interest through the exploration and development he Regulatory Regime - General Considerations and the Ghana Framework 73 phase. Ater a commercial ind is made, the NOC then participates on a working interest basis. he NOC and the POC each receive a share of production in proportion to their equity contributions once production starts. Production sharing contracts Like a concession, a PSC grants an oil company or consortium (the “contractor”) the right to explore for and produce hydrocarbons within a speciied area and for a limited time period. he contractor assumes all exploration risks and costs in exchange for a share of petroleum produced from the contract area. Production is shared among the parties according to formulas deined in the relevant PSC and applicable legislation. Unlike a concession, a PSC provides the investor with the ownership of its share of production only at the delivery point or export point (as deined in the contract). Changes in the oil and gas price result in adjustments to the investor’s share of reserves and production entitlement. Title to and ownership of equipment and installation permanently aixed to the ground and/or destined for exploration—and production of hydrocarbons—generally passes to the state, usually upon commissioning. Furthermore, unless speciic provisions have been included in the contract (or in the relevant legislation), the government (or the national oil company) is typically legally responsible for abandonment. If successful, the POC will recover its costs and earn proit by receiving a share of production. Costs are recovered from “cost recovery oil” which is generally limited to a ixed percentage of production. Production not used for cost recovery is called “proit oil”. Proit oil is shared between the state and the oil title company on either a ixed ration or variable share based on production volumes. Ghana does not use this approach fully but there are elements in the Ghana regime. he basic scheme for a production sharing contract is explained by Figure ? . Production Sharing Production Cost oil Profit oil Investor's portion Investor's after tax portion Royalty Government's portion Profit tax Total investor's share 74 he Regulatory Regime - General Considerations and the Ghana Framework Total government's share Service contracts his type of arrangement has the following features. It is not currently used in Ghana. • he oil title company pays all exploration and developmental costs. • he oil title company recovers these expenditures through a discounted crude purchase price, cash payments, or production take. • he State retains entire production upside, although it may grant a negotiated sliding share of oil produced (“Risk Service Contract”). • International oil companies generally dislike being a Service Contractor to the state. hus, this form of contract is infrequently used. THE GHANA REGULATORY REGIME – AN OVERVIEW Overview States have sovereign jurisdiction over their natural resources and are responsible for maintaining a legal regime for regulating petroleum operations. he legal basis for plenary grants of rights of hydrocarbon exploration, development, and production is generally to be found in a country’s constitution. he next level of regulation is the hydrocarbon law itself. Issued by parliaments (or other law making bodies) it sets out applicable principles of law. Increasingly in close parallel with the petroleum law, governments also issue model agreements or model contracts. hese provide more detail as to the terms on which governments will grant rights to individuals or consortia to explore, develop, and produce petroleum resources and provide the starting template for party-speciic negotiations that eventually generate individual petroleum agreements or contracts. here may also be policies or guidelines on particular issues. More detailed implementing rules are also in parallel set out in regulations where particular matters require much tighter prescription. Based on this set of instruments, governments then negotiate customized and individualized petroleum agreements with POCs which set out the terms under which governments will grant rights to these particular individuals or consortia to explore, develop, and produce petroleum resources. Relevant Constitutional Provisions he relevant constitutional provisions are as follows: Territories Article 4 of the Constitution states the following: (1) he sovereign State of Ghana is a unitary republic consisting of those territories comprised in the regions which, immediately before the coming into force of this Constitution, existed in Ghana including the territorial sea and the air space; (2) Parliament may by law provide for the delimitation of the territorial sea, the contiguous zone, the exclusive economic zone and the continental shelf of Ghana. Lands Article 257(1) provides that all public lands in Ghana shall be vested in the President on behalf of, and in trust for, the people of Ghana. Article 257(6) provides further that every mineral in its natural state in, under or upon any land in Ghana, rivers, streams, water courses throughout Ghana, the exclusive economic zone and any area covered by the territorial sea or continental shelf is the property of the Republic of Ghana and shall be vested in the President on behalf of, and in trust for the people of Ghana. he Regulatory Regime - General Considerations and the Ghana Framework 75 Creation of interests in land Article 266(1) states that no interest in, or right over, any land in Ghana shall be created which vests in a person who is not a citizen of Ghana, a freehold interest in any land in Ghana. Article 26(2) then states that an agreement, deed or conveyance of whatever nature, which seeks, contrary to clause (1) of this article, to confer on a person who is not a citizen of Ghana any freehold interest in, or rights over, any land is void. Article 266 also states that no interest in, or right over, any land in Ghana shall be created which vests in a person who is not a citizen of Ghana a leasehold for a term of more than ity years at any one time. Transactions, contracts and undertakings relating to the exploitation of natural resources Article 268(1) provides that any transaction, contract or undertaking involving the grant of a right or concession by or on behalf of any person including the Government of Ghana, to any other person or body of persons howsoever described, for the exploitation of any mineral, water or other natural resource of Ghana made or entered into ater the coming into force of this Constitution shall be subject to ratiication by Parliament. Article 268 (2) derogates from this rule by stating that Parliament may, by resolution supported by the votes of not less than twothirds of all the members of Parliament, exempt from the provisions of clause (1) of this article any particular class of transactions, contracts or undertakings. Agencies and bodies other than Parliament may grant rights with respect to the exploitation of natural resources Article 269 provides for the establishment of a number of Commissions, namely, the Minerals Commission, the Forestry Commission and the Fisheries Commission. hese Commissions together with other such Commissions as Parliament may determine are to be responsible for the regulation and management of the utilization of the natural resources concerned and the co-ordination of policies in relation to them. he Constitutions then derogates from Article 268 by stating under Article 269(2) that notwithstanding Article 268, Parliament may, upon the recommendation of any of the Commissions established by Article 269(1) authorise any other agency of government to approve the grant of rights, concessions or contract in respect of the exploitation of any mineral, water or other natural resource of Ghana.of this article. Such grants of right shall be upon such conditions as Parliament may prescribe. Laws he main laws governing petroleum operations are the Petroleum Exploration and Production Act 2016 (PEPA 2016) and the Ghana National Petroleum Corporation Act 1983 (PNDCL.64). Other relevant laws include the Income Tax Act 2015 with the GNPC Model Petroleum Agreement completing the legal framework. Environmental regulation is carried out via the Environmental Protection Act of 1994. With respect speciically to the ofshore, other laws implicated are the Maritime Zones (Delimitation) Law (PNDCL 159 of 1986). According to PNDCL 159, the territorial sea corresponds to 12 nautical miles (approximately 24 km) from the baselines of Ghana, whilst the EEZ is deined as the area beyond and adjacent to the territorial sea but less than 200 nautical miles (approximately 396 km) from the baselines from which Ghana’s maritime zones are measured. PNDC L 159 also grants the rights, to the extent as permitted by international law, to the government of Ghana for the purposes of: “exploring and exploiting, conserving and managing the natural resources, whether living or non-living, of the waters superjacent to the sea-bed and of the sea-bed and its subsoil, and with regard to any other activ76 he Regulatory Regime - General Considerations and the Ghana Framework ities for the economic exploration and exploitation of the zone, such as the production of energy from the water, currents and winds…” Objectives and scope of PEPA 2016 Scope of PEPA 2016: his Act applies to petroleum activities within the jurisdiction of the Republic of Ghana, including activities in, under and upon its terri¬torial land, inland waters, territorial sea, exclusive economic zone and its continental shelf. Object of PEPA 2016 he object of the Act is to provide for and ensure safe, secure, sustainable and eicient petroleum activities in order to achieve optimal long-term petroleum resource exploitation and utilisation for the beneit and welfare of the people of Ghana. Management of petroleum resources under PEPA he management of petroleum resources by the Republic of Ghana shall be conducted in accordance with the principles of good governance, including transparency and accountability and the object of this Act. Title to petroleum under PEPA 2016 Petroleum existing in its natural state in, under or upon any land in Ghana, rivers, streams, water courses throughout Ghana, the exclusive economic zone and any area covered by the territorial sea or continental shelf, is the property of the Republic of Ghana and is vested in the President on behalf of and in trust for the people of Ghana Agreement type As regards agreement or contract types in use, Ghana falls into the modernised concession category with a signiicant role reserved for the NOC (GNPC) as it holds both carried and participating or working interests in all agreements. Government institutions Institutional responsibility for managing the oil and gas sector as a subset of the energy sector is as follows: 1. he Ministry of Energy is responsible for developing and implementing energy sector policy and for supervising the operations of a number of government institutions, including the Petroleum Commission, the Energy Commission and GNPC. he Ministry supervises the petroleum sector through a team of representatives from the Ministry, GNPC and the Petroleum Commission on behalf of the Minister. 2. he Petroleum Commission is the upstream regulator with responsibility for, inter alia, qualifying licensees, approving appraisal plans, and implementing local content regulations. he Petroleum Commission was established in 2011 under the Petroleum Commission Act (Act 821). It has statutory responsibility for the regulation and management of petroleum he Regulatory Regime - General Considerations and the Ghana Framework 77 3. 4. 5. 6. 7. 8. 9. resources and coordination of policies in relation to these resources. Speciically, the Commission was established to: promote petroleum activities for the beneit of Ghana; recommend national policies related to petroleum activities; monitor compliance with national policies, laws, regulations, agreements on health, safety and environmental standards in petroleum activities; monitor and carry out inspections and audits of petroleum facilities; promote local content and local participation; receive and store petroleum data; receive applications and issue permits for speciic petroleum activities; assess and approve appraisal programmes; advise the Ministry of Energy on activities related to petroleum including development plans and decommissioning plans for petroleum ields; issue an annual report on petroleum resources and activities; analyse economic information related to petroleum activities and submit forecasts to the Ministry; and perform any other function related to the object of the commission. he Energy Commission was set up by the Energy Commission Act, 1997 (Act 541) and has functions relating to the regulation, management, development and utilisation of energy resources in Ghana. he Energy Commission is the technical regulator of Ghana’s electricity, natural gas and renewable energy industries, and the advisor to Government on energy matters. GNPC is the NOC with responsibility for commercializing oil and gas. GNPC negotiates petroleum agreements with International Oil Companies (IOCs)/Private Oil Companies (POCs) and holds the participating and carried interests on behalf of Ghana under each petroleum agreement. Ghana National Gas Corporation (GNGC) manages gas aspects and is a subsidiary of GNPC. It was established in 2012 with a mandate to operationalise the Jubilee gas infrastructure and to act as gas aggregator/marketer. It is currently a subsidiary of GNPC, with GNPC acting now as the Gas Sector Aggregator. he Environmental Protection Agency (EPA) Act, 1994 (Act 490) grants the Agency, enforcement and standards setting powers, and the power to ensure compliance with environmental law in Ghana. he Attorney General Department is responsible for the legal regime, laws and regulations and also for those international law aspects that are not covered by the Ministry of Transport. he Ministry of Finance and Economic Planning is responsible for the following activities: mobilisation of external and internal resources; allocation of resources to all economic sectors; ensuring sustainability of public debt; preparing and implementing Ghana’s annual budget and inancial statements; management of public expenditure; and development and implementation of inancial sector policies. he Ghana Revenue Authority under this Ministry manages the tax regime, collects petroleum revenues and provides guidance on revenue utilization. Maritime navigation and traic is central to OOGP. he Ministry of Transport manages infrastructural development and service delivery for the maritime transport subsector amongst other sectors. Two of its agencies are vital to OOGP given the importance of FPSOs, petroleum tankers and related vessels to the efective operation of the petroleum sector. hey are (1) the Ghana Maritime Authority (GMA) and Ghana Ports and Harbour Authority (GPHA). he GMA was established under the Maritime Authority Act (Act No. 630 of 2002) and is responsible for monitoring, regulation and coordination of all maritime activities for the Republic of Ghana. GMA regulates all aspects of maritime vessel use in support of the petroleum sector. he GPHA is responsible for planning, managing, building and operating Ghana’s seaports. he GPHA owns Ghana’s two main seaports (Takoradi and Tema) and is a key player in the operation of the sections of the marine terminals that service the petroleum industry. 78 he Regulatory Regime - General Considerations and the Ghana Framework PETROLEUM AGREEMENTS IN THE GHANA SYSTEM he provisions that govern petroleum agreements are as follows: • A body corporate shall not, unless otherwise provided in this Act, engage in the exploration, development and production of petroleum except in accordance with the terms of a petroleum agreement entered into between that body corporate, the Republic of Ghana and the Corporation (PEPA 2016, Section 10(1)). • he Minister shall represent the Republic of Ghana in the negotiation of the terms of a petroleum agreement and shall enter into a petroleum agreement on behalf of the Republic (PEPA 2016, Section 10(12)). • he Minister may require a consortium as a condition for entering into a petroleum agreement (PEPA 2016, Section 10(11)). • A petroleum agreement shall only be entered into ater an open, transparent and competitive public tender process (PEPA 2016, Section 10(3)). • A contractor shall, subject to the provisions of this Act, carry out petroleum activities in the contract area as provided in the petroleum agreement (PEPA 2016, Section 10(2)) • Despite subsection (3), the Minister may on stated reasons decide not to enter into a petroleum agreement ater the tender process as prescribed (PEPA 2016, Section 10(4)) • Where all or part of the area ofered for tender in a public tender process has not become the subject of a petroleum agreement, but the Minister determines that it is in the public interest for that area to be subjected to a petroleum agreement, the Minister may initiate direct negotiations with a qualiied body corporate for a petroleum agreement (PEPA 2016, Section 10(5)) • he Minister shall publish an invitation to tender or an invitation for direct negotiations in the Gazette and in at least two state-owned daily newspapers and may publish ire invitation in any other medium of public communication (PEPA 2016, Section 10(6)). • A body corporate who wishes to submit a bid or participate in negotiations shall submit an expression of interest to the Minister, as prescribed (PEPA 2016, Section 10(7)) • Where the Minister receives more than one expression of interest, a tender process in accordance with subsection (3) shall be undertaken (PEPA 2016, Section 10(8)) • Despite subsection (3), the Minister may, in consultation with the Commission, determine that a petroleum agreement may be entered into by direct negotiations without public tender, where direct negotiations represent the most eicient manner to achieve optimal exploration, development and production of petroleum resources in a deined area (PEPA 2016, Section 10(9)) • he Republic may enter into a petroleum agreement with a body corporate that has the requisite technical competence and inancial capacity to fulil the obligations of the petroleum agreement and other requirements as prescribed (PEPA 2016, Section 10(10)). • A petroleum agreement shall contain a term that the Corporation shall (a) hold an initial participating carried interest of at least iteen per cent for exploration and development, and (b) have the option to acquire an additional participating interest as determined in the petroleum agreement which may be exercised within a speciied period of time following the declaration of commercial discovery, and shall be a paying interest in respect of costs incurred in the conduct of petroleum activities other than exploration costs (PEPA 2016, Section 10(14)). • A petroleum agreement entered into by the Minister shall not be efective if it is not ratiied by Parliament in accordance with article 268 of the Constitution (PEPA 2016, Section 10(13)). • Any borrowing exceeding the cedi equivalent of thirty million ^ United States Dollars for the purpose of exploration, development and production shall be approved by Parliament he Regulatory Regime - General Considerations and the Ghana Framework 79 and shall be in consonance “with the Petroleum Revenue Management Act, 2011 (Act 815) (PEPA 2016, Section 10(15)). THE NATIONAL OIL CORPORATION - THE GHANA NATIONAL PETROLEUM CORPORATION he Ghana National Petroleum Corporation (GNPC) Law, 1983 (P.N.D.C.L. 64) established the GNPC. he GNPC is a corporate body established under the Ministry of Energy to responsible for the exploration, development, production and disposal of petroleum in Ghana. he GNPC is empowered to conduct petroleum operations and partner with foreign investors to promote the economic development of Ghana. It further spells out the organizational structure, the objects and modus operandi of the corporation. he supervising Ministry of the activities of GNPC is the Ministry of Energy. Article 2 of the law spells out the object of the Corporation. Article 3 gives the Corporation the power to form any subs. GRANTING RIGHTS OF EXPLORATION – GENERAL CONSIDERATIONS20 As far as this aspect of OOGP is concerned the business of the regulatory authority is (1) to delimit prospective petroleum acreage or areas in which interested persons can prospect for petroleum (2) ofer up such areas to interested irms through oicially and publicly advertised bid tenders; ((3) manage the selection process and select appropriate irms; (4) negotiate exploration and post-exploration contracts with successful entities. Direct negotiations with selected irms although oten criticised is also common and would typically involve selected irms being invited to explore acreage not included in or planned to be included in a bid tender. In order to receive the most competitive ofers, however, the bid tender method is to be preferred, especially where it is evident that the petroleum industry is already interested in the region or it is reasonably to be anticipated that the industry will be interested21. Determining areas to be offered to the petroleum industry22 Figure ? Graticulation Before licensing procedures can commence, the regulatory authority must irst accurately identify the areas to be ofered (the contract area, license area, title area) so that irms have a clear idea of location and can bid in particular conigurations. he approach is for the regulatory authority to specify a uniform shape for the areas to be ofered, with many countries following the approach taken in either the Gulf of Mexico or the North Sea. It is generally expected that contract areas will be geometrically regular in shape – normally a 3:1 rectangle – and will be oriented north/south or east/west. Deining areas to be ofered is important from the point of view of management of OOGP within the framework of other ocean uses as well as managing OOGP in its own right. he dominant approach is to use the principle of “graticulation” (geographic demarcation) which divides up the area to be ofered on the basis of blocks as shown by Figure ? As to sizing of contract areas, the usual practice is 80 he Regulatory Regime - General Considerations and the Ghana Framework to specify in the petroleum law or other documentation, both the minimum areas to be allocated to bidders (in square kilometres or square miles), leaving it to the regulatory authority to determine the inal quantity and form of individual contract areas granted to applicants within these permitted limits. Offering prospective petroleum areas through bidding23 Although there are many variations worldwide, the key elements of competitive bidding for prospective areas has the following elements: 1. he regulatory authority issues a bid package which provides: • an accurate map of the area(s) open for bid; • a brief description of the geology and topography of the ofered area(s); • a bid sheet listing the criteria for bid evaluation and providing a format for bidders to submit their proposals; • a model contract(s), to which bidders must identify any exceptions; • the procedure for the submission and evaluation of bids and the subsequent negotiating process; • the amount of any bid guarantee to be submitted, set in an amount both to encourage the widest competition and to discourage less than serious bids.24 2. he regulatory authority publishes in the oicial government journal or newspaper a brief description of the areas to be subject to the bid tender, the proposed petroleum operations to be conducted (for example, new exploration, development, enhanced recovery, well workovers) and instructions for obtaining bid packages; 3. he regulatory authority publishes similar such notices in domestic and foreign business and trade publications; 4. he regulatory authority sends such information directly to bidders whom the regulatory authority believes may be interested. 5. he regulatory authority may require prospective bidders to purchase geological and geophysical data, well logs or other proprietary information owned by the State concerning the area(s) subject to the bid tender. The tender process he elements of this process are: bid submission, bid evaluation, award of contractor status; negotiation of a petroleum agreement. Best practice suggests the use of sealed bids; their public opening; transparent but conidential procedures for their evaluation and a maximum time limit for the regulatory authority to conclude the process and negotiate a petroleum agreement. Onorato suggests that a typical approach is to in order of their merit all responsive and competitive bids – factoring in all well an evaluation of the bidder’s technical and inancial competencies – and to notify the irst several (for example, three) ranked applicants. hereater, the regulatory authority will begin negotiations, based on the model contract, with the highest ranked bidder, mandated to conclude a petroleum agreement therewith within a maximum time limit (for example, 60 days), or to commence fresh negotiations with the next ranked bidder(s). Alternatively, the regulatory authority may reject all bids and either re-bid the area(s) or withdraw all or part of it from the bid tender. he Regulatory Regime - General Considerations and the Ghana Framework 81 Criticisms of Discretionary licensing and Work-Bidding Approach25 here has been periodic criticism of the work-bid approach principally by theorists who prefer an auction process. he key criticisms are set out below: Even if the criteria are published and the process is allegedly objective and non-discriminatory, the process has some major weaknesses. As noted … above, the leasing system should select the most eicient operators as lessees. Selection by a bureaucracy would be eicient only if the administrators are capable of identifying eicient operators. he many applying companies might appear quite equal with regard to technological and inancial capabilities. hus, the authorities have a serious information problem deciding which company is able to create most value. his objection applies even if the authorities have some knowledge of the companies’ historical performance at the shelf. Another serious weakness is the lack of transparency. he losing companies have no assurance whatsoever that they have lost to a more eicient applicant. In addition, it is also important to note that the bureaucratic incentives to make an eicient selection of operators are in place. Administrative procedures are much more vulnerable to corruption and regulatory capture than market based open procedures, although this objection might not apply to all resource owners in question. Criticism against this method can also be put forward from a public choice perspective … A discretionary license allocation system confers considerable administrative powers on government bureaucrats. Considerable work in appraising license applications on behalf of the administrators of the system is necessary, specialists have to be attracted to the various governmental bodies involved in evaluation of applications, thus increasing the budget and inluence of the bodies. Moreover, specialized knowledge in various areas enables the government bureaucrat to inluence politicians and political parties because of the dependence of the politician on the bureaucrat for advice and guidance in a highly specialized area. Consequently, through the discretionary system the government bureaucrat retains considerable administrative power which, because of his superior knowledge relative to the politician, may be employed to further his own interest. But even if the list of weaknesses associated with this allocation method is long, Hann (1986) cools down those who optimistically call for change: “Bureaucrats in the government and in the oil companies would be strongly opposed to changing the system because of the threat to their positions and inluence acquired over time.” Direct negotiations As mentioned earlier acreage which is not included in or planned to be included in a bid tender process is oten licensed by the regulatory authority through direct negotiations. Given the possibilities of corruption associated with direct negotiations, best practice approaches would require that the direct negotiation partner should provide suicient information on the following issues: its corporate status and ownership; its area of interest, deined by geological co-ordinates; its technical competence and inancial resources, full described and documented; and complete terms and conditions it proposes for a petroleum agreement. Discouraging non-genuine bids As Onorato succinctly puts it: he evil to be prevented here is “promotion” by an applicant that has neither the inancial nor technical capabilities to fulil the proposed MWO. Too oten, states new to the sector 82 he Regulatory Regime - General Considerations and the Ghana Framework will award licences to such companies, under questionable circumstances, which such companies will, in turn, seek to sell, assign or “farm-out” all or most of their rights to an oil title company at a signiicant proit, having made no real rights to an oil title company at a signiicant proit, having made no real monetary or work expenditures. THE GRANT OF RIGHTS OF EXPLORATION UNDER PEPA 2016 Area management by the Minister, the Commission and the Corporation Ghana now has a highly structured process. It involves the periodic preparation and presumably public release of a reference map; (2) Ministerial opening-up of an area to and for the conduct of petroleum activities ater strategic impact assessments; (3) periodic closure and re-deinition of areas open to and for petroleum activities. As is to be expected, there is also provision for compensation. he rule framework is set out in detail below. Reference map setting out petroleum prospective areas & contract areas26 granted under petroleum agreements he Minister, in consultation with the Commission, is expected to periodically prepare a reference map that shows areas of possible accumulation of petroleum within the jurisdiction of Ghana. hese areas are then to be divided into numbered areas, each of which is to be described as a block27 (PEPA 2016, Section 6). Once an area subject to a petroleum agreement has been negotiated, it is to be called a contract area. It is to be speciied in the petroleum agreement as well as on the reference map. A contract area may cover one or more blocks or parts of one or more blocks (PEPA 2016, Section 12). Opening up of an area to and for petroleum activities he statute envisages that periodically, the Minister will decide to open an area for petroleum activities (PEPA 2016, Section 7 (1)). Prior to such oicial opening up of an area to and for petroleum activities, the Minister is required (in collaboration with the Petroleum Commission and other agencies) to undertake an evaluation of the various interests in the target area (PEPA 2016, Section 7 (2)). Prior also to this opening up, the Minister is expected to inalise a report on the evaluation. his report must at a minimum provide for the target area, a strategic assessment of (a) the impact of petroleum activities on local communities, (b) the impact of petroleum activities on the environment, trade, agriculture, isheries, shipping, maritime and other industries and risk of pollution, and (c) the potential economic and social impact of any proposed petroleum activities (PEPA 2016, Section 7 (3)). Additionally, the Minister is expected to publish this evaluation report in the Gazette and in at least two state-owned daily newspapers. He may also publish the report in any other medium of public communication (PEPA 2016, Section 7 (4)). he report shall specify the area proposed to be opened for petroleum activities, and the nature and extent of the petroleum activities that it is anticipated will take place in the area in question (PEPA 2016, Section 7 (5)). Rights of public participation and objection are also provided for by the statute. Accordingly, a person who has an interest in an area which is the subject of an evaluation report has the right within sixty days ater the publication of the report, to present their views to the Minister (PEPA 2016, Section 7 (6)). he Minister is required to take due consideration of the views of an interested party of the report into account with these views expected to contribute to his decision on whether or not to open the area (PEPA 2016, Section 7 (7)). he Minister is expected to publish he Regulatory Regime - General Considerations and the Ghana Framework 83 his decision in the Gazette and in at least two state-owned daily newspapers as well as any other medium of public communication that he selects to use (PEPA 2016, Section 7 (8)). he Minister also has the power to reserve areas for the Corporation/GNPC - a block, part of a block or a number of blocks may thus be specially allocated to GNPC (PEPA 2016, Section 7 (9)). Closure and redeinition of area previously open to and for petroleum activities he Minister may also close an area (or redeine the boundaries of an area) which has previously been declared to be open under section 7, provided that the target area is not covered by an existing petroleum agreement or authorization (PEPA 2016, Section 8 (1)). Public notice of the intention to close or redeine is required via notice of the decision to close or redeine being published in the Gazette and in at least two state- owned daily newspapers as well as any other medium of public communication that the Minister chooses to select (PEPA 2016, Section 8 (2)). Within sixty days ater the publication, a person who has an interest in the afected area may make a representation to the Minister on the closure or redeinition of the boundary (PEPA 2016, Section 8 (3)). he Minister shall, ater taking due consideration of any repre¬sentation, determine whether or not to close an area or redeine the boundaries of the area (PEPA 2016, Section 8 (4)). he Minister shall ater the expiration of the sixty day period, publish the closure or redeinition of the boundaries of the area in the Gazette and in at least two state-owned daily newspapers as well as any other medium of public communication that the Minister chooses to select (PEPA 2016, Section 8 (5)). he Minister must ensure that closure or redeinition of the boundaries of an open area doeas not afect another area covered by a petroleum agreement or authorisation existing at the time of the decision (PEPA 2016, Section 8 (6)). Access to land and payment of compensation to afected interests Where the conduct of petroleum activities is likely to afect any lawful economic or social interest or activity of the inhabitants of an area, the Corporation shall negotiate the appropriate permission from the relevant authorities and interested persons (PEPA 2016, Section 72 (1)). he contractor or the Corpora¬tion will then pay the agreed compensation to such interested persons (PEPA 2016, Section 72 (1)). Where the afected interest is a licensee, the responsibility falls on the Petroleum Commission to negotiate access and also pay compensation (PEPA 2016, Section 72 (1)). Where there is hindrance to the acquisition of property, the property may be acquired for the Corporation under the State Lands Act, 1962 (Act 125) and the Corporation is expected to bear the cost (PEPA 2016, Section 72 (2)). Ghana - a mix of direct negotiations and bidding based on the licensing round approach PEPA 2016 envisages that Ghana will replace its previous system of direct negotiations with a mixed system of direct negotiations and bidding based on the licensing round approach. he rule framework is to be found in Section 10 of the statute. It will be seen that the two approaches have an uneasy relationship with each other. he general principle appears to be that petroleum agreements shall only be entered into ater an open, transparent and competitive public tender process (PEPA 2016, Section 10(3)). here is however considerable space for the use of direct negotiations. Tendering intermingled with direct negotiations he new system appears to be likely to operate as follows: 84 he Regulatory Regime - General Considerations and the Ghana Framework • he Minister represents the Republic of Ghana in the negotiation of the terms of a petroleum agreement and enters into petroleum agreements on behalf of the Republic (PEPA 2016, Section 10(12)). • he Minister must publish invitation to tenders or invitations for direct negotiations in the Gazette and in at least two state-owned daily newspapers as well as any other medium of public communication he selects (PEPA 2016, Section 10(6)). • A body corporate which wishes to submit a bid or participate in negotiations will then submit an expression of interest to the Minister (PEPA 2016, Section 10(7)). • Where the Minister receives more than one expression of interest, a tender process in accordance with subsection (3) shall be undertaken (PEPA 2016, Section 10(8)). • Despite 10(3), the Minister may on stated reasons decide not to enter into a petroleum agreement ater the tender process as prescribed (PEPA 2016, Section 10(4)). • Where all or part of the area ofered for tender in a public tender process has not become the subject of a petroleum agreement, but the Minister determines that it is in the public interest for that area to be subjected to a petroleum agreement, the Minister may initiate direct negotiations with a qualiied body corporate for a petroleum agreement (PEPA 2016, Section 10(5)). Direct negotiations as the irst and only step he statute also provides that despite the stated preference for tendering set out by PEPA 2016 at 10(3), the Minister may, in consultation with the Commission, decide that a petroleum agreement may be entered into by direct negotiations without public tender. As set out in the statute, the rationale for this choice would be that the Minister, on advice, takes the view that direct negotiations represent the most eicient manner to achieve optimal exploration, development and production of petroleum resources with a deined area (PEPA 2016, Section 10(9)). he Minister represents the Republic of Ghana during direct negotiation of the terms of a petroleum agreement and enters into the speciic petroleum agreement on behalf of the Republic (PEPA 2016, Section 10(12)). he current criteria and system for assessment of bids he Ghanaian authorities currently use the criteria and selection process set out below. Financial Capacity he criteria for assessing inancial capacity are: • Whether the applicant has the necessary inancial resources and technical expertise; • he likelihood that the applicant will continue to have access to suicient resources to meet the requirements of the proposed work program as well as other commitments previously entered into in other permit areas • he future viability of any consortium lodging an application, including evidence that a satisfactory Joint Operating Agreement has or can be reached; • he applicant’s past inancial performance in other petroleum exploration areas in Ghana or, if relevant, elsewhere. Technical Expertise and Capabilities he task is to select the work program most likely to achieve the fullest assessment of the pehe Regulatory Regime - General Considerations and the Ghana Framework 85 troleum potential within the permit area in the minimum guaranteed period, recognising the essential role of wells in the discovery of petroleum. Work programs proposed in bids must signiicantly advance the exploration status of the area. Work program bids are assessed taking account of the following criteria: • he quality and appropriateness of well drilling proposals with quality and appropriateness assessed in part by the extent to which well drilling proposals relate to a supporting program of geological and geophysical work; • he amount, type and timing of any proposed seismic surveying programme; • proposals for accessing and analysing existing non-exclusive seismic data. • he quality and appropriateness of proposals to undertake other types of information acquisition and analysis, including reprocessing; • he extent to which the applicant’s technical assessment of prospectivity and other matters cross-relates to its proposals with respect to seismic surveying, well conceptualisation and targeting, well timing and other aspects of drilling and associated work; • Signiicant appraisal work over any previous petroleum discoveries within the area. Consideration of Past Performance As indicated above, GNPC may take into consideration, amongst other matters the applicant(s) past performance in other petroleum exploration areas in or, if relevant, elsewhere. his may occur even where the applicant’s proposed work program is the highest submitted. his would particularly apply in the situation where one or more of the applicants were participants in previous permits that had been cancelled because of default in meeting work program commitments and where there was no agreement to maintain good standing. Selection via a panel of oicials Applications received are assessed against the selection criteria by a panel of oicials. his panel then prepares a report containing recommendations as to the winning bid. Applications are assessed on the basis of the information contained in the written applications together with any additional information requested by GNPC with such information required to be submitted in writing. Applicants may be invited to attend an interview and information provided during that interview will also be taken into account. However, the composition and timing of the work program proposed in the original application as part of the competitive bidding process cannot be amended by the provision of additional information or through the interview process. 86 he Regulatory Regime - General Considerations and the Ghana Framework THE EXPLORATION PHASE28 General policy considerations Exploration – contrasting objectives of governments and companies29 Government Corporate • to secure rapid and thorough exploration; • To secure rates of discovery commensu• to secure maximum levels of reliable inrate with overall strategy and capabilities formation about all OOGP prospects of the irm • to prevent ‘feet-dragging” and other stra- • To acquire reserve assets appropriate to tegic behaviour by oil title companies irm strategy, positioning and needs • to secure maximum transition from ex- • To minimize being “locked into” develploration to development of all commeropment commitments antithetical to the cially viable inds irm’s overall strategy Governments and exploration Basically exploration provides information to the government on the overall prospectivity of its resources and allows it to better move companies towards production and development. Exploration information also helps with the more efective design of acreage promotion and the monitoring of the eforts of already established licensees involved in all phases of production. Companies and exploration As mentioned earlier, from the company viewpoint, the relationship between reserves and production/depletion is the most important variable in OOGP. he role of an efective exploration programme is basically that it should contribute to the expansion of production in a timely manner. Accordingly, exploration serves a number of inter-related and subtle functions in the production process30: • It provides information about the amount of the existing exploitable stock of the resources; • It provides information about the cost of extractions of diferent deposits (including information about market-relevant and production-relevant characteristics); • It provides information on the location and reserve estimates for diferent deposits and thus allows production to be scheduled more efectively and assists with a more eicient depletion pattern31 • It contributes to reducing existing and future extraction costs due to the information it provides Sunnevag further observes32: By accumulating a large stock of proven reserves one may schedule the production of various deposits more eiciently. his concern about intertemporal eiciency is certainly warranted if the depletion of some deposits leads to tight constraints induced by scarce capacity in production or transport… notably the production of natural gas may require the sharing of common infrastructure. hus it seems that good intertemporal allocation of gas ields requires extensive knowledge about the resource base. his then dictates a rather he Regulatory Regime - General Considerations and the Ghana Framework 87 large inventory of proven reserves… Exploration may also serve to generate discoveries so that reserves are suicient to permit extractionat a rate compatible with demand. Companies therefore aim to retain the maximum freedom to take decisions regarding the rate and extent of exploration, even as the government partner also wishes to retain the power to determine the rate of exploration. he reality however is that the bargaining strength of the government partner is weakest in the pre-exploration stage when the obligations of the irm are being negotiated33. he government partner operates under a shadow of uncertainty and ofers the right to explore or the right to explore and exploit in return for an exploration programme that has large elements of uncertainty34. he concept of the minimum work obligation has rapidly evolved to efectively manage this situation of uncertainty, with all sectors of OOGP accepting that OOGP States have a right to ask for a particular standard of Minimum Work Obligation (MWO) from oil title irms. Evaluating the exploration opportunity – the Company perspective35 From the point of view of the POC it will evaluate the exploration situation it is entering into against the following criteria: • To what extent is the company obliged to furnish to the government partner information and geological and geophysical data gathered by it during exploration? • To what extent is the company required progressively to relinquish or reduce the area held by it for purposes of exploration? • Is there a minimum work obligation imposed on the company? To what extent does the government partner retain the power to control or supervise the extent and rate of exploration? • Is there a minimum expenditure obligation imposed on the company? • Is the company required to furnish a performance bond to guarantee performance of its obligation? • Are there any iscal or inancial provisions, which provide an incentive for rapid and thorough exploration? 88 he Regulatory Regime - General Considerations and the Ghana Framework EXPLORATION LICENCES UNDER PEPA 2016 Under PEPA 2016, Ghana now has two types of licences: the non-exclusive reconnaissance licence and the exclusive exploration licence which is part of the PA. he exploration period which is divided into three segments is efectively an exploration licence joined up with a production licence in one instrument, the PA. The reconnaissance licence – a non-exclusive right Non-exclusive licences provide a framework for specialized oil services companies to undertake (a) data collection including seismic surveying and shallow, drilling, as well as (b) processing and interpretation or evaluation of petroleum data with respect to and across large areas. To secure the services of such companies for the Corporation, the Minister may (in consultation with the Commission) grant a person, a petroleum reconnaissance licence covering a deined area (PEPA 2016, Section 7(1)). A reconnaissance licence grants the licensed person permission to undertake (a) data collection including seismic surveying and shallow, drilling; (b) processing and interpretation or evaluation of petroleum data with respect to and across the deined area (PEPA 2016, Section 7(2)). A reconnaissance licence is issued for up to three years in the irst instance, but can, where necessary, be extended by the Minister for up to two more years (PEPA 2016, Section 7 (5)). As a general rule, a reconnaissance licence does not grant a person a right to acquire data in an area covered by a petroleum agreement or an authorization (PEPA 2016, Section 7 (7)). Even so, the Minister may, in consultation with the contractor, grant a licence which is co-terminous with a PA on condition that the reconnaissance activities of the licensee do not unreasonably interfere with the activities of the contractor under the PA (PEPA 2016, Section 7 (8)). A person shall not commence activity under a reconnaissance licence unless that person has complied with (a) the relevant statutory requirements on environmental pro¬tection prescribed in the Environmental Protection Agency Act, 1994 (Act 490); and (b) any other applicable enactments (PEPA 2016, Section 7 (6)). Variants of the basic reconnaissance licence he Minister may also grant an exclusive right to undertake reconnaissance activities in a deined area not covered by an existing reconnaissance licence. However, such grant does not afect any proprietary rights of the Republic to data or preclude the rights of the Commission or the Corporation to undertake reconnaissance or other petroleum activities within that same area (PEPA 2016, Section 7 (3)). he Republic may also enter into a petroleum agreement with a per¬son who has the requisite technical competence and inancial capacity to undertake reconnaissance activities and other require¬ments as prescribed (section PEPA 2016, Section 7 (4)). A petroleum agreement may be entered into with a third party in respect of an open area covered by a reconnaissance licence (PEPA 2016, Section 7 (10)). Finally, unless the Minister otherwise determines, the right granted under a reconnaissance licence to acquire new data in the open area shall terminate from the efective date of a petroleum agreement and an obligation to refund fees or liability for other losses shall not arise as a result of the termination (PEPA 2016, Section 7 (11)). Finally, the Minister shall not be held liable by a third party for fees or for other losses that arise as a result of the reconnaissance licence granted to that third (PEPA 2016, Section 7 (9)). he Regulatory Regime - General Considerations and the Ghana Framework 89 Rules governing the exploration right within the Ghana PA A multi-phase exploration period Ghana has merged both exploration and production licences into one agreement thereby cutting down the bureaucracy which would otherwise the process of negotiating a production licence as a follow-on from an exploration licence. he basic exploration period within a PA is seven years from the efective date of the agreement (PEPA 2016, Section 21 (1)). he exploration period is broken up into sub-periods (the statute uses the term working periods) com¬prising an initial exploration period and up to three extension periods (PEPA 2016, Section 21 (2)). A contractor can move into the next working period where they have fulilled the work and expenditure obligations for their current working period via a written notiication to the Com¬mission before the expiration of the relevant working period (PEPA 2016, Section 21 (3)). he Commission may on an individual basis and upon application, extend a working period provided that the contractor has carried out substantial parts of the work programme stipulated in the petroleum agreement in a prudent manner and to the satisfaction of the Commission (PEPA 2016, Section 21 (4)). No indication is given as to how long the extension of a working period can be, with the result that the exploration period within a PA is lexible and in practice may extend beyond seven years. he basic rule though, is that, a petroleum agreement automatically terminates where a contractor fails to submit a declaration to the Minister, that the petroleum discovered in a contract area is a commercial discovery, before the expiration of the overall exploration period (PEPA 2016, Section 21 (7)). Last gasp commercial discoveries may justify extension of an exploration period beyond seven years he Minister in consultation with the Commission may extend the overall exploration period beyond seven years: (a) where a discovery of petroleum is made in the last year of the exploration period, and an extension is necessary to enable a commerciality determination to be made; (b) in exceptional situations as may be prescribed under the statute (PEPA 2016, Section 21 (5)). An extension shall (a) only apply to the reduced area encompassing the geological structure in which the discovery is located; and (b) shall be limited to the time period necessary for the determina¬tion of whether the discovery is a commercial discovery (PEPA 2016, Section 21 (6)). Permit required before exploration drilling can commence he mere fact that a POC has a right to explore under a PA does not provide a basis to commence drilling as the statute requires a contractor to secure two sets of inter-related approvals before drilling can start. hese permits are a drilling permit from the Petroleum Commission (PEPA 2016, Section 24(2)) and an environmental approval from the EPA under the Environmental Protection Agency Act, 1994 (PEPA 2016, Section 24(3)). Each well or ield is also to be identiied by a unique designation assigned by the Commission (PEPA 2016, Section 24(4)). he contractor is also prohibited from changing the designation, status or classiication of a well or ield without the written approval of the Commission (PEPA 2016, Section 24(5)). hese requirements also apply to GNPC when it is operating as a sole operator under section 11 (1) of the statute (PEPA 2016, Section 24(6)). 90 he Regulatory Regime - General Considerations and the Ghana Framework The Minimum Work Obligation Concept36 MWOs set out certain minimum requirements with regard to the extent of geological and geophysical surveys to be carried out, the minimum number of exploratory wells to be drilled and the minimum depths to which these should be drilled. Despite the MWO having emerged as a governmental right, it is still the practical reality that MWO can be diicult to elaborate when the level of information is low. he MWO is typically submitted in the bid and is negotiated into its inal form ater the successful bidder has been selected.37 MWO can be expressed as a year by year obligation or for the entire exploration period38. he MWO typically consists of 1) work scope; 2) expenditure obligation; 3) liquidated damages for non-performance 4) performance bond (generally for the minimum expenditure obligation)39 . Onorato suggests that MWO should be expressed in quantitative terms (for example number of wells and/or metres to be drilled; kilometres of seismic lines to be acquired or in monetary terms (monetary value of each MWO committed). Preferred practice is that the MWO will be expressed in quantitative work obligations with line-item monetary values assigned to each such obligation, payable as a penalty in the event of non-fulillment40. Onorato suggests that: To support the annual work programme, the … contract should require the contractor to provide an unconditional bank guarantee or standby letter of credit in favour of the regulatory authority, setting out the negotiated US dollar or other hard currency amount of such guarantee for each phase of the exploration period, by line item. Provision is then made for the scheduled reduction of the guarantee on certiication by the regulatory authority to the issuing bank that the work in question has been completed. It is typical for contracts to provide for an escape clause that sets out valid technical reasons for non-performance of MWO41 Minimum Work Obligations – difering State and POC objectives he State inevitably wishes to acquire and process as much data as possible, as rapidly as possible. herefore host governments want to oblige the POC to undertake a maximum amount of seismic surveys, exploration drilling and other exploratory operations as quickly as is reasonably possible. From the point of the view of the State this is relatively costless as under most agreements, the State carries very little exploration risk. Even when it has a carried interest requiring eventual reimbursement of contractor expenditures, typically reimbursement of exploration expenditures is not required. Given that under most petroleum agreements, the host government regarding its petroleum resources. he POC views the issue very diferently as it has a inite level of inancial, personnel, and other resources to devote to speciic as well as total exploration operations. Each POC will also generally have a choice of competing exploration opportunities in one or more host countries. he priority to be attached to each of these opportunities, as well as the capacity of the POC to undertake exploratory operations, is subject to constant revision as new data becomes available, market conditions and inancial circumstances change, and as the POC takes on additional commitments. Generally therefore the POC has little interest in obtaining data in any particular Contract Area unless the acquisition of such data will signiicantly increase the possibility that the POC will make a commercial discovery there. As a result, it is generally in the interest of the POC to have as much lexibility as it can in terms of the extent, and timing, of its minimum work obligation commitments he Regulatory Regime - General Considerations and the Ghana Framework 91 Evaluating MWO Obligations – the Company perspective42 he kinds of issues of concern for companies in light of the world-wide market for technical services and its other commitments would be: • • • • • • • • • What is the nature of the irrevocable commitment required by the government? What is the time period granted for performance? What is the lexibility or leeway built into the MWO?43 What happens if MWO are not performed? Where the work commitment consists of seismic data and a minimum number of wildcat sells, is there a penalty for each line kilometer of seismic data not shot and each meter of wildcat not drilled?44 Are penalties in the form of liquidated damages (pr-eagreed monetary amounts)? Are there controls over when work programme and budget are submitted? How much pre-approval is required? How rigid are the time periods in which work is to be conducted? – for example 1 exploration well to be drilled per relevant period (6 months; 1 year) but without a grace period45 Onorato also takes the view that: … the regulations should establish the principles that while the rightsholder may credit work undertaken in excess of the WMO for a given term to an ensuing term, its failure to perform MWO for any given term will give rise to penalties, including the payment to the regulatory authority of the value of the MWO not completed, termination of the petroleum agreement or both. To ensure that the the government partner concerned will receive payment for the value of MWO items not completed, the regulations should specify that the rightsholder must secure either a bank guarantee or an irrevocable standby letter of credit in favour of the regulatory authority, on a line-item basis, against the total value of the applicable MWO which such security may be drawn down on demand by the regulatory authority in cases of non-performance or default. The regulation of minimum work obligations under PEPA 2016 he rules in the statute are minimal with details on actual work obligations negotiated on a case by case basis and set out in each PA. he statute provides that for each working period of the exploration phase, a petroleum agreement shall include a term setting out the minimum work obligations as well as corresponding minimum expenditure amounts to be fulilled by a contractor during each phase (PEPA 2016, Section 23 (1)). Monetary obligations arise for the contractor where they fail to fulil the minimum work obliga¬tions attached to each working period, and if additionally, the Commission has not oicially extended the duration of that working period. In such situations the contractor will be required to pay the Corporation the amount required to complete the unfulilled portion of the work program for that working period (PEPA 2016, Section 23 (2)). Clearly this is a situation which calls for the posting of a bond or some other form of monetary instrument to manage this type of risk. Finally, the Minister may, terminate the petroleum agreement where the contractor fails to fulil the minimum work obliga¬tion within the working period stipulated and the Commission has not extended the duration of that working period, (PEPA 2016, Section 23 (3)). 92 he Regulatory Regime - General Considerations and the Ghana Framework Relinquishment General policy considerations 46 Corporate strategy may wish to hold on to particular areas for a range of reasons, including reserves policy, whereas the government partner is interested in rapid and orderly discovery and production of petroleum. he government partner thus desires early relinquishment whilst companies may desire to hold on to acreage for a longer period. he purpose of relinquishment provisions is to ensure that by the end of the exploration phase of a petroleum agreement all acreage contracted but not to be commercially developed is returned by the rights-holder to the regulatory authority in orderly geometric pattern suitable for ofering to other interests in an orderly and eicient manner47. A typical mandatory relinquishment pattern for a seven-year maximum exploration phase would be: 25% of the original contract area ater two years; 50% of the original area ater four years and all portions of the contract area ater the end of the exploration phase, except those areas which are retained under a retention licence or which have been declared commercial. Relinquishment provisions operate alongside provisions to return G& G data (raw data and interpretation) to the State ensuring that at the end of the period, the State is much better informed about the area in question in addition to having appropriate levels of development and production where this is feasible. Given the strategic behaviour problem, the government partner also has a vested interest in resuming control over areas where companies have carried out initial exploration eforts and have not made any discoveries or have decided not to carry out any further exploration as these areas may better suit the eforts of other irms or may be aggregated with the areas of other irms. The regulation of relinquishment under PEPA 2016 PEPA 2016 provides for both voluntary and compulsory relinquishment. Voluntary Relinquishment A contractor is free under 22 (1) to submit a proposal to relinquish a contract area or part of a contract area to the Commission at any time. he Commission approves each proposal on the basis of the prescribed conditions (PEPA 2016, 22 (2)). Such conditions will include an assessment of the extent to which the minimum work obligations have been met and also whether any inancial amounts posted to support the minimum work obligations should be declared to be forfeit. Relinquishment following completion of work periods and/or obligations A contractor who chooses to enter into the irst extension of the exploration period under the PA should expect to relinquish at least 50% of the contract area agreed at the date the petroleum agree-ment became efective (PEPA 2016, Section 22 (3)). Where the contractor continues to explore into the second or third extension period, he should expect the contract area retained to be not more than twenty-ive per cent of the area agreed at the efective date of the petroleum agreement (PEPA 2016, Section 22 (4)). Relinquishments under these conditions will occur at the end of each relevant working period despite any extension granted under section 21 (4) (PEPA 2016, Section 22 (5)). However, the Minister may (in exceptional cases and in consultation with the Commission) intervene to enlarge the areas that are retained by the contractor (PEPA 2016, Section 22 (6)). his power can be exercised with respect to all the extension periods. he Minister may be justiied in doing this taking into account the size, location or nature of the contract area (PEPA 2016, 22 (7)). he Regulatory Regime - General Considerations and the Ghana Framework 93 Other relinquishment provisions To allow for efective conduct of petroleum activities, the area relinquished must (unless otherwise determined by the Minister in consultation with the Commission) be contiguous and compact and be of a size and shape that will facilitate such activity (PEPA 2016, Section 22 (8)). he area to be retained by the contractor ater relinquishment To protect the interests of the POC (but also the interests of the Host State in rapid discovery of petroleum) the statute provides that the area to be retained at the end of the exploration period should (1) as much as possible include geological structures containing discoveries made in the contract area; (2) be of a suitable size and shape (PEPA 2016, Section 22 (9)). he Minister approves the inal coniguration for the retained area in consultation with the Commission (PEPA 2016, Section 22 (9)). DISCOVERY OF PETROLEUM & ASSESSMENT OF COMMERCIALITY General Considerations he discovery of petroleum raises a large number of issues ranging from the type of resource discovered (oil, gas, distance to market etc.). It also raises issues as to whether what has been discovered is commercial. Commerciality is possibly the most diicult issue at this stage since commerciality is very oten in the eyes of the beholder. here are a number of diferent issues including: 1. How is a “commercial discovery” deined? 2. What conditions are to be fulilled in order for a company to come under an obligation to develop such a reservoir? 3. What is the extent of the the government control over the development decisions of the company? 4. whether commerciality is required to hold onto a licence? 5. How long a possibly commercial ind can be held on to by the company 6. How commerciality its into the strategies of company and government Deinitions of commerciality Some countries pre-deine commerciality (for example commercial may be deined as 1 discovery well plus 1 or 2 appraisal wells capable of producing commercial quantities of oil)48 whilst others leave it to the commercial judgement of the company. In other jurisdictions commerciality is assessed through the regulator reviewing the company’s information on the ind. Retention of currently non-commercial ields he contingent character of the commerciality assessment is driven by the price of crude oil and gas as well as the inancial capabilities of the inders of the deposit. he question is whether it is practicable for a government to allow an operator to hold on a discovery which it views as not commercially viable in the short term, when they may be other companies who will view the discovery as commercial and develop it. 94 he Regulatory Regime - General Considerations and the Ghana Framework In response to this problem, the practice has developed of having a retention licence for non-commercial areas that the company wants to hold onto. From the point of view of improving the reserves proile of the company, this type of licence is useful for a company which wants to improve its reserves proile or which wants to later trade in reserves and development licence for more commercial licences. In some countries however, the retention licence concept is not present. A ield once shown to be commercial has to be developed or the company has to relinquish it to other more eager parties. Development phase: general policy considerations Assuming that the discovery is commercial, the enterprise and the government both enter a highly crucial phase during which signiicant investments must be made to develop the reservoir with the cost of development being many times the cost of exploration. he key problem is that corporates will view development priority, expenditure levels and technological options from within their global strategy whilst governments will want the most rapid and efective rate of exploration within government strategy. Technological choices made in the development phase are crucial since these will virtually condition longer term production matters such as the inter-relationship between primary and post-primary recovery (particularly the extraction rate related in turn to the rate of decline of the ield - see Chapter 2); the relationship between gas and oil (including laring, use of associated and non-associated gas); whether proven or experimental methods are to be used by the irm etc. THE GHANA APPROACH TO DEFINING AND ASSESSING COMMERCIALITY Notification of petroleum discovery and appraisal Section 25 of PEPA 2016 addresses notiication of petroleum discovery and appraisal. he starting proposition under sub-section 1 is that a contractor is obliged to furnish information requested by the Minister or the Commission and shall therefore submit periodic reports on the results of explo¬ration carried out under an agreement. Where exploration activities result in a petroleum discovery, the contractor shall within forty-eight hours ater such discovery submit written notiication of the discovery to the Minister (PEPA 2016, Section 25(1)(a)). his must be done before any notii¬cation to a third party (PEPA 2016, Section 25(1)(a)). his notiication is important since the date of the written notiication to the Minister shall be the discovery date (PEPA 2016, Section 25(3)). Section 25(1)(b) requires further and more detailed written notiication to the Minister and the Commission, this notiication being intended to provide the full particulars of the discovery in writing. his must be done as soon as practicable and in any event within one hundred days ater the discovery. he more detailed notiication will state whether the discovery merits appraisal or not (PEPA 2016, Section 25(1)(b)). Consequences of notification that a discovery does not merit appraisal he consequence of expressing a view that a discovery does not merit appraisal is that the contractor must with efect from the date of notiication, relinquish the contract area encompassing the geological structure in which the discovery is located (PEPA 2016, Section 25(4)). Subsection (5) provides that a contract area relinquished under subsection (4) shall not reduce the contract area to be retained in accordance with section 22. Delineation of the contract area to be relinquished is subject to the approval of the Commission (PEPA 2016, Section 25(6)). he Regulatory Regime - General Considerations and the Ghana Framework 95 Notification that a discovery merits appraisal Notiication that a discovery merits appraisal triggers a requirement that the contractor prepare and submit a programme and schedule to carry out an adequate and efective appraisal of the discovery to both the Commission and the Minister, (PEPA 2016, Section 25(7)). his programme and schedule must contain information that will enable the contractor to delineate the extent of the accumulation of petroleum and to determine whether the discovery constitutes a com¬mercial discovery (PEPA 2016, Section 25(8)). As a general rule, appraisal periods are speciied in the applicable petroleum agree¬ment and may not exceed two years from the date of discovery (PEPA 2016, Section 25(9)). In special cases, the Commission may recommend that an extension of the appraisal period beyond two years be granted by the Minister. he Commission may stipulate conditions to govern the extension (PEPA 2016, Section 25(9)). he proposed appraisal programme is subject to the approval of the Commission, such approval stipulating conditions that must be met before or as part of the appraisal process. A contractor shall not commence an appraisal programme or enter into binding obligations relating to an appraisal programme until the appraisal programme has been approved by the Commission (PEPA 2016, Section 25(10)). An appraisal report must be submitted to the Commission within ninety days ater completion of the appraisal programme. his report must state the results of the appraisal programme including whether the discovery is commercial49 or not, and must provide a basis for whatever assessment is provided (PEPA 2016, Section 25(13)). In the event that a contractor declares a discovery not to be commer¬cial, the contract area encompassing the geological structure in which the discovery is located, must be relinquished by notii¬cation in writing to the Commission within ive days from the date of the declaration that the discovery is not commercial (PEPA 2016, Section 25(14)). he contract area to be retained in accordance with section 22 shall not be reduced on account of the relinquishment (PEPA 2016, Section 25(15)). Finally, the Commission must approve the delineation of the con¬tract area with relinquishment taking efect from the date of notiication to the Commission (PEPA 2016, Section 25(16)). he rules on notiications and appraisals apply to GNPC when it is operating as a sole operator under s section 11(1). However, in what is a departure from the principle of competitive neutrality between the NOC and the POC, GNPC is allowed to have a longer appraisal period than the two years that is applicable to the private sector (PEPA 2016, Section 25(17)). 96 he Regulatory Regime - General Considerations and the Ghana Framework THE DEVELOPMENT PHASE Plan of development and operation Deadlines A declaration of commerciality inaugurates the process of development of the ield. his is the most expensive phase within the petroleum value chain. PEPA 2016 requires the contractor to submit a plan of development and operation to the Minister once a ield is declared commercial (PEPA 2016, Section 27(1)). he Minister sets a deadline for the submission of the plan (PEPA 2016, Section 27(2)). Clearly this is an iterative process in which it is ater discussions between the two sides that the Minister sets a deadline. Practice and experience in Ghana is that the process will take at least two years. he essential elements of a plan of development Section 27(3) sets out the required content for the plan of development stating that it must cover both the development and production aspects together with an environmental report approved by the appropriate institutions in accordance with applicable enactments (PEPA 2016, Section 27(3)). Section 27(4) sets out the minimum requirements for a plan of development, stating that the plan must address both the development and production aspects and must provide detailed information on the economic, reserves, technical, operational, safety, commercial, local content and environmen¬tal components of the proposed development. Section 27(4) provides a list of these minimum requirements, namely: (a) a description of the proposed development strategy and concept; (b) an economic assessment of the diferent development methods, estimated investments, operational costs and selection criteria; (c) a plan covering the total development concept, where the develop¬ment is proposed in two or more phases; (d) an assessment of the potential for development of further petroleum resources within the contract area to ensure the maximum long term recovery of the resources; (e) information on tie-ins with other petroleum ields where applicable; (f) area studies addressing the possibility of co-ordination of petroleum activities including with the development of nearby petroleum ields; (g) proposed drilling and well completion plans; (h) the geological parameters and reservoir engineering method¬ology that has been selected; (i) a description of the facilities for production, storage, transportation and delivery of petroleum that will be the infrastructure backbone of the development; (j) a development schedule; (k) a long-term production schedule; (l) a description of prospective technical solutions including possible solutions for enhanced recovery; (m) a description of capacities of the proposed facilities; (n) solutions with respect to the eicient use of energy, as well as the prevention and minimisation of environmentally harmful discharges and emissions; (o) proposals with respect to the disposal and use of associated gas where applicable; (p) management systems, including information on the plan¬ning, organisation and implementation arrangements proposed for the development; (q) operation and maintenance considerations; (r) a description of iscal metering systems; (s) a petroleum marketing plan; (t) a security plan; (u) a inancing plan for the development; (v) a health and safety assessment report; (w) an emergency preparedness plan; (x) facilities for transportation, utilisation or treatment of petroleum; (y) decommissioning and disposal of facilities; (z) applications for the permits and licences that will be required; (aa) a local content plan; and inally, (bb) an employment and recruitment programme and a tech-nology transfer plan (PEPA 2016, Section 27(4)). he Regulatory Regime - General Considerations and the Ghana Framework 97 Marginal ields and controls over laring he Minister may require the contractor to ensure that a marginal ield delineated before and ater approval of the plan of development and operation, is optimally developed and produced (PEPA 2016, Section 27(5)). he plan of development and operation shall include details for the construction of facilities to avoid gas venting or laring under normal operating conditions (PEPA 2016, Section 27(6)). Ministerial controls over the plan of development process he Minister may n consultation with the Commission, in the national interest limit the approval to the development and production of individual reservoirs or phases and the development and production may be subject to conditions determined by the Minister, including requirements relating to additional capacities for additional resources or third party access (PEPA 2016, Section 27(7)). he Minister may revise the long term production schedule if the revision is warranted by resource management considerations or signiicant socio-economic considerations (PEPA 2016, Section 27(8)). Unless otherwise permitted by the Minister, a contractor shall not (a) enter into contracts relating to the plan of development and operation, or (b) commence construction works until the plan of development and operation has been approved by the Minister (PEPA 2016, Section 27(9)). A plan of development and operation becomes efective upon the prior written approval of the Minister (PEPA 2016, Section 27(10)). he contractor shall promptly notify the Minister in writing of any deviation from the assumptions and preconditions on which a plan has been submitted or approved (PEPA 2016, Section 27(11)). Any deviation or alteration to the plan of development and operation or material alteration to the facility requires the written approval of the Minister (PEPA 2016, Section 27(12)). he Minister may require a new or amended plan of develop¬ment and operation to be submitted before the approval of any deviation or alteration (PEPA 2016, Section 27(13)).Where a contractor does not submit a plan of development and operation within the time limit set by the Minister in accordance with subsection (1), and the Minister has not extended the time limit, the area encompassing the ield to be developed shall be relinquished by the contractor (PEPA 2016, Section 27(14)). his section applies to the Corporation where it undertakes petroleum activities in accordance with section 11 (1) (PEPA 2016, Section 27(15)). he bases on which Ministerial approval can be withheld he Minister shall not approve a plan of development and operation unless (a) the plan would ensure eicient, beneicial and timely exploitation of the petroleum resources concerned; (b) the plan takes into account good petroleum industry practice and safety factors; (c) the contractor has adequate inancial resources and technical and industrial competence and experience to undertake efective development and production operations; (d) the descriptions and proposals of the contractor under section 27 (4) are satisfactory to the Minister; (e) the contractor is able and willing to comply with the condi¬tions on which a plan of development and operation is approved; (f) the local content plan, the proposed employment, recruit¬ment and training of Ghanaian citizens and the technology transfer plan have been approved by the Commission; and (g) the contractor has adequate insurance cover; and (h) the Minister has received recommendation from the Com¬mission and relevant agencies (PEPA 2016, Section 28(1)). A plan of development and operation shall not be approved if a contractor is in default under a petroleum agreement (PEPA 2016, Section 28(2)). Where a plan of development and operation is not approved, the Minister shall by written notice to the contractor state the reasons for 98 he Regulatory Regime - General Considerations and the Ghana Framework non-approval (PEPA 2016, Section 28(3)). Where a plan of development and operation is not approved by the Minister, the area covered by the plan of development and opera¬tion shall be relinquished by the contractor (PEPA 2016, Section 28(4)). his section applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 28(5)). Postponement of development Where public interest or national interest requires, the Minister may, ater consultation with the contractor, postpone the development of a ield (PEPA 2016, Section 29(1)). In the event of a postponement under subsection (1), the term of the petroleum agreement shall be extended for the period of postpone¬ment, and the obligation to pay acreage fees during that period shall be suspended (PEPA 2016, Section 29(2)). his section applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 29(3)). THE PRODUCTION PHASE Policy Considerations From the company point of view, the key questions in understanding a production control regime are the following: 1. 5. How much control does the government partner have over decisions and policies relating to production? 2. 6. To what extent can/does the government partner inluence or determine decisions relating to the rate of extraction, level of production, adoption of secondary recovery procedures, laring of gas, etc? 3. 7. What standards (good oilield practice? other standards) are laid down to regulate petroleum operations by the company and how far do these enable the government partner to regulate and efectively supervise the operations of the companies? 4. 8. In overall terms, how extensive/intensive is regulation of production operations? From the government perspective, the most important consideration is how rapidly production will occur and whether petroleum will be recovered in such a way as to maximise the recovery from the ield of all recoverable petroleum. As stated in Chapter 2, excessive rates of recovery may damage the natural drive of the ield whilst recovery at an over-leisurely pace may also damage government revenue interests and targets. he use of enhanced recovery options is also a matter of signiicant contention given their capacity to signiicantly afect geological formations and their cost. here are also environmental, safety, multiple-use and decommissioning implications. The over-riding requirement of prudent exploitation Ghana has chosen the phrase prudent exploitation to cover the mix of policy objectives that are sought with respect to management of its petroleum endowments. To give efect to this concept, the statute enjoins contractors to develop and produce petroleum in a man¬ner that will ensure the maximum long term recovery of the resource (PEPA 2016, Section 26(1)). Contractor are required to ensure that development and production of petroleum is conducted in accordance with best international practice and sound economic principles, and in a manner that will ensure that waste of petroleum or loss of reservoir energy is avoided (PEPA 2016, Section he Regulatory Regime - General Considerations and the Ghana Framework 99 26(2)). Contractors are also to conduct continuous evaluation of their depletion strategy and develop appropriate technical solutions to any problems that may arise from the exploitation process (PEPA 2016, Section 26(3). hey are also enjoined to take the necessary measures to optimise the recovery of Ghana’s petro¬leum resources (PEPA 2016, Section 26(3)). he obligation of ensuring prudent exploitation applies equally to the Corporation where it undertakes petroleum activities in accordance with section 11 (1) (PEPA 2016, Section 26(4)). Commencement of petroleum production he statute provides that production of petroleum shall not commence without the written approval of the Commission (PEPA 2016, Section 30(1)). Before such approval is granted, the Commission must formally assess whether: (1) the contractor has developed the ield in accordance with the plan of development and operation; (2) the contractor has complied with any conditions speciied in the approved plan of development and operation (PEPA 2016, Section 30(2)). his section also applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 30(3)). Annual permits covering petroleum production activity (extraction; enhanced recovery and flaring) Governments and the market both desire information about the way existing reserves are being depleted. he metric that is used is termed the production rate (annual production as a percentage of proven reserves). he production rate should also ideally be part of a wider depletion strategy50 or policy. Depletion policy is driven by a number of considerations, amongst which are geology, the revenue needs of a country, international relations and so on. Saudi Arabia is famous for having a depletion strategy in which it increases or reduces production to afect global petroleum prices. It is not clear whether Ghana has developed a depletion strategy or policy yet. Designing and implementing a depletion strategy is a sophisticated exercise and it would be no surprise if Ghana has not yet developed even a basic policy, given the recency of its rise to the status of being a petroleum producing country. It is useful however to note that PEPA 2016 provides some of the technical ield level tools to be able to develop and implement a depletion strategy. he heart of the incipient system is the right of the Commission to require information about proposed production levels in the context of long-term production forecasts. he rule framework is as follows: • A contractor shall not produce or inject petroleum if the contractor does not have an annual permit granted for that purpose by the Commission (PEPA 2016, Section 31(1)). • Where the ield is a new ield, the Commission is required to approve test production of a petroleum ield. he duration, quantity and other conditions for the test production are decided by the Commission (PEPA 2016, Section 31(7)). • An annual permit can only be granted ater an application in writing to the Commission (PEPA 2016, Section 31(2)). • he application provided to the Commission must set out a long-term production forecast updated from the plan of development and operation and must locate the speciic annual planned level of production within the production forecast (PEPA 2016, Section 31(3)). • he Commission is required to issue an annual production permit stipulating the quantity of petroleum which may be produced or injected (PEPA 2016, Section 31(4)). • he stipulation of the quantity speciied in subsection (4) shall be based on the long-term production schedule in the plan of develop¬ment and operation, unless new information on the reservoir or other new relevant circumstances warrants otherwise (PEPA 2016, Sec- 100 he Regulatory Regime - General Considerations and the Ghana Framework tion 31(5)). • he Commission may require a contractor to submit a report on ield related matters, including alternative schemes for production and where applicable, the injection and the total recovery factor for the various schemes (PEPA 2016, Section 31(8)). • Finally, the Commission may include a permission to lare or vent petroleum as regulated by section 33 in the production permit (PEPA 2016, Section 31(6)). All these actions (request for permission to produce; provision of information about annual and longer term production matters, permission to vent or lare petroleum; information about plans to inject petroleum and/or water) provide a basis for developing an appropriate depletion strategy within the medium-term. Ministerial and Commission directions with respect to reservoir management and depletion policy he rights of intervention outlined below also provide a basis for the eventual development of a depletion strategy. he powers of intervention are as follows: • he Commission may direct a contractor to take appropriate steps to increase or reduce the rate of petroleum production to a rate that will enhance optimum recovery of petroleum from the ield and that will not exceed the capacity of existing production facilities (PEPA 2016, Section 31(9)). • he Commission in consultation with the Minister may also direct the modiication of the long term production schedule approved in accordance with this section when the national interest so requires (PEPA 2016, Section 31(10)). • A requirement of proportionality is placed on the Minister so as to ensure that the commercial interests of particular POCS are not discriminated against. hus, the Minister shall, to the extent possible ensure that the burdens of reduction are shared fairly, where the decision to reduce production relates to several ields as the statute requires him to endeavour to apportion the reduction proportionately among these ields (PEPA 2016, Section 31(11)). • his section also applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 31(12)). DECOMMISSIONING/ABANDONMENT AND RESTORATION General policy considerations his phase involves the decommissioning, abandonment and/or removal of platforms and linked structures. he issues arise at the end of all the phases of operations outlined above. An exploration programme which will not mature into a development or production phase faces this issue as do the other phases which do not evolve further ater a certain point. Fully established production complexes will face this problem ater the life of the ield expires or new platforms come to be installed. he decommissioning of pipelines is also becoming an extremely important issue51 Decommissioning/abandonment is discussed more fully by Chapter 6. he Regulatory Regime - General Considerations and the Ghana Framework 101 THE ROLE OF GNPC UNDER PEPA 2016 The Objectives of GNPC As indicated previously, GNPC is expected to play a signiicant role in Ghana’s petroleum sector. Its mandate under PNDC Law 64 of 1983, (now PNDC Act 64) is to undertake the exploration, development, production and disposal of petroleum for Ghana. Fleshed out in more detail, that translates into the following oicial objectives:52 (a) to promote the exploration and the orderly and planned development of the petroleum resources of Ghana; (b) to ensure that Ghana obtains the greatest possible beneits from the development of its petroleum resources; (c) to obtain the efective transfer to Ghana of appropriate technology relating to petroleum operations; (c) to ensure the training of citizens of Ghana and the development of national capabilities in all aspects of petroleum operations; (d) to ensure that petroleum operations are conducted in such a manner as to prevent adverse efects on the environment, resources and people of Ghana. Reservation of blocks and exploration rights for GNPC It is on this basis, that Section 7(9) of PEPA 2016 provides that the Minister may reserve a block, part of a block or a number of blocks in an open area for the Corporation. Under Section 9(1) the Minister may in consultation with the Commission, grant to a person, a petroleum reconnaissance licence in respect of a deined area, including a reconnaissance licence grants to the licensed person a non¬exclusive right to undertake; data collection including seismic surveying and shallow, drilling, and processing and interpretation or evaluation of petroleum data in the area speciied in the licence. Additionally, the Minister may in a special case grant to a person an exclusive right to undertake reconnaissance activities in a deined area not covered by an existing reconnaissance licence, but the grant of that right does not afect any proprietary rights of the Republic to data or preclude the rights of the Commission or the Corporation to undertake reconnaissance or other petroleum activities within that area. GNPC as a Carried and Paying Participant in Petroleum Agreements Section 10 of PEPA 2016 outlines the legal requirements for Ghana’s petroleum agreements. It also sets out the role that GNPC is expected to play as a participant (both carried and paying) within these agreements. he basic rule under s. 10 is that a body corporate cannot engage in the exploration, development and production of petro¬leum in Ghana, unless such activity is governed by and in accordance with the terms of a petroleum agreement entered into between that body corporate, the Republic of Ghana and the Corporation. As regards participation by GNPC, s. 10(14) provides that a petroleum agreement shall contain a term that with respect to exploration and development, the Corpo¬ration has an automatic right to hold an initial participating carried interest of at least iteen per cent. However, with respect to production, the right of GNPC is an option only. It is an option to acquire an additional participating interest as determined in the petroleum agreement. It is in other words, a matter that will be negotiated on a case by case basis. his production related additional participating interest option must be exercised within a speciied period of time following the declaration of commercial discovery. Apart from exploration costs, which are speciically exempted, it will also be a paying interest in respect of costs incurred in the conduct of petroleum activities (PEPA 2016, Section 10(14)). GNPC as Sole Operator “Sole responsibility” petroleum activities are activities that are undertaken by GNPC under the following terms and conditions: (1) hey take place in an area opened for activity under 102 he Regulatory Regime - General Considerations and the Ghana Framework PEPA s. 7 but which are not covered by a petroleum agreement (PEPA 2016 , Section 11(1)); (2) hey can only take place on the basis of an authorization by the Minister: (PEPA 2016 , Section 11(1)); (3) his authorization must have been approved by Parliament under Article 268 of the Constitution (PEPA 2016, Section 11(2)); (4) Sole responsibility activities can only take place in accordance with annual programmes embedded in long-term exploration and produc¬tion programmes drawn up by the Corporation and approved by the Minister in consultation with the Commission (PEPA 2016, Section 11(3)(b); (5) GNPC may utilize sub-contractors to undertake sole responsibility activity under service contracts with the strict proviso that such sub-contractors are not entitled to any share of the petroleum produced as a result of their operations (PEPA 2016, Section 11(4). Efectively, as a matter of law, production-sharing arrangements are prohibited.53 Pre-emption Section 18 provides that where a contractor enters into an agreement to dispose of all or part of the interest of that contractor directly or indirectly under a petroleum agreement, the Corporation shall have a pre-emption right to acquire the interest on the same terms as agreed with the potential buyer. Where the consideration agreed is not in monetary terms, the Corporation may pay the corresponding monetary value of that consid¬eration. Where a contractor has entered into an agreement to dispose of all or part of the interest of that contractor under a petroleum agree¬ment, the contractor shall notify the Minister, the Commission and the Corporation immediately of the consideration and other terms agreed. he Corporation shall notify the contractor of the election of the Corporation to exercise the pre-emption right within ninety days of the receipt of the notiication. Transfer of assets to GNPC PEPA Section 19 provides for the transfer of assets to the Corporation. his provision is clearly informed by the objectives of GNPC in terms of ensuring that petroleum sector technology is transferred for the beneit of the nation. he provision states that ownership of physical assets purchased, installed or con¬structed by a contractor for petroleum activities shall be transferred to the Corporation at the option of the Corporation either when the full cost has been recovered in accordance with the terms of the petroleum agree¬ment or when the petroleum agreement terminates. he contractor is still entitled to further use of the assets for purposes of operations under the petroleum agreement but remains liable for maintenance, insurance and other costs associated with the use of the assets. Notably, any physical assets that are used by a contractor in a petroleum activity under a capital or inancial lease54 shall be treated as purchased assets and where at least ity percent of the cost of a physical asset has been recovered in accordance with the terms of an existing petroleum agreement, the Corporation may have the title to the asset transferred to the Corporation by the contractor on the payment by the Corporation of the unrecovered portion of the cost of the asset. Absence of special privileges for the Corporation where operating as a contractor under the Act To maintain competitive neutrality with the private sector, the Corporation is to be treated in the same way as any other contractor with respect to the following activities and regulatory or commercial requirements under the delineated sections of the statute: exploration drilling – 24(1)(6); notiication of petroleum discovery and appraisal – 25(17); prudent exploitation – 26(4); preparation of plan of development and operation - 27(15); restrictions on approval of plan of development and operation – 28(5); postponement of development – 29(3); comhe Regulatory Regime - General Considerations and the Ghana Framework 103 mencement of petroleum production – 30(3); production programmes and permits – 31(12); utilisation of associated natural gas – 32(2); restrictions on laring – 33(5); measurement of petroleum obtained – 37(11); Decommissioning plan – 43(8); Plugging and abandonment of well – 46(5); restoration of afected areas – 47(2); 48(2) - liability for decommissioning; use of Ghanaian goods and services - 61(2); and payment of annual fee in respect of acreage – 83(2). Interestingly enough, however, GNPC is not required to establish a decommissioning fund. DOMESTIC SUPPLY REQUIREMENT Ghana imposes a domestic supply requirement on petroleum companies that have reached the production stage. To meet demand in the country, PEPA 2016 deines the domestic supply requirement as the diference between: (1) the total petroleum entitlements of the Republic and the Corporation and (2) the total volume of petroleum in barrels of oil or of gas equivalent of petroleum products that is produced (PEPA 2016, Section 71(3)). he basic rule is that a contractor may export from the Republic, petroleum which the contractor is entitled to export under the terms of a petroleum agreement (PEPA 2016, Section 71(1)). However, to meet domestic supply requirements as determined by the Minister, a contractor shall sell to the Republic at the prevailing market price as prescribed, for the same period a percentage of the petroleum to which the contractor is entitled (PEPA 2016: Section 71(2)). Each party’s obligation to supply petroleum for domestic supply requirement shall not exceed the total of the entitle¬ment of that party under the petroleum agreement. he volume of petroleum to be supplied by the contractor shall be calculated on the basis of the pro rata share of the petroleum to which the contractor is entitled (PEPA 2016 Section 71(4)). Additionally, in the event of war or other emergency afecting energy supplies, the Minister may require a contractor or the Corporation to supply all or part of the quantity of petroleum produced at the prevailing market price to the Republic or any agency of the Republic (PEPA 2016, Section 71(5)). CONTROLS OVER COMPANY TRANSACTIONS Transactions between contractor and affiliates – application of an arms-length standard Transactions between contractors or sub-con¬tractor and ailiates are to be carried out on the basis of prevailing international com¬petitive prices and other terms and conditions that would be fair and reasonable if the transaction had taken place between the contractor or sub-contractor and a non-ailiate (PEPA 2016, Section 88). his requirement mirrors the arms-length standard requirements of ITA 2015. hese are discussed in detail by Chapter 4. Mortgaging of participating interest he borrowing of money against the variety of interests that can be held under a petroleum licence is widespread throughout the industry and takes a variety of forms.55 he most common type of loan within the many options available, is the reserves based loan. It is typically a revolving facility secured by proved reserves as these are lower risk, with borrowing levels determined by a valuation of the assets. As the US Government’s Oice of the Comptroller of the Currency points out, most reserves based loans have “a term of three to ive years and are intended primarily to fund acquisition and development costs for new reserves, which, if successful, increase the reserve valuations and provide increasing cash low for debt service and proits for the company’s shareholders and investors”.56 104 he Regulatory Regime - General Considerations and the Ghana Framework To provide controls and to ensure that all such transactions are disclosed PEPA 2016 provides that a contractor or licensee shall not mortgage a participating interest under a petroleum agreement or a licence without the written approval of the Minister (PEPA 2016, Section 57 (1)). Additionally, in what is a major restriction on the activities of the POCs, the majority of whom are foreign, a contractor or licensee shall not mortgage any participating interest for the beneit of petroleum activities outside Ghana (PEPA 2016, Section 57 (2)). It is clear then that foreign companies may use their participating interests to raise money outside Ghana but only to back activities under their petroleum agreements in Ghana. he statute states that the Minister may also in special circumstances, permit mortgag¬ing of a participating interest for the beneit of petroleum activities in Ghana, even though such activities are not related to the speciic petroleum agreement or licence that secures the loan (PEPA 2016, Section 57 (3)). Any mortgage that is taken out must be registered in the Petroleum Register (PEPA 2016, Section 57 (5)). For the purposes of this section, s. 95 of the statute, deines ‘‘ailiate” to mean a shareholder of a contractor or sub-contrac¬tor who owns ity per cent or more of the shares in the business of the contractor or sub-contractor or an entity which controls, is controlled by or is under common control with the contractor or sub-contractor. Participating interest is also speciically deined and comprises those rights which at any time arise from the petroleum agreement or licence as well as other rights in connection with activities carried out in accor¬dance with the petroleum agreement or licence (PEPA 2016, Section 57 (4)). REVIEW OF TERMS AND CONDITIONS he terms of a petroleum agreement may be reviewed by the parties to the agreement where there is a material change in the circum¬stances that prevailed at (a) the time the agreement was executed, or (b) the last review of the agreement (PEPA 2016, Section 20 (1)). Notably, if the review results in material change, the petroleum agreement must then be subject to re-ratiication by Parliament in accordance with article 268 of the Constitution (PEPA 2016, 20 (2)). his clause although appearing to be quite simple raises the complicated issue of stabilization clauses. It is beyond the scope of this monograph to discuss these issues. CO-ORDINATION OF PETROLEUM ACTIVITIES AND UNITISATION The Policy Considerations In many cases a reservoir lies beneath (or in legal language straddles) two or more licensed areas or concessions. It is economically, commercially and politically more eicient to recover the petroleum by operating the reservoir as a unit, rather than by allowing each rights holder to independently extract the petroleum. Unitisation has developed as the most appropriate way for IOCs and governments to manage the geological uncertainty associated with the reservoir. Unitisation can be voluntary or compulsory. In a statutory or compulsory unitisation, a state regulatory agency has the authority to impose unitisation on a pool of oil or gas. he unit is operated by a single company on behalf of the group. Unitisation also envisages that ater the initial unitization the parties will revisit and re-determine their unit interests. he Regulatory Regime - General Considerations and the Ghana Framework 105 The rule framework for Unitisation under PEPA 2016 he rules are set out clearly and simply and demonstrate a commitment to prudent exploitation: • Where an accumulation of petroleum extends beyond the boundaries of one contract area into one or more other contract areas, the Minister in consultation with the Commission may, for the purpose of ensuring optimum recovery of petroleum from, the accumulation of petroleum, direct the relevant contractors, to enter into an agreement to develop and produce the accumulation of petroleum as a single unit (PEPA 2016, Section 34(1)). • he agreement shall be entered into within a period speciied by the Minister and shall be submitted to the Minister for approval (PEPA 2016, Section 34(2)). • Where two or more accumulations of petroleum are in proximity to one another but are (a) in diferent contract areas, or (b) in one contract area and an area not covered by a petroleum agreement the Minister may require the accumulations of petroleum to be developed and produced in a coordinated manner in order to ensure eicient petro¬leum activities (PEPA 2016, Section 34(3)). • Where an accumulation of petroleum extends beyond the boundaries of a contract area into an area not covered by a petroleum agreement or an authorisation under section 11 (1), the Minister may authorise the Corporation to enter into a contract for the development and production of the accumulation of petroleum, and require the accumulation of petroleum to be developed as a single unit (PEPA 2016, Section 34(4)). • he Minister may stipulate conditions and make appropriate directions to the Corporation and the contractor as prescribed for the unitised development and such conditions, if signiicantly diferent from the conditions of the adjoining contract area, shall be ratiied by Parliament (PEPA 2016, Section 34(5)). Chapter 5 discusses unitisation in more detail. CROSS-BORDER COOPERATION AND UNITIZATION A similar approach is taken with respect to cross-border reservoirs. In such situations, the Republic may, where an accumulation of petroleum extends onto the land or the continental shelf of another country, seek to reach agreement with that other country on the most eicient co-ordination of petroleum activities in connection with that accumulation of petroleum as well as the apportionment of the accumulation of petroleum (PEPA 2016, Section 35). THIRD PARTY USE OF PRODUCTION FACILITIES he Commission may direct that facilities which are owned by a contractor or the Corporation may be used (a) by others if warranted by considerations for eicient opera¬tion and resource management, or (b) for the beneit of society where the use would not unreason¬ably interfere with the usage requirements of the contractor or the Corporation or of any person who has already been granted the right of use (PEPA 2016, Section 36(1)). An agreement on the use of facilities shall be submitted to the Commission for approval and the Commission may, as a condition for approval, modify the tarifs and other conditions agreed between the parties, having due regard to resource management considerations and a reasonable return on investments for the owner (PEPA 2016, Section 36(2)). he Commission may, where an agreement for use is not reached within a reasonable period of time, stipulate the tarifs and other conditions for use, having due regard to resource management consider¬ations and a reasonable return on investments for the owner (PEPA 2016, Section 36(3)). Where required for resource management considerations, the Commission may alter the conditions of a previously approved agree¬ment for third party use to ensure the implementation or continuation of projects (PEPA 2016, Sec106 he Regulatory Regime - General Considerations and the Ghana Framework tion 36(4)). In stipulating new conditions, the Commission shall have due regard to resource management considerations and a reasonable return on investments for the owner (PEPA 2016, Section 36(5)). he rights and obligations of the contractor under this section apply to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 36(6)). TRANSPORTATION, TREATMENT AND STORAGE Section 38 (1) and (2) describe the operation of the required license to install and operate facilities for transportation, treatment and storage of petroleum. Under sub section (1) a person shall not install or operate a facility for transporta¬tion, treatment or storage of petroleum without a license granted by the Minister unless there is an existing right to install and operate the facility derived from the approval of a plan of development and operation, and (2) a person shall not commence installation and operation of a facility if that person does not have a permit granted by the Commission. PEPA Section 39 provides for the application to install and operate facilities. he provision provides that an application for a licence to install and operate a facility for transportation, treatment or storage of petroleum shall specify a description of the facilities and be supported with a scoping report approved in accordance with applicable enactments. he description shall contain detailed information on economic, resources, technical, operational, safety related, commercial, local content and environmental components of the proposed project and a scoping report approved in accordance with applicable enactments. he Minister may require the applicant to provide alternative proposals. Additionally, the Minister may, in consultation with the relevant agencies, grant an exemption from a particular requirement under subsection (1) where the circumstances require. A material deviation or alteration of the terms and precondi¬tions on which an application has been submitted or approved and a signiicant alteration of facilities shall require the prior written approval of the Minister and may require a new or amended application to be submitted for that approval. Additionally, an applicant shall not enter into a contract of signiicant value or commence construction works until the licence has been granted by the Minister. he conditions for granting of a licence to install and operate facilities is handled in Section 40 of PEPA 2016. Under the Section, a licence to install and operate a facility for transportation, treatment or storage of petroleum shall include ownership of the facility; the landing point, routing, dimension and capacity for other pipelines; the main technical description and location for other facilities; and; decommissioning plan. he Minister may, when granting a licence to install and operate a facility, and at any subsequent point in time stipulate tarifs set by the Commission for use of the facility; and direct the tie-in of the facility to another facility; or increase in capacity of the facility; or a modiication of the facility to enable its use for diferent types of petroleum; and the type of petroleum to be transported, treated or stored. he cost of implementation of the directives mentioned may be borne by the party in whose favour the directive was made or shall be taken into account when the tarif is stipulated, and the Minister shall appoint one of the licensees as operator and may approve a change of operator upon the request of the licensees or when there are signiicant reasons to do so. Licenses are granted for a ixed period of time and can be extended on similar or new terms on application to the Minister. he Regulatory Regime - General Considerations and the Ghana Framework 107 Section 41 provides for the landing of petroleum, such that the Minister may in consultation with the Commission and contractor, determine the manner and place in which petroleum is delivered by the contractor and the Corporation. PEPA Section 42 addresses third party use of transportation, treatment and storage facilities. he sections provides that An owner and operator of a facility for the transportation, treatment or storage of petroleum shall grant third party access to the facility on fair, transparent and non-discriminatory terms. Access shall not be to the detriment of the needs of the owner, operator or other users who have already been granted a right of use. Unless otherwise determined by the Commission, the transportation tarifs shall cover the cost incurred by the owner of the pipeline in constructing, inancing, operating and maintaining the pipeline and related facilities, including a reasonable rate of return on the investment, taking into account the risks assumed by the owner; and each user including the owner of the pipeline, shall pay a transportation tarif calculated in relation to the share of the petroleum transported. Additionally, a person is not entitled to the use of a transportation, treat¬ment or storage facility unless that person has entered into an agreement with the owner or operator of the facility. Parties shall submit an agreement on the use of transpor¬tation, treatment and storage facilities to the Commission for approval, and the Commission in consultation with the Minister may, as a condition for approval, change the tarifs and other conditions agreed between the parties, having due regard to resource management consid¬erations while allowing the owner reasonable returns, taking into’%. account, investment and risks. Where an agreement for use is not reached within a reasonable period of time, the Commission in consultation with the Minister may determine the tarifs or other conditions for the use, having regard to resource management considerations while allowing the owner reasonable returns taking into account investments and risks. MEASUREMENT OF PETROLEUM OBTAINED he iscal provisions in PEPA 2016, the Income Tax Act and the various petroleum agreements all depend on accurate measurement of quantities of petroleum. he unitization arrangements that are common to many ields (in Ghana’s case the Jubilee ield) also equally depend on accurate measurement of petroleum. he rule framework is therefore highly prescriptive. Its core elements (to be leshed out by Regulations) are: • A contractor shall measure and analyse the petroleum pro¬duced, transported and sold from a ield by a method customarily used in’ good international petroleum industry practice and in applicable enactments (PEPA 2016, Section 37(1)). • he Commission shall ater consultation with the Standards Authority approve the measurement system which may be veriied as prescribed (PEPA 2016, Section 37(2)). • he Commission shall install facilities to monitor production (PEPA 2016, Section 37(10)). • A contractor shall not alter the (a) method of measurement, or (b) calibration of any equipment used for measurement with¬out the written approval of the Commission (PEPA 2016, Section 37(3)). • he Commission may require an alteration to be made only in the presence of a person authorised by the Commission (PEPA 2016, Section 37(4)). • he Commission may direct that the method of measurement or the calibrated equipment be tested or examined by the relevant agency occasionally, or at the intervals and by the means prescribed (PEPA 2016, Section 37(5)). • A test or examination under subsection (5) may be done in the presence of a person authorised by the Commission (PEPA 2016, Section 37(6)). 108 he Regulatory Regime - General Considerations and the Ghana Framework • Where a measuring method or calibrated equipment is found to be incorrect, that method or calibrated equipment is considered to have existed in that condition during a period that is represented by half of the period from the last occasion when the method or equipment was tested or examined to the date when the method or equipment was found to be incorrect (PEPA 2016, Section 37(7)). • Royalty and any other payments due to the Government, the Commission or the Corporation under the petroleum agreement for that period shall be adjusted accordingly (PEPA 2016, Section 37(8)). • A contractor who knowingly uses an inaccurate measuring method or an uncalibrated equipment commits an ofence and is subject to penalties under section 93 (PEPA 2016, Section 37(9)). • his section applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 37(11)). UTILISATION OF ASSOCIATED NATURAL GAS Any natural gas produced in association with crude oil may be used in petroleum activities as agreed between a contractor and the Corporation, in consultation with the Commission and in accordance with applicable enactments, good petroleum industry practice and approved production plans (PEPA 2016, Section 32(1)). his section applies to the Corporation where it undertakes petroleum activities under section 11(1) (PEPA 2016, Section 32(2)). RESTRICTIONS ON FLARING A person shall not lare or vent petroleum, unless that person is authorised under subsection (2) or (3) (PEPA 2016, Section 33(1)). he Commission shall ater consultation with the Environmental Protection Agency authorise a person to lare or vent petroleum where (a) it is necessary in the interests of normal operational safety of the petroleum activities; (b) it is necessary in order to comply with a requirement imposed under an Act; or (c) it is warranted by exceptional circumstances (PEPA 2016, Section 33(2)). In case of an emergency, and where there is insuficient time to request an authorisation from the Commission, a contractor may lare or vent petroleum without the approval of the Commission under subsection (2), but shall ensure that the laring or venting is done in accordance with prescribed procedure and kept at the lowest level possible (PEPA 2016, Section 33(3)). Where petroleum has been lared or vented in an emergency, the contractor shall immediately inform the Minister, Environmental Protection Agency and the Commission of the event (PEPA 2016, Section 33(4)). his section applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 33(5)). LIABILITY Section 59 of PEPA 2016 states that licensee parties or contractor parties, who jointly hold a petroleum agreement or a licence are jointly and severally responsible to the Republic for the inancial and other obliga¬tions and liabilities arising out of the petroleum activities. However, contractor and a licensee are not jointly and severally responsible for payment of taxes, royalties in cash and additional oil entitlement. PEPA 2016 further provides for the indemniication of the Republic and the Corporation against claims arising from the operations of the licensee, contractor or sub-contractor brought by a third party, noting that “where third party liability is incurred by a person who under¬takes a task for a licensee, contractor, sub-contractor or the he Regulatory Regime - General Considerations and the Ghana Framework 109 Corporation, the licensee, contractor, sub-contractor or the Corporation is liable for damages to the same extent as, and jointly and severally with the person undertaking the task and if applicable, the employer of the person”. LOCAL CONTENT General Observations Local content requirements (LCRs) are imposed by Host States to regulate petroleum investments with the intention of promoting growth of domestic industry and creating local employment. LCRs are an integral part of performance requirements imposed on foreign investors which could include export obligations, location of an industry in a ‘backward’ region and mandatory technology transfer. In the past 60 years, LCRs and other forms of performance requirements have been widely used throughout the world to nurture the growth of infant industries and promote economic development in the host countries. Ghana currently has statutory provisions as per PEPA 2016, a local content policy as well as a Legislative Instrument.57 Employment and training of Ghanaian citizens As regards this aspect of the tableau of options open to Host States, PEPA 2016 requires a licensee, contractor, sub-contractor or the Corporation to ensure that Ghanaian citizens who have the requisite expertise or qualii¬cations with respect to various levels of activities are employed. his must be in accordance with applicable enactments as well as the terms and conditions of the relevant licence, petro¬leum agreement or petroleum sub-contract (PEPA 2016, Section 60(1)). here is also a requirement to prepare and implement plans and programmes to train citizens in all aspects of petroleum activities in accordance with the Local Content Regulations and the terms of the licence, petroleum agreement or petroleum sub-contract (PEPA 2016, Section 60(4)). here is also a power to mandate the employment of Ghanaian citizens in speciic categories and functions (PEPA 2016, Section 60(2)). A person carrying out preferential policies to enhance local content (as relected in in the conditions of service provided for personnel) is enjoined not to engage in any discriminatory practices on grounds of race, tribe, nationality or gender (PEPA 2016, Section 60(3)). Use of Ghanaian goods and services he rules for enhancing local content in this arena are as follows: • A licensee, contractor, sub-contractor or any other allied entity shall acquire materials, equipment, machinery and consumer goods which are produced or provided for in the country by an indigenous Ghanaian company58 and which are of the same or similar quality as foreign materials, equipment, machinery and consumer goods, and are available for sale and delivery in due time at prices which are not more than ten per cent higher than the imported items including transportation and insurance costs and customs charges due (PEPA 2016, Section 61(1)). • A licensee, contractor, sub-contractor or any other allied entity shall contract local service providers to the extent to which the services they provide are similar to those available on the international market and their prices, when subject to the same tax charges, are no more than ten per cent higher than the prices charged by foreign contractors for similar services (PEPA 2016, Section 61(1)). • his section applies to the Corporation where it undertakes petroleum activities under section 11 (1) (PEPA 2016, Section 61(2)). 110 he Regulatory Regime - General Considerations and the Ghana Framework Technology transfer With respect to technology transfer, the Commission is required to encourage and facilitate the formation of joint ventures, partnership and the development of licensing agreements amongst indigenous Ghanaian companies, foreign contractors and service or supply companies interested in the petroleum industry (PEPA 2016, Section 62(1)). his section shall not be interpreted to disable any licensee, contractor, sub-contractor or the Corporation from protecting its com¬petitive position in the petroleum industry (PEPA 2016, Section 62(2)). Local content plans Depending on their position in the value chain, the statute requires that licensee, contractor or sub-contractor prepare and imple¬ment local content plans (PEPA 2016, Section 63(1)). he local content plan shall be submitted to the Commission for approval (PEPA 2016, Section 63(2)). he local content plan includes (a) a plan for fulilling the applicable Ghanaian content require¬ments with respect to the provision of goods and services; (b) a plan for the transfer to the Corporation of technological know-how and skills related to petroleum activities; and (c) a detailed annual recruitment and training programme (PEPA 2016, Section 63(3)). he licensee, contractor or sub-contractor shall submit an annual report on the local content plan, describing the initiatives taken in the preceding year and their results (PEPA 2016, Section 63(4)). Establishment of the Local Content Fund A Local Content Fund is to be established (PEPA 2016, Section 64). he object of the Fund is to provide inancial resources for citizens and indigenous Ghanaian companies engaged in petroleum activities (PEPA 2016, Section 65(1)). For the purposes of achieving the object of the Fund, moneys from the Fund shall be applied to (a) education, training, research and development in petroleum activities for Ghanaian citizens, indigenous Ghanaian com¬panies and Ghanaian institutions of learning; and (b) loans on a competitive basis to small and medium scale enterprises59 to support their participation in petroleum activities (PEPA 2016, Section 65(2)). Sources of money for and management of the Fund he sources of money for the Fund include (a) contributions from a contractor as agreed in a petroleum agreement; (b) contributions from a sub-contractor of the sum of one per cent of the total consideration payable by the contractor or licensee for every contract; (c) moneys approved by Parliament; and (d) grants (PEPA 2016, Section 66(1)). he moneys of the Fund shall be paid into a bank account opened by the Board of the Commission with the approval of the Controller and Accountant-General (PEPA 2016, Section 66(2)). Payments from the Fund shall be signed by (a) the chairperson of the Board and the Chief Executive of the Commission; or (b) the chairperson of the Board and one other member of the Local Content Committee (PEPA 2016, Section 66(3)). he Fund shall be administered by the Minister and the Local Content Committee set up under section 8 of the Petroleum Commis¬sion Act, 2011 (Act 821) (PEPA 2016, Section 67(1)). he Minister and the Local Content Committee shall for the purpose of administering the Fund (a) formulate policies to generate money for the Fund; (b) determine the allocations to be made towards the objectives of the Fund; and (c) determine the annual targets of the Fund (PEPA 2016, Section 67(2)). he Minister shall approve the annual budget of the Fund (PEPA 2016, Section 67(3)). he Local Content Committee may invest a part of the moneys of the Fund that it considers appropriate in the manner approved by the Minister in consultation with the Minister responsible for Finance (PEPA 2016, Section 67(4)). he Fund is exempt from payment of tax (PEPA 2016, Section 67(5)). he Regulatory Regime - General Considerations and the Ghana Framework 111 Reporting and accountability on local content issues he Local Content Committee shall keep books of account and proper records in relation to them in the form approved by the Auditor- General (PEPA 2016, Section 68(1)). he Commission shall submit the accounts of the Fund to the Auditor-General for audit within three months ater the end of the inancial year (PEPA 2016, Section 68(2)). he Auditor-General shall not later than three months ater the receipt of the accounts, audit the accounts and forward a copy of the audit report to the Minister (PEPA 2016, Section 68(3)). he Commission shall, within one month ater the receipt of the audit report, submit an annual report covering the operations of the Fund for the year to which the report relates to the Minister (PEPA 2016, Section 69(1)). he annual report shall include the report of the Auditor- General (PEPA 2016, Section 69(2)). he Minister shall, within one month ater the receipt of the annual report, submit the report to Parliament with a statement that the Minister considers necessary (PEPA 2016, Section 69(3)). THE WTO COMPATIBILITY OF GHANA’S LOCAL CONTENT PROVISIONS60 Although the matter has not yet been tested legally in WTO fora against Ghana, there is a very strong argument, that Ghana’s local content requirements violate Ghana’s national treatment obligations towards other countries, under the General Agreement on Tarifs and Trade (GATT) 1994 and the Agreement on Trade-Related Investment Measures (TRIMs Agreement) 1995. As the 2014 survey of the issue by Hestermeyer and Nielsen, shows, the GATT case-law on this issue is extensive.61 he GATT rules that are relevant are: • Article III:1 of the GATT which provides that internal measures ‘should not be applied to imported or domestic products so as to aford protection to domestic production’. T= • Article III: 4 of GATT (which prohibits measures that discriminate in favor of locally-produced products versus imports). he text of GATT Article III:4 provides in part that imported products must be accorded “treatment no less favourable” than that accorded to “like products of national origin in respect of all laws, regulations and requirements afecting their internal sale, ofering for sale, purchase, transportation, distribution or use”. • Article 2 of TRIMs (which prohibits trade-related investment measures that are inconsistent with GATT Article III). he text of Article 2 of the TRIMs Agreement provides that “no Member shall apply any TRIM that is inconsistent with the provisions of Article III… of GATT 1994”. he annex to the TRIMs Agreement also includes an “illustrative list” of measures that are inconsistent with GATT Article III:4, including “those which are mandatory or enforceable under domestic law or under administrative rulings, or compliance with which is necessary to obtain an advantage, and which require…the purchase or use by an enterprise of products of domestic origin or from any domestic source…”. Although seldom adjudicated on in the local content context,62 Article III: 5 of the GATT is also relevant. Paragraph 5 of Article III of the GATT reads: No contracting party shall establish or maintain any internal quantitative regulation relating to the mixture, processing or use of products in speciied amounts or proportions which requires, directly or indirectly, that any speciied amount or proportion of any product which is the subject of the regulation must be supplied from domestic sources. Moreover, no contracting party shall otherwise apply internal quantitative regulations in a manner contrary to the principles set forth in paragraph 1. 112 he Regulatory Regime - General Considerations and the Ghana Framework To the extent that subsidies are provided to domestic industry by government so as to meet local content objectives, Ghana’s local content rules and implementing programmes may also violate Articles 3 and 5 of the WTO Agreement on Subsidies and Countervailing Measures (SCM Agreement). here is an existing critique of the extent to which these WTO disciplines constrain development in countries that wish to use local content to advance their economies and societies.63 At the same time, free trade oriented policy groups in the developed countries see local content requirements as a threat to free trade and are not likely to relax their opposition to the use of local content requirements.64 he United States, EU and Japan also consistently push an anti-LCR agenda within the WTO. DATA OWNERSHIP, REPORTING, PROVISION OF INFORMATION & CONFIDENTIALITY Given its high levels of uncertainty, information and data are central to reducing risk in arguably OOGP From the government point of view possession of high quality G & G information at the pre-exploration phase is essential because it allows the government to devise an overall strategy with respect to disposal of blocks. High quality information allows the government to negotiate more efective MWOs as well as assess MWOs either with respect to one entity or on a comparative basis. High quality information delivered in a timely manner also allows the government to re-organise MWO obligations where this is required. hus for example MWO for a particular block held by Firm A may be re-negotiated on the basis of timely information delivered by Firm B working on an adjacent block. he most important of these normally include: 1. 4. Submission to the regulatory authority of the rights holder’s annual work program; timing and procedures for its approval; 2. 5. Prompt supply to the regulatory authority of quality copies of all geological, geophysical, well and other technical data developed for a contract area, subject of a petroleum agreement, by the rights-holder; 3. 6. Rights-holder’s guarantee of reasonable and timely access for the regulatory authority personnel to all areas upon which petroleum operations are conducted under a petroleum agreement. Ownership of petroleum data is outlined in Section 52 of PEPA 2016. he section provides that data and information obtained by a licensee, contractor, sub-contractor or the Corporation as a result of petroleum activities and the geological, geophysical, technical, inancial and economic reports, studies, interpretations and analyses prepared by or on behalf of a licensee, a contractor, sub-contractor or the Corporation in connection with petroleum activities shall be the property of the Republic. A licensee, contractor or sub-contractor may, for the duration of a licence or petroleum agreement, use the data and information obtained however, the licensee, contractor, sub-contractor or Corporation shall provide to the Commission data and information as well as the reports, studies, interpretations and analyses. he Commission may permit a licensee, contractor, sub¬contractor or the Corporation to market the right of use to geological, geophysical and technical data, reports, studies and interpretations on terms to be agreed and may also provide information to the Corporation to use. he Regulatory Regime - General Considerations and the Ghana Framework 113 Section 53 of PEPA 2016 states that a licensee, contractor, sub-contractor and the Corporation shall maintain complete and accurate records in Ghana of the petroleum activities carried out by the licensee, contractor, sub-contractor or the Corporation shall also complete and keep accurate books of account, records and registers relating to these activities. Written consent of the Commission require to export or permit the retention or exportation of data, documents or geological and reservoir samples and in the event that data, documents or samples are exported, the con¬tractor, sub-contractor or licensee shall return the data, documents or samples to this country forthwith at the written request of the Commission. he data is conidential and shall not disclose the data to a third party without permission from the Commission except as may otherwise be provided in accordance with the terms of a petroleum agreement or petroleum sub-contract. Section 54 of PEPA 2016 requires a contractor and the Corporation to report to the Commission any information prescribed. Under Section 55, the Minister or the Commission may request a person conducting petroleum activities to provide information relevant to the activities. A petroleum register is maintained by the Commission and in accordance with Section 56, the register is open to the public. RIGHTS OF SUPERVISION AND AUDITING he Commission may, in the performance of its functions, authorise a person to supervise or inspect petroleum activities to ensure that the activities are carried out in accordance with this Act (PEPA 2016, Section 51 (1)). he Commission or the person authorised by the Commission under subsection (1) may (a) enter any area, structure, platform, vehicle, installation, vessel, aircrat, facility, oice or building used for petroleum activities; (b) inspect, test or audit the works, equipment, operations, records, registers and inancial accounts of a licensee, con¬tractor, sub-contractor or the Corporation that is related to or used in petroleum activities; (c) in collaboration with relevant authorities, take or remove samples of petroleum, water or other substance for the purposes of analysis or testing; (d) inspect, take extracts from, or make copies of any docu¬ment relating to the petroleum activities; (e) direct a vessel or a mobile facility to be brought to a port in Ghana when considered necessary for the purpose of super¬vision or inspection under this Act; or (f) conduct examinations, inquiries and relevant activities that are necessary to ensure that the provisions of this Act, the Regulations, the petroleum agreement and any licence are being complied with (PEPA 2016, Section 51 (2)). A person subject to supervision or inspection under this Act shall, when so demanded by the Commission or a person authorised by the Commission and in spite of any requirement for conidentiality, pro¬vide information that is considered necessary for the performance of the supervision or inspection (PEPA 2016, Section 51 (3)). A licensee, contractor, sub-contractor or the Corporation shall provide the Commission or the person authorised by the Commission under subsection (1) with reasonable facilities and assistance to enable the efective and timely performance of the supervisory or inspection functions under this section (PEPA 2016, Section 51 (4)). he Commission may issue directives as are necessary for the implementation of this section (PEPA 2016, Section 51 (5)). he Commission may require the licensee, contractor, sub-con¬tractor or the Corporation being supervised or inspected under this section to bear the expenses related to the supervision or inspection (PEPA 2016, Section 51 (6)). 114 he Regulatory Regime - General Considerations and the Ghana Framework PETROLEUM OPERATING STANDARDS OR BEST OILFIELD PRACTICE A person conducting petroleum activities under this Act shall conduct petroleum activities in a prudent manner and in accordance with applicable enactments, standards, best international practice65 and sound economic principles (PEPA 2016, Section 50(1)). Prudent petroleum activities as prescribed in subsection (1) include reasonable steps to (a) optimise the ultimate recovery of petroleum from a petro¬leum ield; (b) prevent waste of petroleum; (c) secure the health, safety and welfare of persons and com¬munities; and (d) protect the environment and ensure its sustainability (PEPA 2016, Section 50(2)). Petroleum activities shall be conducted in accordance with directives given, restrictions imposed or requirements made by the Minister, the Commission and other relevant agencies (PEPA 2016, Section 50(3)). he Regulatory Regime - General Considerations and the Ghana Framework 115 CHAPTER SUMMARY his Chapter has presented the current legal framework governing exploration and production activity in Ghana. General considerations and international best practice have provided the backdrop for a thorough presentation of the key statute, the recently promulgated Petroleum Production and Exploration Act 2016. he statute is comprehensive and relects international best practice as it covers all the key matters that need to be addressed as a matter of general legislation, within a system which uses petroleum agreements based on the modernised concession or tax/royalty approach. Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. See generally, William Onorato, Legislative Frameworks used to foster petroleum development AMPLA Yearbook 1997, 247-285, Kamal Hossain, Law and Policy in Petroleum Development (1997) especially at Chapters III-V; Raj Kumar, Taxation for a cyclical industry, 17 Resources Policy 1991 133-148; Dutch disease refers to a situation in which the discovery and exploitation of petroleum leads to the overvaluation of a country’s exchange rate with the efect that the country’s exports become more expensive and the imports cheaper. his in turn leads to a contraction of the non-petroleum sectors of the economy as exports from these sectors fall and imports which can be bought easily using oil revenues replace domestic production. With an industrialised country, it implies a decline in the manufacturing sector whilst for a less-industrialised country it leads to major problems in agriculture. he term comes from the experience of the Dutch economy ater huge gas inds in the 20the century. See Paul Stevens Oil and Gas Dictionary (1983) 64. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 134 Note for instance, the recent international uproar when Royal Dutch Shell reduced its assessment of its reserves: (1) Reserves writedown shrinks Shell proits - February 05, 2004 http://www.rte.ie/business/2004/0205/shell.html; (2) Shell’s inance chief quits on reserves - April 19, 2004 - http://www.rte.ie/ business/2004/0419/shell.html Raghavendra D. Rao ‘Modellingoptimal exploitation of petroleum resources in India’ Resources Policy 28 (2002) 133–144, 134. Raghavendra D. Rao ‘Modellingoptimal exploitation of petroleum resources in India’ Resources Policy 28 (2002) 133–144, 134. Raghavendra D. Rao ‘Modellingoptimal exploitation of petroleum resources in India’ Resources Policy 28 (2002) 133–144, 134. he total amount of crude oil and natural gas produced from a reservoir during any time period should meet the speciied Production to Reserve ratio (P/R). his is done so as to maintain a balance between production and the available recoverable reserve during any given time period. Chapters 1 and 2 discussed the diference between oil and gas, noting in particular the diiculties of commercialising gas discoveries meaning that in many cases exploration resources which efectively lead to the inding of gas are efectively misspent exploration resources. Raghavendra D. Rao ‘Modelling optimal exploitation of petroleum resources in India’ Resources Policy 28 (2002) 133–144, 134 Huguette Blanc0 and Louis R. Zanibbi, Financial planning and analysis techniques of mining irms A note on canadian practice– 18 Resources Policy June 1992 84-91 Raj Kumar, Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 134. Hossain 44-46; Onorato 263-268, 272, 275-277 Hossain 46-48, Onorato 263-268, 272, 275-277 Hossain 49-50 Hossain 52-54; Onorato 255-259, 268-271, Onorato 277-281 See generally Chapter 6 of this monograph. he United States has an extensive regime of private onshore ownership of oil production alongside a regime of Federal government ownership ( outer continental shelf and Federal onshore lands); and State ownership (inner continental shelf and State onshore lands). he Federal government also has plenary authority over the States in the ofshore area. See generally, William Onorato, Legislative Frameworks used to foster petroleum development AMPLA Yearbook 1997, 247-285, 274; Kamal Hossain, Law and Policy in Petroleum Development (1997) especially at Chapters III-V; Tordo, S. (2007). “Fiscal Systems for Hydrocarbons: Design Issues”. World Bank WorkingPaper 123, Washington, D.C.; Tordo, S. (2009). “Exploration and Production Rights: Allocation Strategies 116 he Regulatory Regime - General Considerations and the Ghana Framework and Design Issues.” World Bank Working Paper No. 179. World Bank, Washington, DC. 20. See Onorato, 263-265, Hossain, Chapter 4, Tordo (2009) Chapter 2. 21. he transparency and broader spectrum of competition are the strengths of the bid tender process. he oten-stated fear of direct negotiations stems from the possibility of both corruption and sharp practice by either the State or applicant parties. 22. Onorato, 264 23. Onorato 265; Tordo, (2009) Chapter 2 and then at 38-45. 24. Onorato, 265. 25. Designing auctions for ofshore petroleum lease allocation - Kjell J. Sunneva Resources Policy 26 (2000) 3–16 at 5. 26. Section 90, PEPA 2016, concerned with interpretation states, that the term “contract area” means the area covered by the petroleum agree¬ment in which a contractor is authorised to explore for, develop and produce petroleum but excludes portions of the area in respect of which a contractor’s rights are from time to time relinquished or surrendered. 27. Section 90, PEPA 2016, concerned with interpretation states, that the term “block” means an area that is approximately six hundred and eighty-ive square kilometres as depicted on the reference map prepared by the Minister 28. Hossain, 112-114; James B. Ramsey, he economics of oil exploration: a probability-of-ruin approach Energy Economics. January 1980;C. F. Mason, Learning from exploration information; the case of uranium Resources and Energy (1985) 243-257; R. J. Gilbert, he social and private value of exploration information, Department of Economics Working paper No. 91, (University of California, Berkely CA); R. J. Gilbert, R. J. 1979 Search strategies and private incentives for resource exploitation in R. Pindyck (ed.) Advances in the economics of energy and resources Vol II. (JAI Press, Greenwich Ct). 29. Hossain points out that: “while it is broadly true that at the exploration stage there is less likelihood that contractors will pursue course of action inconsistent with the interests of the host countries, a number of situations have been pointed out… where the interest of the the government partner and the company may diverge, as for example where the geophysical data shows indications of a small reservoir or one containing only gas. Further, a company faced with budgetary constraints in the context of its global operations may be inclined to commit less of its resources to a particular country than geological indications merit” Hossain, 112. 30. Sunnnevag, 27. 31. Chapter 2 discussed aspects of the problem of over-rapid depletion afecting natural drive such that not enough petroleum is eventually recovered. Exploration can help provide information to manage the reservoir depletion process. 32. Sunnevag, 27. 33. Hossain, 112; 34. Hossain, 112; 35. See Hossain, 114. 36. Onorato, 268 37. Onorato, 275. 38. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 116 39. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 116 40. Onorato, 275, 41. For example, a clause which excuses non-attainment of depth criteria due to impenetrable formations, economic basement or lack of further prospectivity or allows substitution of work such as the contractor being allowed to submit seismic data as a substitute in a situation where the contractor has been unable to perform the initial MWO - this type of clause is found for example in Gulf Coast agreements in the United States Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 116. 42. See Dur, 116-117. 43. A lexible contract will express a global work commitment without a speciic minimum expenditure obligation and will allow the entire exploration phase for performance. A more restrictive contract will stipulate speciic work commitments in limited time periods and with deinite expenditure obligations. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 116 44. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 117 45. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 117 46. Onorato, 268; Hossain, 44-46, 77-97 & 112-118. 47. Onorato, 268. 48. Stan Dur Negotiating PSC Terms Petroleum Accounting and Financial Management 115-124, 115 49. For the purposes of Section 25, “commercial discovery” means the requirement on the part of the contractor to demonstrate to the government that a discovery would be suiciently proitable for both the contractor and the Republic to merit development. he Regulatory Regime - General Considerations and the Ghana Framework 117 50. See generally, Tordo (2009) at 5-6. 51. See J. B. Hinwood and L.R. Dennis, “Environmental issues in pipeline facility abandonment” he APPEA Journal 1998, Part 2 172-177. 52. See generally, http://www.gnpcghana.com/overview.html 53. he question is whether this a priori prohibition of production sharing arrangements is appropriate as there may be situations where a production sharing approach may be the better way to engage the services of a sub-contractor with respect to risky areas. 54. For the purposes of the above sections, “capital or inancing lease” means a lease that meets one or more of the following criteria the lease term is greater than seventy-ive per cent of the economic life of the asset, the lease contains an option to purchase the asset for less than the fair market value, the ownership of the subject of the lease is trans¬ferred to the lessee at the end of the lease term, and/or the present value of the lease payments exceeds ninety percent of the fair market value. 55. For transaction types, see generally Oice of the Comptroller of the Currency (OCC) Oil and Gas Exploration and Production Lending (2016) at 9. 56. See Oice of the Comptroller of the Currency (OCC) Oil and Gas Exploration and Production Lending (2016) at 10. 57. Petroleum (Local Content and Local Participation) Regulations, 2013 (LI 2204). 58. Under, s. 95 of the statute,“indigenous Ghanaian company” means a company incorpo¬rated under the Companies Act, 1963 (Act 179) which has at least ity-one per cent of its equity owned by a citizen of Ghana; and has Ghanaian citizens holding at least eighty per¬cent of executive and senior management positions and one hundred per cent of the non-managerial positions and other positions. 59. Under s. 95 of the statute, the term “small and medium enterprises” means an industry, project, undertaking or economic activity that employs not more than one hundred persons with an asset base that is not more than the Ghana Cedi equivalent of two million United States Dollars excluding land or buildings; 60. See generally, Hestermeyer, Holger P. and Nielsen, Laura, he Legality of Local Content Measures under WTO Law 48(3) Journal of World Trade 553-591 (2014), with permission of Kluwer Law International; University of Copenhagen Faculty of Law Research Paper No. 2015-4; King’s College London Law School Research Paper No. 2015-22. Available at SSRN: https://ssrn.com/abstract=2597969 61. See particularly the discussion at 566-576, supra. 62. On this, see Hestermeyer and Holger at 573-574, supra. 63. See for instance, Nwapi, Chilenye, “Neoliberal Extractive Resource Governance Frameworks and Interregional Economic Inequality in the Global South: Strengthening Regional Competitiveness through Local Content Policies” in International Development Economics Associates (IDEAS), eds., Inequality, Democracy and Development under Neoliberalism and Beyond (New Delhi: IDEAS, 2015) 271-286; DiCaprio, Alisa, and Kevin P. Gallagher. “he WTO and the Shrinking of Development Space—How Big is the Bite?” Journal of World Investment and Trade, Volume 7, no. 5, October 2006. 64. See, for instance, Hubauer, Gary Clyde, Jefrey J. Schott, Cathleen Cimino, Martin Vieiro, and Erika Wada. (2013) Local Content Requirements: A Global Problem. Policy Analyses Washington: Peterson Institute for International Economics; Cathleen Cimino, Gary Clyde Hubauer, and Jefrey J. Schott (2014) “A Proposed Code to Discipline Local Content Requirements.” Policy Brief, Peterson Institute for International Economics. 65. his is arguably a reference to the term best or good oilield practice. hat term is deined in some statutes as follows as for example, with s. 6 of the Australian statute, the Ofshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic.) deines good oilield practice means all those things that are generally accepted as good and safe in— (a) the carrying on of exploration for petroleum; or (b) petroleum recovery operations. See also Mike Bunter, World-wide standards of Good Oilield Practice - he impact of the blow-out, deaths and spill at the BP Macondo well, MC 252/1-01, US Gulf of Mexico https://www.ogel.org/article. asp?key=3356 118 he Regulatory Regime - General Considerations and the Ghana Framework he Regulatory Regime - General Considerations and the Ghana Framework 119 120 he Regulatory Regime - General Considerations and the Ghana Framework 4 4 FISCAL ARRANGEMENTS GENERAL CONSIDERATIONS AND THE GHANA REGIME Fiscal Arrangments - General Considerations and the Ghana Regime 121 INTRODUCTION & OBJECTIVES OF CHAPTER here are many economic considerations in OOGP. he perspective of government is to maximize its take from the industry, whilst from the corporate point of view, economics has diferent functions depending on whether matters are being addressed at the level of the project or the overall corporate strategy of the company. his chapter introduces some basic concepts and ideas. THE PUBLIC POLICY ECONOMICS OF PETROLEUM: SOME KEY CONCEPTS Regulatory Economics: The Economic rent concept Easily the most practically important economic concept in OOGP is that of economic rent. he concept of economic rent as applied to the production of petroleum and extraction of other natural resources suggests that in some if not many situations, the person holding title to extract and dispose of the resource may receive a proit that exceeds the normal return on invested capital. he term economic rent is used to refer to this premium. Another way of expressing it is that Economic Rent constitutes a payment to a factor of production that is in excess of the minimum payment necessary to have the factor supplied. he Concept of Economic Rent Natural resource extraction typically involves extraction of depletable natural resources from sites of varying productivity and cost structure. It is this which gives rise to what conventional economic theory calls an economic rent. he concept is based on the following propositions: • that there are four factors of production1 all of which require compensation for their input into the production process; • that given a particular price for the inal good, economic rents are returns over and above the “normal” return which an investor would accept to undertake the particular investment - the lower the costs of an owner/site the higher the rents which can accrue An economic rent is said to be present when the present value of all revenue exceeds the present of all costs, including normal proit. Economic rent is sometimes called Riccardian rent ater the classical economist who proposed the concept. Viewed pictorially as in the graphic below, economic rent as a segment of total economic value sits over and above the segment delineated (Costs + Investors return) which in turn has three elements: • the investment or capital Expenditure (CAPEX); • the operating costs or Operating Expenditure (OPEX); • the normal return or proits an investor would get for that type of project. 122 Fiscal Arrangments - General Considerations and the Ghana Regime Figure 1 Concept of economic rent 1 It is crucial to note that the way in which costs are deined in the economic rent analysis – normal2 returns to the investor are also included in the concept of costs. On this basis, the World Bank has deined economic rent in the extractive industries as follows: he economic rent of mining “is the value of the product less all the direct and indirect costs of production, including the minimum return to capital required to make an investor commit funds in the irst place”3 . Translated to the OOGP context the concept has the following elements: • the oil and gas resources in the ground belong to the State (landowner) with the companies extracting such resources (capital & enterprise).undertaking the task for the State • the companies extracting the petroleum resources should receive a “normal” remuneration to capital and other resources needed for undertaking the task on behalf of the State; • the land-ownership based value of the petroleum lease should go to the resource owner4 • Where there is a high resource rent, unless there are government policies to recover resource rent, these returns will accrue as “windfall” proits to the extraction companies (capital & enterprise) with the consequence that the owner of the resource, the State is penalised. Basic technical aspects of the concept of economic rent he key to understanding the concept is the proposition that given a uniform inal price (as with p below) signiicant returns can accrue to those enterprises whose costs are extremely low or moderately low in comparison to the overall price that it is possible to obtain for the particular product or commodity. On the other hand irms with higher costs may be unable to beneit from the opportunity to appropriate rents. Fiscal Arrangments - General Considerations and the Ghana Regime 123 Figure 2 Concept of economic rent 25 he concept is further explained by the graphic6 above, in which C is the marginal irm but A and B are irms to which economic rents accrue. It can be seen that at market price p, irms A and B (see shaded area) are earning an economic rent, which is represented by the shaded area. Producer B faces less favorable site characteristics and thus produces at higher costs than producer A, but still exhibits lower costs than the marginal competitor, C, who just covers his average/marginal costs at market price p7 . he concept of economic rent (although currently incorporated within the models of neo-classical economics)8 comes from the classical school of economics or more accurately the political economy school of the 18th and 19th centuries9 In that school an economic rent was deined as a surplus value, that is, the diference between the price at which a good is sold and the production costs of that good. In Ricardo’s classical example, economic rent accrued diferentially due to the diferent productivity of agricultural production sites. A site with less favourable characteristics would in the Ricardian view face higher production costs, and thus earn less (the assumption underlying the proposition is that there is a free market with exogenously given prices and that all things are equal)10 . As shown in the graphic above, the marginal irm (Firm C) will be able to merely cover its production costs11 and will not receive any economic rent. Finally it should be noted that economic rent is typically divided into three diferent kinds: diferential, scarcity, and quasi-rent. Diferential rent arises because of innate diferences of production sites, as described in the graphic below, whereas scarcity rent emanates from excess demand for the good. Both kinds of rent arise from the characteristics of the natural resource and their sum is therefore called ‘resource rent’. In contrast, quasi-rent is deined as an economic value, which can be attributed to a irm’s investments in its products. Such investments could be: advertising, speciic training of the employees, and so forth. hese expenses can result in a higher price (brand) or lower costs (better technology). Quasi-rents are thus rents, which accrue due to managerial investments in the products and should be let with the company in order to have it make these investments. he concern with economic rent is in fact extremely important since in general extraction of minerals and petroleum is characterised by the land owner transferring their powers over the land in greater or lesser part to the resource extractor and associated interests. he concept seeks to more precisely specify the return that should low back to the landowner ater all costs to the other factors of production have been met. 124 Fiscal Arrangments - General Considerations and the Ghana Regime The State as resource owner and the right to returns from ownership It has been demonstrated above, that the concept of economic rent (and the right of the owner of land12 to claw it back) seeks to ensure that neither capital nor enterprise appropriate what in the dominant economic model rightly belongs to the owner of land. he economic rent concept has been translated at the law and policy level into the basic and widely accepted tenet in the minerals and petroleum sector that the State as resource owner has the right to claw back all or part of this economic rent from the companies which extract the natural resource. he economic rent is in that sense a reward to a particular State as landowner for the geological/historical/geographical accidents which have led to it possessing territory with high mineral prospectivity. The Concept of User Cost he concept of user cost further explains why it can be said that the State is penalised and should seek to recover at least part of the economic rent. he user cost concept focuses attention on the costs of extracting the resource now or at a later time period – a choice which has consequences. User cost with respect to a depletable resource is deined in conventional economics as the opportunity cost of the non-availability of that natural resource at a future date which results from extracting that resource today rather than keeping it in the ground13 . According to the inluential neo-classical theorisation of this situation14 , the person who owns a resource which is used up in an earlier time period arguably foregoes the possibility that the value of the resource will rise in a later time period and thus also gives up the extra returns that will come from such a rise15 . By extracting the resource now (or leasing out the right to extract now to a third party) they are giving up the option to remove it later and thus deserve some compensation for foregoing the option. To allow the extractor of the resource (the OOGP company) to fully capture all economic value associated with that resource16 is providing the extractor with unearned returns over and above a “normal” return. It is thus justiied for the State which allows a resource to be depleted in an earlier time period to seek to use royalties or taxation to recover some of the foregone economic value arising from the decision to exploit now rather than later. Investing the Resource Rent – the Hartwick Rule and Economic Sustainability A further rationale ofered for resource rent taxation as a means of extracting the economic rent is the need to ensure economic sustainability when the resource base of the country is a depletable resource. he argument is that taxing resource rent is justiied in part because it provides revenues to reinvest in other economic activities a rational and prudent response to the reality of progressive depletion17. Applying the Resource Rent Concept to OOGP As can be seen in the graphics below it is possible (at least conceptually) to analyse the price fetched by a barrel of oil to show the diferent value components incorporated within the price at which it is sold and thereby isolate the economic rent. It is also possible to show how particular pools of oil, especially larger deposits fetch higher rents whilst smaller pools fetch less. It is also possible to analyse the arrangements between governments and companies in ways which show hosw the rent is extracted from the company. Fiscal Arrangments - General Considerations and the Ghana Regime 125 Figure 3 – Applying the resource rent concept to OOGP Economic Rent Concept Applied to Price of a Barrel of Oil18 Concept of economic rent applied to petroleum ields/ pools Figure 4 - Economic or Resource Rent Concept Applied to an Oil Field 126 Fiscal Arrangments - General Considerations and the Ghana Regime At the purely technical level the diference in costs between the larger and smaller pools is simply because they have a much larger energy level (natural drive – Chapter 2) pushing the oil and associated gas to the surface. he consequence of this is that for example, as compared with enterprises in the North Sea or the United States, enterprises drawing from the large oil pools of Saudi Arabia19 deploy much less resources in cost terms given the intensity of the natural drives that can be called upon to drive petroleum to the surface (See Chapter 2 on natural drive mechanisms). As a consequence it is estimated that Saudi liting costs20 are around US$1.00-$2.00 per barrel whilst it also has extremely low exploration/inding costs21 estimated at around 10 cents per barrel22. By contrast liting costs in the North Sea and the Gulf of Mexico are around US$3-$4 a barrel. Mechanisms and criteria for extracting the resource rent As seen above resource rent is not attributable to efort by any of the other factors of production - it is linked with the resource and its owner and belongs, therefore, to the owner of the resource. However it still needs be at least partly extracted from capital and enterprise given that in the nature of things the rent is appropriated by the enterprise (the OOGP company) once it is given a licence and begins to extract the resource and then proceeds to sell it. Despite the theory, the reality is that full extraction of the resource rent is not possible given that the resource owner does not have full information as to the total size of the rent (capital and operating costs, normal returns to the investor, supernormal proit etc.). In the absence of such knowledge a reasonable sharing mechanism has to be found, which redistributes part of the economic rent to the owner of the resource without destroying the incentives for the other factors of production to contribute to extraction of the resource. he principal mechanism that has been devised is the resource rent tax which is of two principal types23: • the classical resource rent tax (RRT) which looks more closely at losses and expenses and taxes projects, enterprises or consortia ater a pre-speciied threshold is met and at a speciied rate24 • he cash low tax, a tax on cash lows above a certain level and known as a Brown tax25 Other “government take” instruments can also extract the resource rent as well (eg. royalties and income tax). However the general consensus is that a specially designed tax is better than the other forms of government take. It is also widely agreed that resource rent taxes need to be implemented in ways that do not introduce distortions into enterprise decisions; otherwise, total resource value will be reduced26. he question is how best to formulate “neutral” tax incentives for investment. Fiscal Arrangments - General Considerations and the Ghana Regime 127 Figure 5 - Economic Rent Concept and the concept of Government Take Source: Johnston, D., International Petroleum Fiscal Systems and Production Sharing Contracts 56. Investing the Rent from OOGP: An Example27 Suppose a country has an oil ield containing 100 barrels of oil. his constitutes its “natural capital.” he country can hire an international oil company to extract its oil at a cost of $1 a barrel. his cost includes payments for labour, intermediate inputs like electricity, for accounting and marketing services, and for the use of capital equipment needed to extract the oil. Since oil is a scarce resource, the price of oil on the world market gets bid up to $2 a barrel, which is well above the $1 a barrel cost of extraction. his scarcity results in a resource rent of $1 a barrel from its production. he country has a choice of extracting the oil (or some part of it) now for the economic beneit of the current generation, or leaving it in the ground for future generations to extract and sell. If all 100 barrels are extracted in one year, the country earns an economic proit, or resource rent, of $100 (the revenue of $200 minus extraction costs of $100), but leaves no oil for future generations. What might the country do with this proit? he country has a choice of either spending it on current consumption or investing it in other economic activities that will generate income and employment in the future. If the resource rent is used only for consumption by the current population—for example, buying television sets for all the country’s citizens—then nothing is let for future generations. Future generations are worse of than if the oil had been let in the ground because there is nothing let for them to extract. On the other hand, the country could invest the $100 (or some part of it) in an investment fund to replace the now-depleted natural capital. As long as this investment is intact, it will generate income, beneiting both current and future generations. he current generation will not have as much to spend as if they had the entire $100 proit, but this policy ensures that all citizens, 128 Fiscal Arrangments - General Considerations and the Ghana Regime current and future, will have some beneit from the country’s natural capital. An example of such a fund is the Permanent Fund created from oil revenues in the state of Alaska in the U.S. Part of the resource rent is held in an investment fund and the annual proceeds from this fund, above the amount needed to keep the real value of the fund intact, are distributed to all residents of the state. hus if it costs $1 a barrel to produce a barrel of oil out of existing wells, then any price in excess of $1 will induce irms to enter the market. But the price of a barrel of oil is much more then $1. Economic rent is the diference between the price of oil and its cost of production. It is now accepted practice that governments as resource owners have a right to substantially tax this premium. here are many easy of extracting the government share of the resource rent. As shown by the Resource Rent explanatory diagram below. Governments can take their share of the resource rent through bonuses, royalty payments, taxes like a Resource Rent Tax (RRT) or through Proit Oil, which is Oil that is shared between government and contractor ater Cost Oil has been allocated to the Contractor under a PSC. Further policy justiication for applying a resource rent tax comes from the fact that petroleum resources are exhaustible. It is argued that in this situation, the RRT partially compensates the owner of the resource for the fact that ater a time it will be depleted. CONCEPTS IN PROJECT ECONOMICS AND FINANCE Capital Expenditure and Operating Expenditure Capital expenditures (CAPEX or capex) are expenditures creating future beneits.. An operating expense, operating expenditure, operational expense, operational expenditure or OPEX is an ongoing cost for running a product, business, or system. The production profile of an OOGP Project At the project level, economic considerations revolve around the production proile of the project and the diferent expenditure and revenue streams from the project. As the graphics below show, the irst 2-2.5 years of a typical project involves a high degree of capital expenditure with no revenues in return. Figure 6 - Production Proile Fiscal Arrangments - General Considerations and the Ghana Regime 129 he graphics below undertake the same analysis from the points of view of the project economist and the project accountant. he prominence of government take should be noted. he relationship between CAPEX and OPEX is also quite striking. Figure 7 - Production Proile: he Economists View Figure 8 - Production Proile: the Accountant’s View 130 Fiscal Arrangments - General Considerations and the Ghana Regime Figure 9 - Cash Flow Proile for a Petroleum Project 1 Source Kjemperud, A. Fiscal regimes and project economy http://www.ccop.or.th/ppm/document/SEM2/ALFRED_Fiscal_regimes_and_project_economy.pdf (copy with author) Figure 10 - Cash low Proile for a Petroleum Project 2 CASH FLOW STREAM (DOLLARS) NET CASH FLOW GROSS REVENUE ABANDONMENT SEISMIC LAND OPERATING COSTS TAXES & ROYALTIES DRILLING -1 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 YEARS FROM BONUS BID Energy Fiscal Arrangments - General Considerations and the Ghana Regime 131 GOVERNMENT TAKE & TAXATION Extracting the Resource Rent28 he principal instruments of OOGP taxation are: • royalties; • corporate tax; • additional oil entitlements, resource rent taxes or additional proits tax; Of the above, royalties are usually categorized as an output related tax, while corporate tax, additional proits tax and withholding taxes are classiied as proit related29. Divisble income, government take and investor take or contractor take Governments and POCs are interested in sharing the divisible income. his is the term used to describe the amount of money that remains ater the lifetime revenues of a petroleum project are reduced by the lifetime costs of the project. he share of the divisible income that goes to the state is called ‘government take’. he remainder that goes to the IOC is called ‘investor take’ or ‘contractor take’. Government Tax Regime Objectives Tax regime objectives for government s are typically an amalgam of the following:30 • responsiveness to proitability ie the degree to which the tax corresponds closely with profits; • quickness of payback ie ability of the regime to permit an early payback of capital invested; • severity of the tax burden ie the degree to which it is fair and equitable, and sensitive to the investor’s ability to pay the dues that are imposed so as to avoid, as far as possible, creating inancial strains that afect the project, especially during a slump; • certainty and convenience ie the extent to which a regime is stable (low political risk) and transparent, and payment is related to the lows generated by the project; • eiciently in terms of promoting a rational mineral exploration programme ie reducing distortions in production and costs and preserving incentives for managerial eiciency; • incentive to invest in exploration ie the degree to which it encourages risk taking in new exploration; • incentive to reinvest ie the degree to which it encourages com- panies to reinvest to improve performance; • impact on the marginal project ie the extent to which it discourages the undertaking of a project which would otherwise be viable in the absence of the tax. POC Objectives Tax regime objectives for the oil company would have the following content:31 • Stability of revenue generation ie the sensitivity of tax revenues to luctuations induced by the business cycle - in other words, the ability of the instrument to produce predictable and stable revenues from year to year. 132 Fiscal Arrangments - General Considerations and the Ghana Regime • Progressiveness ie the degree to which the tax gives the government a greater share of proits as proits rise during price boom conditions. • Ease of collection and administration, which will also include the cost and diiculty of making the tax enforceable ie the extent to which it is diicult to avoid or evade. • Early revenue generation ie the ability of the tax to generate revenue in early years (a corollary to delayed payback to the investor). • Distributional justice ie ability to extract windfall gains arising out of either a price bonanza or a particularly low cost rich deposit (subsumed in this is also the principle of promoting just and equitable distribution of income). • Neutrality - the degree to which the instrument is fair to other industries over a wide range of circumstances and risk. Figure 11 - Capture of economic rent by governments Royalties A royalty (or a severance tax, as it is normally known in the USA) is a payment to the state for the extraction and exhaustion of a non- renewable resource. In a large number of countries an overwhelming share of the mineral output is exported so in reality a royalty is an export tax. he base for the levy is either on the output per unit (for instance a ixed nominal payment per ton of inal output or per ton of ore extracted, irrespective of the price level), or on price, or on value of production (ad valorem basis), or as a proportion of sales, or on a combination of any of these. An ad valorem royalty is more responsive to price changes than one based on units of production because it adjusts to prices. he policy rationale for royalties is that they provide a payment to the owner of the resource which repays the owner for the permanent removal of their resources a removal which has intergenerational consequences. Advantages of Royalties he advantage of a royalty is that the government will receive some income from production at the outset, without the need to rely upon the assessment of company costs or proits – the Fiscal Arrangments - General Considerations and the Ghana Regime 133 corporate income tax procedure and the resource rent tax both require more complex inancial assessments. Royalties are in wide use because they are easy to collect, easy to understand and easy to administer. Disadvantages of Royalties Royalties have been criticised on the basis that they do not respond in a sensitive way to luctuations in oil prices and other cyclical trends which afect OOGP. It is certainly the regulatory authorities that royalties have a greater impact when prices are lower or where the oilield is marginal. It is however becoming the accepted international practice for governments to remit, defer, reduce or waive payment on royalties on individual projects either at the development plan approval stage or later in the producing life of a mine if circumstances then so warrant. Sliding scale royalties32 A variant of the royalty is the sliding scale royalty. A sliding scale royalty rate may be created using the following criteria to diferentiate between royalty levels. • • • • • • • level of ield production level of well production location cumulative production production rate and price R factor or internal rate of return other criteria such as water depth, oil gravity, or elapsed time Sliding scales are used to escalate the royalty based on a factor that tends to predict the proitability of a project. Oil & gas projects tend to be more proitable when: • • • • production rate is higher prices are higher costs are lower costs have been recovered Receiving royalty in kind33 A state may opt to receive its royalty ‘in kind’, which means that it can take physical possession of its share of actual petroleum for its royalty. A state that has the capability to market its own production, or a desire to make use of its production share for a diferent purpose than the POC (for example, to take it to a domestic use) may choose to do this, and it can be a useful right. In some cases, states prefer to take their production in kind because they can actually do a better job than the POC of marketing the state share. However, most states allow the POC to sell the state’s royalty share of production and accept payment in cash at the value that the POC obtained. A right to take a royalty in kind requires a few months’ advance notice to the POC, and for a gas project, it may be a onetime election. Rentals34 A ixed payment made on an annual basis at the beginning of the calendar year or contract year. A rental may take on diferent forms it could be a ixed amount for the contract, or ixed amount per square kilometre of operations land, or a negotiated amount. It may be payable during the 134 Fiscal Arrangments - General Considerations and the Ghana Regime exploration phase, the production phase or both. he rental serves a number of purposes. It provides to the government a guaranteed annual income of a known amount, which helps in budget planning, irrespective of changing oil prices. he government can calculate the expected amount of rental payments it will receive based on the number of petroleum contracts it has granted and the area that they cover. his contributes to the government’s administrative costs of running the petroleum operation. It also creates a mild incentive for the IOC to voluntarily relinquish any area where it does not intend to conduct exploration activity, permitting the government to ofer that area to other companies. Bonuses35 Bonuses are amounts paid at the licensing stage (signature bonuses), for the discovery of new reserves and/or for achieving a production target. Signature bonuses can be minimal (US$25 million, for example, in Chad) to quite large (in some cases US$1 billion or more, as in Angola) and can be a signiicant source of revenue to the government in the early stages of oil development. he prooduction bonus is a payment made at a certain point in time during the life of the petroleum contract. A production bonus may occur at the time that a commercial discovery is declared, at the time that petroleum production begins, at a deined production rate, or at a deined quantity of cumulative production. he production bonus provides to the government a ixed amount of revenue at a certain point in time. Also, this type of bonus tends to increase as the amount of production increases. Bonuses can however be dangerous as large bonuses at the start of the project may leave the Government dependent on the company for further income lows. Profit oil or the host government’s production entitlement36 Oil production shared between a company and government once investment and operating costs are recovered through cost oil (the physical oil or revenue used to cover the operator’s costs). Proit oil sharing ratios can be scaled based on production sliding scale, or internal rates of return on a project. In a production sharing arrangement, the production entitlement would be transferred by an POC to the government or the NPC and can be received as physical oil or cash. Additional oil entitlement37 here are examples of petroleum agreements, such as in Ghana, where an additional oil entitlement has been included to address issues related to windfall proits in a time of high oil prices. According to the GNPC, “Additional Oil Entitlement which is also called ‘super normal’ proit tax is additional proit tax that the government is entitled to levy on operations in case of windfall proit, that is, where the investor’s actual internal rate of return exceeds the targeted rate of return used to evaluate the proitability of the venture during the negotiations.” Carried Interest38 Carried interest allows a government/NPC to have a working interest in a joint venture or company producing oil from a block without a cash investment or at a rate lower than its working interest share. In Ghana, for example, “carried interest is levied ater deduction of royalty and operating costs, but before the deduction of exploration and development costs from the total value of oil produced. It can be taken in the form of oil or cash. Carried interest is normally levied at a rate between 7.5-15 percent in most oil-producing countries. Fiscal Arrangments - General Considerations and the Ghana Regime 135 Corporate income tax An OOGP company is a business entity like any other, and in most countries is be subject to normal corporation tax though there is a tendency for signiicant OOGP countries to apply different, usually higher rates to OOGP as compared to normal corporate rates. Corporate income tax is determined at the level of the corporation, where other iscal tools determine the amount payable at the level of the well, the ield or the petroleum contract. Consequently, corporate income tax will include features like deductions for depreciation and other features of the corporate income tax regime. he resulting tax calculation can therefore yield very diferent results than a royalty; a 12.5% royalty is very diferent than a 12.5% rate of tax. he tax is levied on income ater deductions of clearly deined costs of production and allowances intended to create an incentive. Taxes are only paid when revenues exceed costs and allowances. OOGP regimes also tend to provide more generous capital write of provisions than those accorded to other industries. his is because OOGP is more risky than other investments and development is mine speciic, with little or no salvage value. Exploration expenditure also tends to be favourably treated mainly because of its uncertainty. Typical allowable or fully or partially deductable costs are the operating costs necessary to the production process, royalties and other levels of taxes, and interest. However allowances provided and the provisions determining the carrying forward of losses tend to be less uniform although in many cases, OOGP irms are oten able to take advantage of special provisions concerning exploration and development and in some cases extending to research and development and training in addition to depletion and other development oriented activities. he most important concession relating to the sharp price swings of is provision for the regulatory authority permitting the carrying forward of losses which are typically made in exploration. Corporate tax is the principal form of rent resource extraction in those countries which do not have a resource rent tax. Advantages Since the income tax is a tax on proits there is no inherent bias against low proit, marginal irms. It is also more directly related to the oil price cycle. Disadvantages here is signiicant scope for tax avoidance and tax evasion given the multitude of exceptions which typically exist. Complex rules (called ring-fencing) try to limit the utilization of loss forward or backward rules especially important ater a reorganization or other change in corporate ownership. Ring-fencing of corporate taxes39 Some states create special rules for assessing corporate tax on oil & gas. his concept is sometimes referred to as ‘ring fencing’. Rrng fence provisions seel to limit the irm’s ability to set of the expense of unsuccessful eforts in one area of its operations against other projects or sources of income. he opposite of ring fencing is called ‘consolidation’, where activities across multiple contract areas are treated on a combined basis operations. Ghana currently has a very robust and extensive ring-fencing as discussed in detail further on in the Chapter. 136 Fiscal Arrangments - General Considerations and the Ghana Regime Resource rent taxes (RRT) Resource rent taxes vary from regime to regime, but a common method is to charge RRT when the investor has earned a speciied rate of return on the project net cash low. From the total revenue of the project each year, total payments, which include exploration expenditure, development costs, operating expenditure, royalties, corporate taxes and other levies are deducted. he net cash lows are carried from year to year, increasing at what is normally referred to as the threshold rate of return or accumulation rate, which is predetermined before the exploration stage. In the early years the net cash lows remain negative since the entire capital invested is deducted from the gross revenue. As proits are added to the receipts every year, the negative cash lows diminish, and as soon as they become positive the tax is triggered. To achieve progressiveness there could be several trigger threshold rates with higher marginal rates. Figure 12 – he Resource Rent tax relative to other aspects of the iscal regime he advantage of such a tax is that it only hits at the economic rent, and is only payable ater the company has achieved what would be regarded as a normal rate of return. If there is no corporate tax or royalty, the APT regime gives the investor a tax holiday for the payback period, the length of which is decided ultimately by the proits generated40. Advantages he RRT is generally quite well targeted and collects the surplus revenues it is aimed at to a signiicant degree. Disadvantages he principal drawback eiciency is that the tax gives incentives to the investor in certain circumstances to incur unnecessary costs (in order to reduce total tax payments more than in Fiscal Arrangments - General Considerations and the Ghana Regime 137 proportion to the total tax expenditure), a problem commonly referred to in the literature as gold plating. RRT may also be diicult to collect in terms of computation. Figure 13 - RRT – he perspective of the economist Figure 14 - RRT – he perspective of the accountant 138 Fiscal Arrangments - General Considerations and the Ghana Regime THE GHANA FISCAL REGIME – AN OVERVIEW he iscal regime is fundamental to many aspects of an investor’s plan of exploitation, afecting the scope of exploration and discovery, the timing and scale of initial development, the rate of production and decline, the timing and scale of enhanced recovery operations, the overall resource recovery factor, and the timing of inal abandonment. he pervasive impacts of the iscal system, on the investor as well as the government, amplify the importance of designing and implementing a sound iscal regime. Constitutional Provisions Article 257 (6) of the 1992 Constitution provides that all natural resources, and petroleum in particular, belong to the nation and thus proceeds from their extraction should go mainly to the nation. he Constitution of Ghana (Art. 174) sets out that taxation can only be by way of enactments approved by Parliament. Applicable Legislative Provisions and the Stabilisation Clauses he iscal regime that applies to the petroleum industry has three sources of legal authority: (1) PEPA 2016; (2) the Income Tax Act 2015 (ITA 2015); and (3) the Petroleum Agreement speciic to each particular POC consortium (PA). he ITA 2015 has repealed the previously operative statutes, the Petroleum Income Tax Act, PNDCL 188 (PITA) and the Internal Revenue Act, 2000, Act. Due to the stabilization clauses in PAs in force, before the passage of the ITA 2015, POCs operating under PAs before the repeal of the previous legislation continue to operate under these laws. Applicable provisions for those PAs not covered by the stabilization clauses are to be found in the following enactments: • PEPA 2016 at ss 85 to 39. • he Income Tax Act 2015 particularly at s. 63 - 76 • he Petroleum Agreements between the State and POCs active in Ghana (PA) Location of specific fiscal provisions within the legal scheme he legal source of authority for iscal provision type is set out in the table below FISCAL PROVISION Location of Legal Authority Government Participation via Car- PEPA 2016 and negotiated on case by case basis within rying and Paid Interest provisions each Petroleum Agreement Royalties and royalty rate PEPA 2016 and negotiated on case by case basis within each Petroleum Agreement Bonuses PEPA 2016 and negotiated on case by case basis within each Petroleum Agreement Rentals in respect of acreage PEPA 2016 and negotiated on case by case basis within each Petroleum Agreement Fiscal Arrangments - General Considerations and the Ghana Regime 139 FISCAL PROVISION Location of Legal Authority Additional Oil Entitlement PEPA 2016 and negotiated on case by case basis within each Petroleum Agreement Income Tax Income Tax Act 2015, PEPA 2016 & Petroleum Agreements Withholding tax Income Tax Act 2015 THE FISCAL REGIME UNDER PEPA 2016 Royalties PEPA provides for the payment of royalties at s. 85. he Act deines “royalty” to mean the entitlement of the Republic to a portion of petroleum produced and saved and not utilized in petro¬leum activities from each ield and which is calculated as a percentage of gross daily production rates without regard to any prior deductions. Under PEPA 2016, s. 85 (1) the contractor shall pay to the Republic, royalty in respect of gross volume of petroleum produced and saved. he royalty is to be paid is as prescribed, or as other¬wise provided in accordance with the terms of a petroleum agreement in respect of the area to which the agreement relates. Royalty at the rate speciied is be delivered to the Republic in kind, unless the Minister directs in writing that the royalty shall be paid in cash to the Republic. he Minister may instruct the contractor to undertake trans-portation, processing and storage of royalty petroleum in kind on terms and priority which are no less favourable than the contractor’s own petroleum from the relevant contract area. he Corporation in carrying out petroleum activities under section (11) (1) is also subject to the payment of royalty at the rates that may be prescribed. he Minister may determine that payment of royalty in kind shall be made to the Corporation on behalf of the Republic and that the proceeds from the sale of the royalty shall be paid by the Corporation to the Republic as prescribed. Rental payments in respect of acreage Contractors are obliged to pay surface rentals for blocks assigned to them for petroleum operations. Section 86 PEPA 2016 sets out the rules with respect to the payment of an annual fee in respect of acreage as follows: (1) A contractor shall pay the Republic annual acreage fees; (2) he Minister shall prescribe the amount to be paid, except that where the amount is not prescribed, the annual acreage fees shall be as provided in accordance with the terms of a petroleum agreement in respect of the area to which the agreement relates; (3) the section applies to the Corporation where it undertakes petroleum activities under section. Surface rentals payable to the state are as follows: Initial Exploration Period US$30 per sq. km 1st Extension Period 2nd Extension Period Development and Production Area US$50 per sq. km US$75 per sq. km US$100 per sq.km 140 Fiscal Arrangments - General Considerations and the Ghana Regime Direct and Indirect Taxes Taxes payable are described under section 87 of PEPA 2016, the provision stating that a licensee, contractor, sub-contractor and the Corporation shall pay taxes, including petroleum income tax and capital gains tax in accordance with applicable enactments. he most directly applicable enactment is the ITA 2015. Payment of Bonuses Under Section 88, the PEPA act describes the payment of bonuses to the Republic in certain circumstances such that, a contractor shall pay bonus to the Republic as may be prescribed, except that where the type and quantum of the bonus payable is not prescribed, the bonus shall be paid as otherwise provided in accordance with the terms of a petroleum agreement in respect of the area to which the agreement relates. Additional Oil Entitlements under each Petroleum Agreement Finally, additional oil entitlements payable to the Republic to soak up super-normal proits are handled under PEPA 2016, S. 89 and provide that the Republic is entitled to a portion of a contractor’s share of petroleum produced from each ield on the basis of the ater-tax inlation-adjusted rate of return that the contractor achieved with respect to each ield. Further, the deinition of Additional Oil Entitlement refers to an additional proit tax based on the rate of return achieved. he State is entitled to additional oil, if the Contractor achieves a speciied ater tax real rate of return. he Contractor’s rate of return is calculated on its net cash low in accordance with a formula speciied in the Petroleum Agreement. Other Payments hese consist of: (1) rents for leasing of government property and public lands; (2) payments at commercial rates for speciic services provided by public enterprises; (3) a technology allowance - a onetime payment by the Contractor to assist GNPC procure plants, equipment and machinery required for petroleum operations; (4) a training allowance – an annual payment by the Contractor to support GNPC in human resource capacity building. THE FISCAL REGIME UNDER ITA 2015 Petroleum taxation is governed by Division 1 of PART VI speciically at ss. 63 to 76 of the statute. Part VI governs special industries and covers petroleum operations and mining operations. Other sections of ITA 2015 lesh out the rules in Division 1. Of particular importance are s. 31 ITA 2015 (the arms-length standard for transactions) and s. 128 ITA 2015 (the concept of controlled relationship). Section 76 provides for the interpretation of words used in Division I of Part VI of the statute. Ring-fencing of petroleum operations under ITA 201541 he ring –fencing concept42 has already been discussed. Essentially when applied to POCs for income tax purposes, the ring fence has the following features: (1) all the oil exploration and production activity carried on by the company falls within the authority of the taxation authorities; (2) for tax assessment purposes, the company’s exploration and production operations are separated from all of its other activities; (3) each separate petroleum operation undertaken by the POC is treated for tax purposes as an independent business: (4) for each year of assessment, Fiscal Arrangments - General Considerations and the Ghana Regime 141 the tax liability of each independent business is calculated separately. Efective application of ring fencing blocks corporate eforts to reduce taxable proits. Readhead explains the problem that ring-fencing tries to address:43 In most sectors, corporate income tax is generally levied at entity level. However, in the extractive sector it is possible that companies will have multiple activities within a single country, creating opportunities for tax optimization; speciically, a company may use losses incurred in one project (for example, during exploration for a new mine), to ofset profits earned in another project. his is referred to as “sideways relief ”. Sideways relief is normal practice, consolidation of income may even encourage exploration and investment. However, for developing countries whose main source of revenue is corporate income tax, any delay in payment may have major consequences for the timing of government expenditure. his is particularly marked in the extractive industry where large amounts of capital expenditure are immediately deductible, making it possible to delay paying income tax for many years. Ring-fencing, controlled relationships and the arms-length standard Section 63 ITA 2015 imposes a petroleum income tax on the income of all persons who undertake petroleum operations. Applying the ring-fencing concept, s. 63(4) ITA 2015 requires that each separate petroleum operation undertaken by the POC should be treated as an independent business and that for each year of assessment, the tax liability of each such independent business should be calculated separately. Section 64 takes this further by specifying that each production ield is an independent business and it is not possible to charge losses on one ield to another. Further elements of ring-fencing are applied in that under s. 63(3) ITA 2015 chargeable income which is not derived from petroleum operations is to be charged separately. It is not to be dealt with as if it were petroleum related income. To provide even more transparency, s. 63(5) applies s. 31 ITA 2015 (the arms-length standard for transactions) and s. 128 ITA 2015 (the concept of controlled relationship) to the separate petroleum operations of the POC once they have been determined by the tax authorities. Controlled relationships With respect to controlled relationships, s. 128(2) is the directly applicable section. It reads: (2) A person and an entity are in a controlled relationship where (a) the person controls the entity or may beneit from ity percent or more of the voting power or rights to income or capital of the entity, (i) either alone or together with persons who, under another application of this section, are associated with the person; and (ii) whether directly or through one or more interposed entities; or (b) the person, under another application of this section, is an associate of a person referred to in paragraph (a). he arms-length standard he Minister may, by legislative instrument, make Regulations on matters relating to transfer pricing and the application of the arm’s length standard: ITA 2015, s. 31(3). Section 31 ITA 2015 applies an arm’s length standard to people who are adjudged by the tax authorities to be in a controlled relationship in a step-by-step manner as follows: 1. Where an arrangement exists between persons who are in a controlled relationship, the per142 Fiscal Arrangments - General Considerations and the Ghana Regime sons shall calculate their income, and tax payable, according to the arm’s length standard: ITA 2015, s. 31(1). 2. he arm’s length standard requires persons who are in a controlled relationship, to quantify, characterise, apportion and allocate amounts to be included in or deducted from income to relect an arrangement that would have been made between independent persons: ITA 2015, s. 31(2). Right of the Commissioner-General to adjust petroleum sector transactions to approximate to the independent persons standard Where in the opinion of the Commissioner-General, a person has failed to comply with the arms length standard, he/she has the power to make adjustments to POC transactions to ensure they are consistent with the relationship between independent persons required by the armslength standard: ITA 2015, s. 31(4). He also has the power to: re-characterise an arrangement made between persons who are in a controlled relationship, including re-characterising debt inancing as equity inancing: ITA 2015, s. 31(5)(a); re-characterise the source and type of any income, loss, amount or payment ITA 2015, s. 31(5)(b); re-apportion and re-allocate expenditure: ITA 2015, s. 31(5)(c). Finally, a transfer of assets between separate petroleum operations is to be treated as an acquisition or disposal of the asset: ITA 2015, s. 31(6)(a). What constitutes the income of a person engaged in petroleum operations Section 66(1) of ITA, 2015 states that assessable income from petroleum operations has the following key elements: • calculation of POC income is to be based on the market value of the petroleum as obtained from the petroleum agreement area during that particular tax year: ITA, 2015, 66(1)(a) • any compensation related to losses or destruction of petroleum from the petroleum agreement area, whether such compensation comes from a policy of insurance or from any other source: ITA, 2015, s. 66(1)(b) • (c) any amount derived from the sale of information relating to the POC’s operations or petroleum reserves: ITA, 2015, s. 66(1)(c) • Any gains from the assignment or other disposal of an interest in a petroleum right: ITA, 2015, s. 66(1)(d) • (e) surplus amounts in a decommissioning fund: : ITA, 2015, s. 66(1)(e) – check section 70 • (f) any amount received by a sole risk party under the sole risk terms of a joint operating agreement: ater production has commenced, where such amount has been paid to a sole risk party as reimbursement of costs or as a premium to that sole risk party: ITA, 2015, 66(1) (f). Section 66 further provides that for assessment of any transaction, the tax authorities will use the market value of petroleum as set out in the relevant PA. Such value shall also not be less than the value that would have been received were the transaction to be an arms-length transaction under s. 31. Finally, for assessment purposes, any discounts, commissions or deductions will also to be disregarded. Fiscal Arrangments - General Considerations and the Ghana Regime 143 Deductions allowed in determining income derived from petroleum operations Section 67(1) ITA 2015 covers this issue. he core list of items that can be legitimately deducted by a POC before it is taxed under the statute is as follows: • annual rental charges and royalties paid by the person under Ghana’s petroleum law and the PA with respect to the speciic ring-fenced petroleum operation: ITA, 2015, 67(1)(a). • capital allowances granted with respect to with respect to the speciic ring-fenced petroleum operation, with those capital allowances calculated in accordance with ITA 2015, hird Schedule Part II: ITA, 2015, 67(1)(b). • contributions to and other expenses incurred in respect of a decommissioning fund for the speciic ring-fenced petroleum operation and in accordance with the rules established for that fund: ITA, 2015, 67(1)(c). • expenses incurred by that person in the course of closure of the speciic ring-fenced petroleum operation, where funds in the relevant decommissioning fund are not yet available or are inadequate: ITA, 2015, 67(1)(d). • any other amount incurred directly by that person in the course of the speciic ring-fenced petroleum operation and which is an allowable deduction under other provisions of the statute: ITA, 2015, 66(1)(e). Section 67(2) ITA 2015, provides that in calculating income from a separate petroleum operation, the Commissioner-General shall not allow a deduction for research and development expenditure, unless the amount is wholly, exclusively and necessarily incurred in the acquisition or improvement of a valuable asset used in the operation: Equally, under 67(2) (a) a research and development deduction is not allowed unless it is wholly, exclusively and necessarily incurred in acquiring services or facilities for the operation and is income of the recipient which has a source in Ghana. A deduction is also not permitted if the amount contravenes s.31 of ITA 201, or it is being claimed with respect to a bonus payment made in respect of the grant of a petroleum right: ITA 2015, s. 67(2)(d). A deduction is also not permitted if it is for expenditure incurred as a consequence of a breach of a petroleum agreement: ITA 2015, s. 67(2)(e). Section 67(4) provides that in ascertaining the income of a person for each of their separate petroleum operations for a year of assessment, relevant inancial costs incurred during that year may only be deducted to the extent that relevant inancial gains are also included in calculating such income. However, under s. 67(6) a inancial cost for which a deduction is not available under subsection (4) may be carried forward by the person and treated as incurred during any of the subsequent ive years of assessment. A person may also set of a loss in respect of a inancial instrument against a gain with respect to a inancial instrument. he Minister under s. 16 may promulgate detailed rules with respect to this aspect of the statute: ITA 2015, s. 67(4). Finally, under s. 67(10), the Minister may, by legislative instrument, make Regulations to prescribe other deductions that may be allowed in calculating the income of a person from petroleum operations. Losses from petroleum operations – ringfencing to prevent sideways relief he ring-fencing concept is further emphasised by s. 68. Section 17 of the statute is the basic or normal section applying to unrelieved losses. It allows for the practice of so-called sideways relief under which a corporation or other entity can ofset their losses against other income (eg 144 Fiscal Arrangments - General Considerations and the Ghana Regime employment income, dividends, rent etc), thereby reducing or eliminating the tax due on that other income under self-assessment. Indeed, in the case of employment or substantial interest income where tax is generally deducted at source, a refund can oten be claimed. he loss relief can be ofset in this way against the income arising in: (1) the tax year in which the loss occurred; (2) the preceding tax year. Losses can also be carried forward. Section 68 seeks to limit these practices as far as petroleum operations are concerned. It states that s. 17 of the statute applies to unrelieved losses of a person from each separate petroleum operation subject to the following: (a) an unrelieved loss shall be deducted by the person in the order in which the loss is incurred; and (b) an unrelieved loss from a separate petroleum operation may be deducted by the person only in calculating future income from that separate petroleum operation and not income from any other activity. (emphasis ours). Non-allowable deductions where there have been changes in ownership Section 62(1) of the ITA 205, provides that where the underlying ownership of an entity changes by more than ity percent at any time within a period of three years, the assets and liabilities of that entity immediately before the change are deemed to have been realised. In such situations, the following restrictions on deductions will apply: (a) the entity cannot deduct inancial costs carried forward that were incurred by the entity before the change: ITA 2015, s, 62(2)(a); the entity cannot deduct a loss that was incurred by the entity before the change: ITA 2015, s. 62(2)(b); the entity cannot carry back a loss that was incurred ater the change of ownership to a year of assessment before the change: ITA 2015, s. 62(2)(d). Disposal of petroleum rights under the ITA – offence not to report disposals of interest Section 69(1) of the statute provides that where a person holds a direct or indirect interest in an entity that holds a petroleum right, the person is treated as holding the interest as a capital asset employed in the business of that entity. Section 69(2) then provides that where the underlying ownership of an entity that holds a petroleum right changes by ive percent or more, the entity is considered to have: (a) disposed of a proportionate interest in its petroleum right and immediately re-acquired that interest by incurring an expenditure that is equal to the amount received for the right disposed of; and (b) received for the disposal, consideration equal to (i) the amount received or receivable as consideration that has arisen out of the change in ownership; or (ii) the market value of the proportion of the right treated as disposed of whichever is higher. Section 69 (3) then provides that where ownership of an entity changes in the manner referred to s. 69(2), then in such a case, the entity shall notify the Commissioner-General within thirty days from the date of the change. It is an ofence not to notify the Commissioner-General of such a change. An entity is liable to is liable on summary conviction to a ine of not more than two hundred penalty units for each failure to report changes to the Commissioner-General: ITA 2015, s. 67(4). Under s. 69(5) these rules (criminalization) does not apply to: (a) the tax treatment of actual disposals of petroleum rights; (b) the application of s. 62, to an entity that holds a petroleum right. Fiscal Arrangments - General Considerations and the Ghana Regime 145 Asset dealing between entities and members 61. Subject to section 45(2), where an asset is realised by way of transfer of ownership of that asset between an entity and one of its members (a) the transferor is considered to have received, in respect of the asset realised, an amount equal to the market value of the asset immediately before the realisation; and (b) the transferee is considered to have incurred an expenditure equal to the amount referred to in paragraph (a). Amounts accumulated in decommissioning funds or withdrawn from them are tax exempt Section 70(1) of the ITA 2015, provides that an amount accumulated in or withdrawn from a decommissioning fund for decommissioning purposes is exempt from tax. Section 70(2)(a) also provides that where there is a surplus in the relevant decommissioning fund ater a person completes decommissioning of a separate petroleum operation conducted by that person, then that surplus shall be included in calculating the annual assessable income of that person from the speciic (and separate) petroleum operation: ITA 2015, 70(2)(a). Additionally, any surplus in a decommissioning fund shall be treated as income for a speciic year, if in that year, the person breaches an approved decommissioning plan: ITA 2015, s. 70(2)(b). The application of the withholding tax rules to petroleum operations Section 71(1) states that s. 59 (3) does not apply to a dividend paid by a company that (a) conducts petroleum operations or that has conducted petroleum operations; or (b) is a partner in a partnership that conducts petroleum operations or that has conducted petroleum operations. Section 59(3) states that a dividend paid to a resident company by another resident company is exempt from tax where the company that received the dividend controls indirectly or directly, at least twenty-ive percent of the voting power of the company which paid the dividend. he efect is that this tax exemption is not available in the petroleum sector. Section 71(2) states further, that a dividend paid in circumstances where s. 71(1) applies is subject to withholding tax in accordance with the relevant provisions of the statute: ITA 2015, s. 71(2). Application of withholding tax rules to expatriates and non-residents working in the petroleum sector Unless, a PA provides otherwise, the gains or proit of an expatriate employee who is employed by a contractor or subcontractor is liable to tax and withholding tax under the statute: ITA 2015, s. 71(3). Section 71(4) also imposes a duty on contractors to apply withholding tax (at rates set out periodically in the First Schedule of the statute) to any amounts due to subcontractors with respect to work or services for or in connection with a petroleum agreement. his withheld tax is to be paid to the Commissioner-General. Section 71(5) of the statute provides that a tax withheld in this way is, in the case of a nonresident person, a inal tax. 146 Fiscal Arrangments - General Considerations and the Ghana Regime Procedural matters – currency in which tax is to be paid A person who is liable to pay petroleum income tax, including interest, ines and penalties imposed under this Act or the Petroleum Revenue Management Act, 2011 (Act 815) shall pay the tax (a) in the currency provided for in the applicable petroleum agreement; and (b) in the absence of any express agreement, the amount shall be paid in Cedis: ITA 2015, s. 63(8)(b). Procedural matters - furnishing of quarterly returns of income Section 72 obliges a person engaged in a petroleum operation to provide a quarterly report within thirty days ater the end of a quarterly period. his report/return must contain: (a) an estimate of the chargeable income of the person with respect to that quarterly period; (b) an estimate of the tax due on the chargeable income of that person as well as a remittance in settlement of the estimated tax: ITA 2015, s. 72. Procedural matters - furnishing of annual returns of income Under s. 73(1), for each year of assessment, annual tax returns are to be iled with the Commissioner-General not later than four months ater the end of the year of assessment. he return is to be iled for each separate petroleum operation: ITA 2015, s. 73(1). he annual return shall include: • a statement containing the full names, addresses, nationality, salaries, wages, fees and allowances of the persons employed in the country: ITA 2015, s. 73(1)(a); • a statement of the amount of production during the year of assessment and the share of that person in the production: ITA 2015, s. 73(1)(b); • a statement of the price paid for the sale or export without sale of the person’s share of the petroleum produced: ITA 2015, s. 73(1)(c); • information relating to matters referred to in this section that is provided under the petroleum agreement: ITA 2015, s. 73(1)(d); • any other statement or information required to be provided under the statute: ITA 2015, s. 73(1)(e). Procedural matters - the Commissioner-General and securing further information he Commissioner-General may (where the Commissioner-General thinks necessary) give notice in writing to a person, requiring that person to furnish within the time speciied in the notice: (a) further information as to the matters in connection with the quarterly returns and annual returns; or (b) any matter which the Commissioner-General considers necessary for determining the assessment of that person: ITA 2015, s. 74. Fiscal Arrangments - General Considerations and the Ghana Regime 147 SUMMARY his Chapter has addressed the following issues as far as iscal regimes are concerned: • Matters of importance to governments from the regulatory and economic point of view; • Matters of importance to oil companies from the regulatory and economic point of view; • he diferent tools that are available to governments to generate what is called government take. Considerations which afect the practical application of these instruments include: timing of exploration; scope of exploration; timing of initial development; scope of initial development of the production proile (decline rate) ; timing of enhanced recovery; scope of enhanced recovery; resource recovery factor; minimum economic ield size; minimum economic price; timing of abandonment. he Chapter also provides a detailed discussion of Ghana’s iscal regime. 148 Fiscal Arrangments - General Considerations and the Ghana Regime Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. he four factors and forms of compensation are: land (rent) labour (wages); capital (interest) and enterprise (proit). In practice it is oten diicult to calculate what a normal proit is. (Strategy for African Mining. World Bank Technical Paper No.181. Mining Unit, Industry & Energy Division, World Bank. August 1992). Designing auctions for ofshore petroleum lease allocation1 Kjell J. Sunneva Resources Policy 26 (2000) 3–16 at 11 Adrian Muller and Cornelia Luchsinger Incentive Compatible Extraction of Natural Resource Rent. Centre for Energy Policy and Economics (CEPE) Federal Institute of Technology Zurich, Working Paper (. d.) (copy with author). (MC means marginal cost and AC means average cost). Adrian Müller and Cornelia Luchsinger Incentive Compatible Extraction of Natural Resource Rent (copy with author), Adrian Müller and Cornelia Luchsinger Incentive Compatible Extraction of Natural Resource Rent (copy with author) David Ricardo; Karl Marx; Adam Smith; William Pettry amongst others belong to this school.. he classical school is to be contrasted with the neo-classical school of the late 19th and early 20th century – Jevons, Pareto, Walras, Marshall to name a few. Adrian Müller and Cornelia Luchsinger Incentive Compatible Extraction of Natural Resource Rent (copy with author) NB: Costs here includes a normal return to the entrepreneur and interest payments to capital he concept of land as used here includes marine resources. What you mine today, you can’t drill for in ten years time since it is gone. Hotelling, Harold (1931). he Economics of Exhaustible Reesources. he Journal of Political Economy 39(2), 137-175. here are assumptions here that prices rise over time which need not concern us here Including the owner’s option to mine it later when its value would be higher – again given certain assumptions which need not concern us here. his principle, of reinvesting revenues from non-renewable resources in other activities, is known as Hartwick’s Rule – see Hartwick, J. M. (1977), Intergenerational equity and the investing of rents from exhaustible resources. American Economic Review, 67 (5): 972-974; Adapted from Christopher Hurst Contractual arrangements for the exploitation of natural gas in developing countries Resources Policy September 1988, 162 Although Saudi Arabia has around 80 oil and gas ields (and over 1,000 wells), more than half of its oil reserves are contained in only eight ields, including Ghawar (the world’s largest onshore oil ield, with estimated remaining reserves of 70 billion barrels) and Safaniya (the world’s largest ofshore oilield, with estimated reserves of 19 billion barrels). he costs of producing oil and gas are described as liting costs - – Performance Proiles of Major energy producers 2002 - http://www.eia.doe.gov/emeu/perfpro/ch4sec1.html Finding costs are the costs of adding oil, including crude oil and natural gas liquids, and dry natural gas proven reserves via exploration and development activities – Performance Proiles of Majore energy producers 2002 - http://www.eia.doe.gov/emeu/perfpro/ch4sec1.html See Energy Information Administration – Saudi Arabia Country Analysis Brief http://www.eia.doe.gov/ emeu/cabs/saudi.html Designing auctions for ofshore petroleum lease allocation Kjell J. Sunneva Resources Policy 26 (2000) 3–16 at 11 Designing auctions for ofshore petroleum lease allocation Kjell J. Sunneva Resources Policy 26 (2000) 3–16 at 11 he “Brown tax” represents an even bolder proposal to target rent capture without afecting returns or discouraging investment. Under the brown tax, the government taxes positive cash lows at a lat rate, but subsidizes exploration and production at that same rate when the investor is sufering from a negative cash low. While this proposal is probably unfeasible in most developing countries, which would have diiculty providing the government’s share, it represents a unique efort at sharing investment risk among the public and private beneiciaries of production. Designing auctions for ofshore petroleum lease allocation Kjell J. Sunneva Resources Policy 26 (2000) 3–16 at 11 his example is sourced from Glenn-Marie Lange, he Contribution of Minerals to Sustainable Economic Development in Botswana, Report to the Botswana Natural Resource Accounting Programme, New York University, November 2000 (copy with author). Fiscal Arrangments - General Considerations and the Ghana Regime 149 30. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148,; Raj Kumar and Marian Radetzki, ‘Alternative iscal regimes for mining in developing countries’, World Development, Vol 15, No 5, 1987, 741-758; K. Brewer, G. Bergevin and R. Dunlop, ‘Fiscal systems’, Resources Policv. Vol 15, No 2, June 1989, pp 131- 148. 31. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 137 32. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 134 33. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 134 34. his section of the Chapter is based on the discussion to be found at Open Oil, Oil Contracts, How to read and understand them (2012), 78. 35. his section of the Chapter is based on the discussion to be found at Open Oil, Oil Contracts, How to read and understand them (2012), 80. 36. his section of the Chapter is based on the discussion to be found at Open Oil, Oil Contracts, How to read and understand them (2012), 76. 37. his section of the Chapter is based on the discussion to be found at Open Oil, Oil Contracts, How to read and understand them (2012), 75-76 38. Gary, I. Oil and gas revenues, funds and state budgets: Minimising leakages and maximising transparency 39. and accountability in the hydrocarbon value chain, 163-164. 40. Gary, I. Oil and gas revenues, funds and state budgets: Minimising leakages and maximising transparency and accountability in the hydrocarbon value chain, 163-164. 41. Gary, I. Oil and gas revenues, funds and state budgets: Minimising leakages and maximising transparency 42. and accountability in the hydrocarbon value chain, 163-164 43. his section of the Chapter is based on the discussion to be found at Open Oil, Oil Contracts, How to read and understand them (2012), 82. 44. Raj Kumar Taxation for a cyclical industry, 17 Resources Policy 1991 133-148, 143-144. 45. See in particular, Alexandra Readhead, Getting a Good Deal: Ring-fencing in Ghana https://resourcegovernance.org/sites/default/iles/documents/getting-a-good-deal-ring-fencing-in-ghana.pdf 46. As per the International Monetary Fund (IMF), ring-fencing can broadly be deined as a “limitation on consolidation of income and deductions for tax purposes across diferent activities, or diferent projects, undertaken by the same taxpayer.” See the conceptual discussion of ring-fencing in Readhead, above. 47. See again, Readhead above. 150 Fiscal Arrangments - General Considerations and the Ghana Regime Fiscal Arrangments - General Considerations and the Ghana Regime 151 5 5 CONTRACTING IN HYDROCARBON OPERATIONS Contracting in Hydrocarbon Operations 153 INTRODUCTION & OBJECTIVES OF CHAPTER General considerations In all countries, including Ghana, the regulatory regime grants OOGP companies the right to undertake many complex forms of contracting subject to the overriding expectation, if not rule, that the interests of governments must be protected against fraudulent or misleading arrangements. hus, in addition to the master agreements1 that regulate relations between a Host State and an international oil company regulators need to have a sound understanding of the many diferent types of contract types used by the actors actually involved in exploration and production (including the national oil company or national petroleum corporation). Contracts include joint operating agreements that govern the operations of the consortia for large projects that are the norm to spread risk but also to take advantage of the highly specialised competencies and attributes of particular irms and to some degree countries and their particular petroleum resource proiles. here are also farm-ins and farm-outs as well as other forms of “silent” inancing arrangements in which a inancial partner joins the active operator in bearing exploration (or less typically, development and production) risk. hese contracts govern horizontal relations between the actors in the sector, whilst the vertical relationship between Host State and international oil corporation is governed by the concession agreement, production sharing contract; licence contract; service contract as the case may be. It is the agreements discussed in this Chapter which give efect to the master contract between Host State and international oil company. It is for this reason that governments oten seek to approve these ancillary contracts or require that OOGP companies disclose such contracts where relevant. Governments do not however signiicantly shape or inluence the contents of such contracts. he content of the contracts under discussion here are driven by the organizational, commercial, inancial and operational requirements of the industry as well as Model Contracts or Model Agreements designed by peak association bodies for use by the diferent sub-sectors of the petroleum industry. A key role in this regard is played by the Association of International Petroleum Negotiators. Accordingly, AIPN Model Agreements are discussed in some detail by this Chapter. Following Timothy Martin2 for our purposes, the key contract may be classiied as follows: Agreement category Speciic types Exploration and production agreements • Study and Bid Agreement • Farm-out Agreement • Joint Operating Agreement and the Accounting Procedure for Joint Operating Agreements • Unitisation Agreement 154 Contracting in Hydrocarbon Operations Agreement category Speciic types Midstream agreements • • • • • • • • Crude Oil Liting Agreement Crude Oil Sales Agreement Crude Oil Transport Agreement Gas Sales Agreement3 Gas Processing Agreement4 Gas Balancing Agreement5 Gas Transport Agreement6 Common Stream Operating Agreement7 Service Contracts • • • • Seismic Contract Drilling Contract Well Services Contract Design and Construction Contract Miscellaneous • Conidentiality Agreement • Transfer and Assignment Agreement In this Chapter, we turn our attention to the more important examples of these types of contract paying particular attention to the contracts that are key to exploration and production, namely: Study and Bid Agreements; Farm-out Agreements; Joint Operating Agreements and Unitisation Agreements. Contracting in Hydrocarbon Operations 155 he full network of contracts that arise in a typical OOGP situation are shown by Figure 1. UPSTREAM CONTRACTS OR AGREEMENTS The study and bid agreement8 his type of agreement is the quintessential example of risk-sharing in the exploration segment of OOGP and is entered into prior to acquiring a block or entering into a project. he agreement governs relations within a group or consortium who decide to form a temporary arrangement for the purpose, at least, initially of exploration. Many study and bid agreements also cover development and production activities. he study and bid agreement lowers inancial risk with respect to high risk prospects as well as large, expensive projects. Typical elements of a study and bid agreement are: • the party who will be in charge of negotiations with the host country; • the proportionate shares the participants will have, • the procedure through which the participants will determine the contents of their application for a license or production sharing contract 156 Contracting in Hydrocarbon Operations • a no-compete clause under which each party “undertakes that neither it nor any of its ailiates shall submit any bid covering the lands … either alone or with any third parties”; • details as to how the evaluation process will be conducted; • the amount of money to be expended on the evaluation; • a requirement that the party conducting the evaluation will make periodic presentations to the other parties; • a procedure for invoicing the parties and collecting the parties’ participating share of the expenses in a speciied currency; • a disclaimer as to liability between the parties – in particular, that the work of the evaluating parties does not generate liability for any of the other parties involved for the work performed; • a requirement that the evaluating party will present its inal evaluation at a speciied time, usually 30 to 60 days prior to the bidding date; • a procedure for addressing what happens if the parties are unable to agree on a bid – typically, the highest proposed bid or the most competitive terms proposed by any party will be the bid submitted; • provisions to govern situations where one or more parties elects not to bid – typically, the agreement will provide that the participating interest share of the exiting party will be acquired by those parties electing to bid; • a clause stating that if the parties who elect to bid revise the commercial terms of their bid, they must notify those parties who have elected not to bid and give these parties an opportunity to participate in the submission of the revised bid; • a clause designating one party as the operator for negotiating a host government contract and for the resulting JOA; • a requirement that each party agree not to submit a competitive bid on its own or with any other party; • a requirement that all information is to be kept conidential, with the exception that disclosures can be made to ailiates, government entities, bona ide potential • purchasers and consultants, if suitable protection is obtained; • a clause providing that the agreement terminates when no party elects to bid, only one party elects to bid, the bid is rejected by the host government or when the JOA supersedes and replaces the agreement. Farmout agreements9 his is an arrangement under which the holder (farmor) of an oil and gas interest agrees to assign an interest in the concession to another party (farmee) in consideration of the farmee drilling a well or wells (farm-out wells) Sometimes the farmee may be required to perform geological and seismic studies or pay a cash consideration for past costs incurred by the farmor. he farmor is said to have made a farm-out and the farmee has made a farm-in. he terms of a simple farm-out might be: • State X grants Company Y (the farmor) a 100% interest in Concession A. • Company J (the farmee) enters into an agreement with Y under which J agrees to perform certain deined work obligations (and/or to pay a deined share of the costs of such work obligations) so the farmor can meet its Minimum Work Obligations to State X. • In return, the farmor will transfer a 50% interest in Concession A to the farmee and retain a 50% interest. • he work obligations are typically to shoot a certain quantum of seismic lines and/or drill a number of exploratory wells within the First Exploratory Period, typically 3 years. • he assigned interest is to revert to the assignor if the assignee doesn’t drill a producing well to a certain depth by a certain date. Contracting in Hydrocarbon Operations 157 “Farming out” makes sense if a company is unable to develop expiring acreage due to budgetary constraints or it wishes to reduce or eliminate risk and improve economics as a percentage of investment and is willing to accept in return a reduced acreage position (and thus a reduction in potential return). “Farming in” makes sense if a company’s budget can stand the costs of drilling and the company is willing to accept greater costs and risks to gain or increase its acreage position in the area and thus increase its potential aggregate return. Farm-outs tend to occur in the exploration, appraisal or development phase of the lifecycle and not in the production phase. he AIPN Model Farmout Contract is oten used as a starting point for negotiation of farm-out agreements. It covers the following issues: • • • • • • • • • • • • • Assignment of interest Conditions precedent to assignment Consideration Obligations under the contract and the Joint Operating Agreement Undertaking of the parties Representations and warranties of the parties Tax issues Conidentiality Notices Governing law and dispute resolution Force majeure Default General provisions Joint operating Agreements10 Rationales for establishment of a JOA Economic risk and technical complexity require that companies group together in consortia to explore for and produce petroleum in the form of joint ventures so they can more efectively maximize expertise and special skills, ofset costs and share risks. his is the principal driver for the emergence and use of the joint operating agreement (JOA) as it provides the constitutional or governing instrument for consortia or groups that commit to a petroleum project typically consisting of both exploration and production phases. Although the term is not necessarily used directly, it is widely understood that such joint ventures with respect to petroleum are ‘unincorporated joint ventures’ and that JOAs are a special type of contractual arrangement to give efect to this particular type of joint venture. Relationship between the JOA and its Parent Concession, Licence or Production Sharing Contract In the example below, a schematic is used to explain how JOAs relate to the general petroleum law of the State as well as the speciic contract between the State and the concession holder. In the example the concession holder deals with the granting State as if it is one person, or a unit, although the reality is that the concession has been granted to three companies: A, B and C with ownership shares expressed as • A - 40%, •B - 40% and C - 20%. 158 Contracting in Hydrocarbon Operations Figure 2 he Joint Operating Agreement – a Schematic he concession is granted in respect of a deined physical area the boundaries of which are deined by area coordinates (surface-mapped latitudinal and longitudinal bearings). Sometimes the boundaries may also be delimited by reference to stratigraphic layers (that is, according to levels of depth below sea level), or by a combination of these descriptions. With respect to the concession area, the concession holder has certain exclusive rights but also has obligations to the State. here is thus a need for the concession holders to regulate their internal relationship so as to meet the obligations under the concession and also to be able to exercise their rights. his is where the JOA emerges to complement the concession. Put another way, the concession sets out the vertical relationship between the state (as the grantor of the concession) and the parties (in their capacity as the concession holder), but does not address the terms of the horizontal relationship between those parties. he JOA is needed to give efect to the concession and acts as the constitution governing the unincorporated joint venture that exists between the parties with respect to the management of the concession that they have been granted. It is the instrument that provides for how the operations that are required to be performed under the terms of the concession will actually be performed as between the parties. It deines their relationship and provides for the sharing between the parties of the rights and the liabilities that derive from ownership of the concession. he JOA although a private law instrument underpins the public law arrangement that is the concession. he closest analogue is that of a partnership agreement between partners, even though all JOAs stress that they are not partnerships in the conventional sense. Scope of the JOA Joint ventures are usually created for a speciied project and thus, are limited in scope. he JOA essentially takes efect ater a licence has been awarded and is oten based on an initial joint bidding agreement or an agreement terme an area of mutual interest agreement (AMI). his initial agreement covers a speciic area within which the parties to the agreement will conduct operations jointly as a group to the exclusion of third parties. Hence, the scope of the JOA is intended to cover all joint activities in this speciic area from the licence award to the termination or surrender of the licence. hus, the JOA will normally include a statement of the scope of the JOA and will formally create the joint venture between the parties in relation to joint exploraContracting in Hydrocarbon Operations 159 tion and development of resources. his agreement is usually the single source of authority by which the parties derive the rights to undertake certain actions as well as the liabilities in relation to the joint venture. Other matters typically addressed include: participating interests and commitments to fund joint operations; operator appointment andbehaviour; meetings, voting, budgets and authorisations; default; exclusive operations; and anaccounting procedure. Participating Interests he proprietorial nature of the JOA refers to the establishment of a common ownership of assets by the parties, who usually own these assets as ‘tenants in common’. his is created by an ‘interests clause’ and efectively speciies the respective percentage interests of the parties in relation to the license granted and also any property owned by them. herefore, the production of any assets as well as any other rights or duties arising from the JOA, are held in relation these percentage interests. he clause in efect transforms the collective unitary form of ownership granted by the license into individual ownership of proportions of the property, each having a separate undivided share of the JOA assets. Furthermore, these undivided interests also form a ‘chose in action’ and can be sold or mortgaged by their owners. he relationship between the parties to the agreement he most important feature of a JOA is the contractual duties of performance between the co venturers. Essentially, a typical JOA operates on two levels: • day to day management of the activities within the venture which is delegated to the operator • overall control and strategic decision making which is through the non operators in their capacity as the joint operating committee he Operator he operator is usually the party with the largest interest and its appointment is usually subject to Government approval. Furthermore, the operator does not act for proit and recovers its costs only, but due to its large share and position, has the ability to greatly inluence the project. he operator has the day to day responsibility for the conduct of the exploration and development operations. he operator is expected to conduct the joint operations itself, its agents or its contractors under the overall supervision and control of the (Op-com). In recent years there has been a tendency of delegating operating functions to professional contractors who are not members of the JOA. Even when this is the case and the operator does not conduct any of the joint operations itself it shall nevertheless remain responsible for the joint operations as the operator. he major duties of the operator include: • • • • • he preparation of programmes, budgets and AFEs he implementation of approved programmes he prompt provision to each of the non operators of reports data and information he maintenance of all appropriate insurance he provision of notice to the non operators of any incidents which may give rise to litigation 160 Contracting in Hydrocarbon Operations he JOA will usually provide for the removal of the operator and the views of the operator and non-operators in this context are largely divergent with regard to these provisions. he operator will want to have operator removal provisions that are limited to those requiring good cause, for example default or wilful misconduct. he operator acts as an agent to the other parties to the JOA and as such owes a duty of care referred to as that of ‘a reasonable and prudent operator’ and because this agency is given for free, it will not want to be liable to the non operators for negligent actions, or even grossly negligent actions. It will only want to be liable for ‘wilful misconduct’ or a failure of its obligation to maintain insurance; it will also not want to be liable for ‘consequential losses. he operator will also want to have provisions which require unanimity among the JOA members, and which allows the operator to veto any attempt to remove it. he non operators on the other hand may prefer to have removal clause which is without cause and based on majority voting of the members. he JOA will also contain clauses allowing the operator to resign and which provide for the selection of a replacement. his is another potential area for tensions. Exit from and Entry into a JOA he transfer of an interest in a JOA and in a license is done by the process of novation and assignment. However, all and any such trading or transactions in license interests is subject to consent being granted by the particular State. In practice, conlicts occur as some parties may wish to transfer their interests freely with minimum restrictions, whilst others may feel that the established relationship should be protected. JOAs therefore have clauses granting existing members, rights of pre-emption or rights of irst refusal with additional consent provisions to ensure that there is no sudden and disruptive as well as unrestrained transfer of interests by parties who wish to leave the JOA. Pre-emptive rights efectively allow the co-licensees of the joint venture to maintain control of the venture. his is achieved by having a say in the introduction of new joint venture partners. Existing joint venture partners reserve the right to acquire the participating interest of a selling joint venture partner who wishes to sell before the opportunity is given to an outsider willing to acquire the interest. It is also sometimes the case that the JOA will specify that operatorship of the venture should irst pass to existing non operating members of a joint venture for consideration before passing on to an external party wishing to become an operator in the joint venture. Model JOA provisions and a Ghana example he AIPN has long paid attention to the issue of Model terms for Joint Operating Agreements. he matters addressed by its 2012 MODEL INTERNATIONAL JOINT OPERATING AGREEMENT are set out at Appendix 1. Matters addressed by a sample Ghanaian JOA are also set out by Appendix 2. Unitisation11 In many cases (see Figure 1) a reservoir lies beneath (or in legal language straddles) two or more licensed areas or concessions. It is economically, commercially and politically more eicient to recover the petroleum by operating the reservoir as a unit, rather than by allowing each rights holder to independently extract the petroleum. Unitisation has developed as the most appropriate way for IOCs and governments to manage the geological uncertainty associated with the reservoir. Unitisation can be voluntary or compulsory. In a statutory or compulsory unitisation, a state regulatory agency has the authority to impose unitisation on a pool of oil or gas. he unit is operated by a single company on behalf of the group. Unitisation also envisages that ater the initial unitization the parties will revisit and redetermine their unit interests. Contracting in Hydrocarbon Operations 161 Figure 3 An underlying Reservoir, related concessions and resulting unit area12 Pre-unitisation agreements A preunitisation agreement deines how parties to licences which contain a common hydrocarbon reservoir will jointly evaluate the reservoir for the purposes of submitting a common ield development plan, including a plan for unitisation. Pre-unitisations are important because they provide stability and also give assurance to both lenders and governments at the critical time when ield development is taking place. hey also provide a framework which allows licensees to undertake initial unitisation evaluation work. hey are in efect preliminary or interim agreements and explicitly provide that they do not determine the actual unitization. In many, if not most cases, the interests of the parties as set out in the pre-unitisation agreement are eventually not relected in the inal unitisation agreement. Changes occur because by the end of the evaluations, more information has become available about the reservoir through geological and reservoir engineering studies. Key provisions of a preunitisation agreement A pre-unitisation agreement will typically cover (among other matters) the following: • initial unit interests of the parties; • appointment of an “operator” for conducting the preunit operations such as preparation of the work programme and budgets; • establishment of an operating committee to review and approve all preunitisation operations; • data exchange to allow each licensee to receive a copy of all data with respect to the other licence, subject to any conidentiality restrictions which may exist with third parties; • technical studies to determine the extent of the ield dimension and quantities of oil and gas in each block; • preparation of a development plan for submission to the government; • provisions governing the negotiation of a unitisation agreement by a certain date; and • appropriate termination event provisions such as (i) the decision of a licensee not to participate in the development or (ii) upon the signature of a unitisation agreement. 162 Contracting in Hydrocarbon Operations A key problem is with respect to data exchange as all parties will be seeking to preserve the conidentiality of data acquired before the pre-unitisation efort in respect of their licence. Figure 4 - he Unitisation Agreement13 he unitisation agreement he purpose of a unitisation agreement is to establish a unit from two or more licence or contract areas. his agreement unitises the commercial interests of the parties even as it provides for the development, operation and decommissioning of the facilities used to extract the resources that underlie the unit area. Each negotiating party tries to ensure that their share of petroleum under the unitization represents the hydrocarbons originally in place in their own original licenced area. his is one of the reasons why data exchange is one of the most diicult aspects of a unitization. Contracting in Hydrocarbon Operations 163 Figure 5 - Unitisation between License Group/Consortia A and License Group/Consortia B he Association of International Petroleum Negotiators (AIPN) has produced a model form unitisation and unit operating agreement. It is oten the starting point for documenting the arrragements that the parties eventually arrive at. Key concerns in unitisation agreements It is important to remember that the key concern for the consortia or licence groups will be the determination of the area in each block which should be unitised. • he “unit area” is determined or decided on the basis of licensee understanding of the surface extent of the reservoir based upon seismic studies and exploration and appraisal drilling or by depth (i.e. the three dimensional boundaries of the reservoir obtained through subsurface data because the ield itself is a three-dimensional entity). • he “tract” is the portion of the unit area underlying the licence which is owned by the licensee and the initial tract participation will be expressed as a percentage. • Tract participation will be expressed as a percentage and will be subject to redetermination over the life of the ield. 164 Contracting in Hydrocarbon Operations Unitisation agreements are to some degree similar to Joint Operating Agreements Unitisation agreement essentially unify consortia who already have joint operating agreements between them. For this reason, the inal unitization agreement mirrors and deals with many of the issues that are dealt with in the JOAs of member consortia. JOA. For this reason, a typical unitisation agreement will contain provisions addressing the following issues: • the appointment and removal of the operator (referred to in unitisation agreements as the “unit operator”); • the authority and duties of the unit operator and conduct of unit operations; • the formation of work programmes and budgets, including invoicing and expenditure principles; • decommissioning; and • assignment and withdrawal. Unitisation is efectively between consortia as shown by Figure 4. Additional provisions speciic to the drivers and operational requirements of unitisation Provisions speciic to unitization in the strict sense are required because of the need to precisely determine the initial tract participation/unit interest. his is critical because the initial determination decides for each party: (1) their expenditure commitments and other inancial matters including payments for unit costs; (2) their share of production; (3) their decision-making power with respect to unit matters. Methodologies for deciding tract participation Methods in common use are: 1. Usage of stock tank oil originally in place (STOOIP) – the total quantity of petroleum in the reservoir before production commences. Whilst this is relatively easy to estimate and agree between the parties, a key disadvantage is that no distinction is made with respect to the recoverability of reserves; 2. Gross rock volume – the total volume of strata within the unit, including the porosity; 3. Reserve estimation – the amount of hydrocarbons expected to be commercially produced; or 4. Moveable oil originally in place (MOOIP) – the oil which is capable of movement within a reservoir even if it is not actually produced. Once the initial tract participations have been calculated, each party’s unit interest is then determined by multiplying the party’s percentage interest under its licence by the initial tract participation for that licence. he tract participations initially set out in the unitisation agreement are always provisional igures given that there will be periodic redeterminations. Contracting in Hydrocarbon Operations 165 Figure 6 – Tract Participation14 Changes to the size of the unit area A unitisation agreement will typically include provisions governing what happens if there is a change in the unit area. For example, the unitisation agreement may state that any change to the unit area will require the unanimous approval of all parties, except in the event of the surrender, revocation, termination or expiration of the licences. Redetermination As more geological, geophysical and reservoir engineering studies are undertaken on the unitised reservoir and, accordingly, more information is obtained about its characteristics and reserve proile (including future production proile), it is common for the information derived to be used to redetermine the initial tract participation and unit interest of the parties in line with the new data obtained. 166 Contracting in Hydrocarbon Operations his is an important principle because it allows for a more accurate allocation of costs and production between the parties to the unitisation agreement. However, like all matters involving technical data and interpretation, which is subjective in nature, there will still be uncertainty regarding the outcome of a redetermination. To cater for the impact of new data with respect to the reservoir, unitisation agreements will oten contain provisions governing the redetermination of the tract participation and unit participation of the parties to the unitisation agreement. he redetermination process is likely to consume a signiicant amount of time and money and can oten lead to disputes between the parties, thus impacting on the relationships between the parties. Given that parties are ultimately deciding upon the unit interests and, consequentially, the allocation of expenditure and production to each party, redetermination of the initial tract participation can become contentious. A unitisation agreement will contain provisions governing when a redetermination should take place, including limits on the number of redeterminations which can take place. Triggers for redetermination Agreement provisions specify typical events which may give rise to a redetermination hey include (but are not limited to): • completion of the last development well pursuant to the unit development plan; • a speciied anniversary ater the commencement of irst commercial production; • cumulative production has reached a certain level of unit substances estimated in the unit development plan; • suicient “New Data” (as deined in the unitisation agreement) has been obtained; and • a change in the unit area and/or the unit reservoir. Situations where eforts are made to limit redetermination It is sometimes the case that unitisation agreements governing small discoveries may attempt to limit or ix the number of tract participations and unit interest that can be generated. hey may also ix the number of times a redetermination can take place. his is justiiable because the inancial costs of constant redetermination may override the merits of open-ended rights of redetermination. Implementing Redetermination Unitisation agreements typically set out procedures for implementing redetermination in in considerable detail. he elements of a typical clause or set of provisions are: 1. Provision is made for the establishment of a determination committee by the unit operator, this committee typically being composed of one representative of each party to the unitisation agreement – the determination committee oversees the redetermination process. 2. he selection and appointment of an independent expert to undertake a technical interpretation of the distribution and extent of the unit reservoir, and to carry out the redetermination. Typically, redeterminations are done by reputable specialized irms, rather than individuals. Contracting in Hydrocarbon Operations 167 3. he establishment of a common database containing all subsurface data, whether raw, processed or interpreted as well as other data such as production data with respect to the ield for submission to the expert. 4. Some unitisation agreements may also speciic that the common database should include all data relating to geological conditions up to a certain distance from the “Unit Area” – typically, this is termed the “Common Data Area”. 5. he right of each party to present a written report and presentation to the expert - this report sets out each party’s technical interpretation of the resources available for distribution within the unit reservoir. 6. he redetermination expert’s obligation to issue a preliminary report setting out his indings on the next round of tract holdings, including the methods of the new tract participations. he report will need to include supporting evidence and must also set out the methodology used to calculate the new set of tract participations. 7. he determination committee then considers the preliminary report. 8. Each party has a right to request that the expert further clarify or further consider his conclusions. 9. Further commentary may be provided by the expert to clarify any issues raised by the determination committee before the issuance of the inal report by the expert. In the absence of any issues being raised by the determination committee, the preliminary report will be deemed to be the inal report. In the event that a redetermination is implemented, the unitisation agreement will contain provisions governing how expenditure and production is adjusted accordingly. Mechanisms vary, however it is common for the unit operator to furnish each party with a statement showing the contribution adjustment to be paid by each party which has an increased unit interest, or to be received by each party which has a decreased unit participation. he parties will have an opportunity to review and if they feel it is necessary, dispute the adjustment using expert determination. he redetermination process – the role of the expert he unitisation agreement typically includes provisions governing the appointment of an expert and may even include a proforma contract which provides the initial basis for negotiation of the contractual relationship between the parties and the expert. In the absence of such a proforma contract, it is critical that the parties expressly establish the terms of appointment for the expert. For redeterminations, the “expert” will usually be an independent company with suicient expertise and resources to undertake the redetermination rather than an individual. Oten each party will provide the determination committee with a list of candidates. Given the importance of redeterminations and to ensure the integrity of the process, engagement letters with the expert may include a warranty that the expert has not conducted any study in relation to the ield in question for any of the parties to the unitisation agreement prior to a speciied time period, and that the expert does not have a conlict of interest with the parties. he parties to the unitisation agreement are accorded the right to provide an initial submission to the expert. his sets out their technical interpretation of the characteristics of the unit reservoir. However, there is no open-ended right of contribution of information and assessment/ re-assessment of the work of the expert, as virtually all unitization agreements state that the determinations provided by the expert their inal report will be inal and binding. 168 Contracting in Hydrocarbon Operations he unitized area and its unitisation agreement versus the non-unit area and its pre-existing JOAs he practice is for all JOAs governing each licence to remain in force and continue to govern conduct operations by the initial consortia outside the unit area. Article 6 of the Unitisation Agreement for the Jubilee Unit contains a detailed set of agreements to govern what are called Non-Unit Operations. he starting extracts of this detailed set of rules is set out below. Unit operations have clear precedence over Non-Unit Operations with Non-Unit Operations being carried out at the risk and expense of the pre-existing consortia: ARTICLE 6 NON-UNIT OPERATIONS, USE OF UNIT FACILITIES 6.1 Right to Conduct (A) Subject to the conditions under this Article 6 and the terms of its applicable Joint Operating Agreement, each Party or JOA Group has the right, at its own risk and expense, to conduct NonUnit Operations within the portion of the Unit Area lying within the Tract or Tracts in which it holds an interest. Except as otherwise expressly provided in Article 6.7, all Non-Unit Operations shall be conducted on behalf of such Party or JOA Group by the Tract Operator for such Party’s or JOA Group’s Tract or by GNPC if GNPC so elects to conduct Non-Unit Operations pursuant to its right to conduct sole risk operations in accordance with Article 9 of the applicable Contract (or, if those Parties participating in the Non-Unit Operation so determine, by Anadarko, provided that the ability to conduct such operations is personal to Anadarko and may not be assigned). (B) he conduct of Unit Operations shall always have precedence over the conduct of Non-Unit Operations. Each Non-Unit Operation shall be conducted in a manner that does not have a material adverse efect on Unit Operations. 6.2 Conditions to Conduct (A) A JOA Group or a Party wishing to conduct Non-Unit Operations must give the Parties and the Unit Operator not less than forty-ive (45) Days prior notice of its intention to undertake such operations and provide the location, the nature of the works, the estimated commencement date and other pertinent information. (B) No Non-Unit Operation (except use of Unit Facilities, which is governed by Article 6.5) may proceed without the approval of the Unit Operating Committee, except operations which GNPC may be entitled to conduct on a sole risk basis under Article 9 of either Contract. he Unit Operating Committee shall approve or reject any proposal to conduct Non-Unit Operations within thirty (30) Days of its submission to the Unit Operating Committee. he proposal shall be deemed approved unless Parties having suicient votes to prevent a passmark vote under Article 8.9(A) (1) notify the Unit Operator and the other Parties within such thirty (30) Day period of their vote against the proposal. A Party may vote against a Non-Unit Operation only if, in its reasonable opinion, the Non-Unit Operations will cause a material adverse efect on Unit Operations. A Party’s vote against a Non-Unit Operation must speciically describe the material adverse efect or efects (which may include, by way of example and not limitation, the Non-Unit Operation’s failure to have a drilling and casing program that adequately protects the Unit Interval, physical conlict (surface or subsurface) between the proposed location of the Non-Unit Operation and the location of Unit Facilities, or the conduct of an unreasonably dangerous operation in the vicinity of Unit Operations) that form the basis for its disapproval. Unit Operating Committee approval shall likewise be required for any material deviation from the announced program for such NonUnit Operation. In the event that the proposed Non-Unit Operation or material deviation from an approved Non-Unit Operation involves the use of a drilling rig or vessel that is standing by in the Unit Area or in a Contract Area speciically for the purpose of conducting such Non-Unit Operation, the foregoing provisions shall apply in respect of such approval, provided that the thirty (30) Day approval period provided in this Article 6.2(B) may be shortened to seventy two (72) hours at the request of the JOA Group or Party wishing to conduct the Non-Unit Operations. (C) Non-Unit Operations shall be conducted under the provisions of the Contract and Joint Operating Agreement applicable to the JOA Group or Party conducting the Non-Unit Operations and shall be at the cost and risk of that JOA Group and/or Party. (D) Non-Unit Operations must not be conducted, or must cease to be conducted, as the case may Contracting in Hydrocarbon Operations 169 be, if the Unit Operator or the Unit Operating Committee determines that the Non-Unit Operations in question present an imminent threat of damage to the Unit Interval or an imminent threat of loss of life, injury, property damage or damage to the environment and so notiies the Party or JOA Group conducting such Non-Unit Operations. Such Non-Unit Operations may not be commenced or resumed until, and on such terms and conditions as, the Unit Operating Committee determines A Party may propose to commence or resume any Non-Unit Operation prevented or suspended as a result of a Unit Operator or a Unit Operating Committee determination under this Article by notice to all Parties, and the proposal shall be deemed approved by the Unit Operating Committee unless Parties having suicient votes to prevent a passmark vote under Article 8.9(A) (1) notify the Unit Operator and the other Parties within thirty (30) Days from the date of receipt of such proposal of their vote against the commencement or resumption of such Non-Unit Operation. A Party may vote against commencement or resumption of such Non-Unit Operation only if, in its reasonable opinion, the Non-Unit Operation will continue to present an imminent threat of damage to the Unit Interval or an imminent threat of loss of life, injury, property damage or damage to the environment. A Party’s vote against commencement or resumption of such Non-Unit Operation must speciically describe the threat or threats that form the basis for its disapproval. In the event that the proposed commencement or resumption of a Non-Unit Operation involves the use of a drilling rig or vessel that is standing by in the Unit Area or in a Contract Area speciically for the purpose of conducting such Non-Unit Operation, the foregoing provisions shall apply in respect of such approval, provided that the thirty (30) Day approval period provided in this Article 6.2(D) may be shortened to seventy two (72) hours at the request of the JOA Group or Party wishing to conduct the Non-Unit Operations. UNITISATION IN GHANA Overview To date the only unitization in Ghana has been the Jubilee Field Unitization. he ield discovered via the Mahogany-1 well in June 2007, covers an area within both the West Cape hree Points (“WCTP”) and Deepwater Tano (“DT”) Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements (“PAs”) and as required by Ghana’s Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. A comprehensive unit operating agreement, the Jubilee UUOA was negotiated between 2006 and 2009. . he parties to the resulting Unitization and Unit Operating Agreement are: Ghana National Petroleum Corporation; Tullow Ghana Limited; Kosmos Energy Ghana HC; Anadarko WCTP Company; Sabre Oil & Gas Holdings Limited; EO Group Limited. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee UUOA. he Jubilee UUOA was executed by all parties and became efective on July 16, 2009. Its table of contents and subject matter are shown by Appendix 3 to this Chapter. Tract participation in the Jubilee UUOA he tract participations were 50% for each block. TGL is the Unit Operator, and Kosmos is the Technical Operator for the development of the Jubilee Field. he accounting for the Jubilee Unit included in these consolidated inancial statements is in accordance with the tract participation stated in the Jubilee UUOA. Deterimination and Redetermination under the Jubilee UUOA Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. he initial redetermination process was completed on October 14, 2011. Any party to the Jubilee UUOA with more than a 10% Unit Interest (participating interest in the Jubilee Unit) may call for a second redetermination ater December 1, 2013. 170 Contracting in Hydrocarbon Operations SERVICE CONTRACTS Service contracts – seismic here are three types of seismic services contracts as follows: Contract type Services covered Seismic acquisition contract Service company provides services to acquire seismic or geophysical data. In OOGP, this also includes provisions to do with the vessel that is to be used. Seismic processing contract Service company ofers services to process ield data using computer programs that generate data which geophysicists interpret for choosing well locations. Seismic licensing agreement. Under this type of contract, seismic contractors acquire geophysical data on a speculative basis over prospective areas. his data is then sold to interested parties. his is diferent from an exploration company or consortium retaining a seismic company to acquire data on an exclusive basis. Drilling contracts15 A drilling contract provides the framework within which a drilling company or drilling contractor provides both rig and personnel to an operator. It could be for either onshore or ofshore operations and covers a wide variety of rig structures. he principal types of drilling contracts are daywork, turnkey and footage contracts with the most common type for ofshore being the daywork contract. Under daywork contracts, the contractor furnishes its rig and crews and receives a stated rate for each day of the contract term. In a turnkey contract, the contractor receives a lump sum for drilling a speciied well or wells. In a footage contract, the contractor receives a speciied amount of compensation for each foot of hole drilled. Customary practice in the ofshore drilling industry provides that the contractor bears risks of personal injury or death of its personnel and generally assumes liability for rig and associated contractor equipment loss or damage. For its part, the operator normally accepts liability for its own personnel and property and, in daywork contracts, generally assumes responsibility for well related risks (including pollution, wild well control, well damage or loss) and reservoir damage. his allocation of liability in which each party assumes liability for its own property and personnel, is oten referred to as the “knock for knock” concept. Contracting in Hydrocarbon Operations 171 Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. he diferent types are concession agreement, production sharing contract; licence contract; service contract and various hybrid forms. his discussion draw primarily from two publications by Timothy Martin, (1) Model Contracts: a Survey of the Global Petroleum Industry 22 Journal of Energy & Natural Resources Law (2004) 281-340; (2) Timothy Martin & J. Jay Park, Q.C. Global petroleum industry model contracts revisited: Higher, faster, stronger 3 Journal of World Energy Law and Business (2010) 4-43. https://academic.oup.com/jwelb/article/3/1/4/1085881/Global-petroleum-industry-model-contracts. his contract type is not discussed in this monograph his contract type is not discussed in this monograph his contract type is not discussed in this monograph his contract type is not discussed in this monograph his contract type is not discussed in this monograph See for more detail, See for more detail, See Andrews Kurth Kenyon, Unitisation – the oil and gas industry’s solution to one of geology’s many conundrums (copy with author); Paul F. Worthington, Contemporary Challenges in Unitization and Equity Redetermination of Petroleum Accumulations (2011), (copy with author); Andrew B Derman and James Barnes, Inst on Oil and Gas Agreements, Autonomy versus Alliance: An Examination of the Management and Control Provisions of Joint Operating Agreements (Rocky Mt Min L Fdn, 1996); Source: Kenyon on Unitisation Source: Kenyon on Unitisation Source: Kenyon on Unitisation For more detail, see Cary A Moomjian, Contractual insurance and risk allocation in the ofshore drilling industry, http://www.iadc.org/dcpi/dc-janfeb99/j-cary.pdf (copy with author). 172 Contracting in Hydrocarbon Operations APPENDICES APPENDIX 1 – MATTERS ADDRESSED BY THE AIPN 2012 MODEL INTERNATIONAL JOINT OPERATING AGREEMENT Contracting in Hydrocarbon Operations 173 174 Contracting in Hydrocarbon Operations APPENDIX 2 - JOINT OPERATING AGREEMENT BETWEEN TULLOW GHANA LIMITED, SABRE OIL AND GAS LIMITED & KOSMOS ENERGY GHANA HC - THE DEEPWATER TANO CONTRACT AREA, OFFSHORE GHANA - 2006 Contracting in Hydrocarbon Operations 175 APPENDIX 3 - UNITISATION AGREEMENT AND UNIT OPERATING AGREEMENT- JUBILEE FIELD UNIT – GHANA - 2009 176 Contracting in Hydrocarbon Operations APPENDIX 4 – SAMPLE DRILLING RIG CONTRACT - ENERMEX Contracting in Hydrocarbon Operations 177 178 Contracting in Hydrocarbon Operations Contracting in Hydrocarbon Operations 179 180 Contracting in Hydrocarbon Operations Contracting in Hydrocarbon Operations 181 6 6 REGULATING ENVIRONMENTAL MATTERS GENERAL CONSIDERATIONS AND REGULATION THROUGH PETROLEUM LEGISLATION Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 183 Introduction And Objectives Of The Chapter he ecological protection dimension of OOGP has emerged as an extremely important issue globally due to the localised, regional as well as globalised impacts of emissions associated with OOGP. In particular, the high level of hydrocarbon-source contributions to greenhouse gas emissions (GHG) and global warming has emerged as a matter of profound concern. here are many dimensions to the ecological aspects of OOGP and an enormous amount has been written. Each facet of the interaction between OOGP and environmental considerations is a scientiic-technical arena in its own right and has its own speciic policy, economic, societal and legal dimension. he aim of this Chapter is to provide the reader with a conceptual overview of the following matters as part of the portfolio of policy understandings essential to appreciating this aspect of OOGP: • Environmental management issues associated with the production and post-production phase of oil and gas ields; • he environmental issues associated with ofshore oil and gas pipelines; • Issues in broad-scale environmental management of ofshore oil and gas regions; • Regulatory regimes in Ghana • Contextual considerations of an economic, geographical and other character. he discussion complements the themes and issues addressed in Chapters ?? to ?? Environmental issues can also be seen as closely related to Chapter ? (Safety considerations) and Chapter ?. he next Chapter focusing closely on regulation of environmental matters through legislation other than petroleum legislation complements this Chapter. An Analytical Perspective On Ecological Aspects Of Oogp1 Given the complexity and sheer volume of the subject matter it is useful to have an overall analytical perspective to help order the diversity of issues and the multitude of writings on this subject. he approach chosen here is to relate the general concept of managing ecological aspects (i. e. environmental management) back to the phases of OOGP that we have studied. To simplify matters, the categorisation adopted is two fold: (1) ecological aspects of the exploration and production phase; (2) ecological aspects of the Post-production phase. To begin with however, an attempt is made to further explain the type of management problem presented by a typical OOGP area. It is also necessary to briely explain the content of the concept of environmental management as applied to OOGP. Categorising Environmental Management in OOGP Chapter ? has comprehensively explained the various activity strands which make up OOGP and has also demonstrated that the actual content of activities (as well as physical structures) change over time with overlapping features as follows: • • • • • the initial geophysical surveys of broad regions to identify exploration targets; the drilling of wells from ships or temporary platforms to test likely targets; spaced development and production drilling from ixed production platforms; construction of transportation and processing infrastructure post-production decommissioning, removal, abandonment and disposal of production platforms and associated infrastructure at the end of each phase of activity. 184 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation In terms of ecological impact, the large or small OOGP complex has the following features: 1. It is a ixed point of continuing disturbance and contamination of the immediate environment (referred to in this Chapter ? as the near-region); 2. It is a source of change and conlict from a broader-scale perspective with of-shore oil ields having a signiicant impact on other users of the marine zone; 3. It is a source of extra load on the social, economic and environmental resources and capacities of the immediate region (especially during construction of production facilities ofshore and support facilities onshore), with the quantum as well as type of load changing in character during the life-cycle of OOGP operations 4. It is an area/space which requires oil companies and regulators to address the removal or abandonment of production platforms ater each phase of activity, with the greatest responsibility accruing at the end of the economically productive life of the ield In terms of identifying the environmental management task, the principal requirement is that regulators and enterprises undertake pollution minimisation and control2 in the context of a highly specialised and technologically speciic form of industrial production with unique economic features (luctuating oil prices, ield production requirements, ield decline, long term capital investment with uncertain payofs etc.). he speciics of pollution control in a hazardous marine environment also have to be added on to the concept of onshore control of pollution from a factory, industrial area or mine. Pollution control relates to all emissions to water and to air as the principal focus. here are two additional dimensions to environmental management in OOGP (see charts below) both of which are relatively new, namely the need to: (1) consider broad-scale multiple use considerations;3 (2) address conservation of the commercial potential as well as diversity of biological resources, requiring now that the critical habitat of marine resources be identiied, managed and protected.4 Offshore Oil and Gas Production: An Offshore Industrial Area Vallega5 provides a useful organising concept for understanding OOGP as a speciic use of the marine zone especially with respect to multiple use considerations and broad-scale environmental management. He argues that efectively OOGP creates a type of use which can be described as an ofshore industrial area. he principal feature of this area is that in the marine zone, a zone characterised by luidity and multiplicity of uses, OOGP removes particular areas from use for a speciic period. Additionally the associated features pipelines as well as onshore staging and processing facilities pose problems for other maritime users. At the same time, the area is cumulatively polluted and due to the relatively ungovernable and inaccessible nature of the marine environment cannot be comprehensively rehabilitated ater production ceases, at least if rehabilitation on land is considered the norm. He notes that “the more numerous the platforms and other use activities are, the deeper the industrial ofshore area inluences other ocean uses”.6 Key Policy Issues he key policy questions that arise from the situation described above include: • What quantity of waste substances can be reasonably introduced into the marine environment during exploration and production in relation to the areas immediately surrounding a Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 185 • • • • • • • • • single platform or cluster of platforms? What quantity of waste substances can be reasonably introduced into the marine environment during exploration and production in relation to larger marine region in which a production ield is located? What is the relative importance of discharges from the oil and gas industry relative to the many other anthropogenic inputs into the marine environment? To what degree do the efects of exploration and production difer in spatial and temporal terms? How persistent are the efects of OOGP on the marine environment in terms of waste discharges and other negative impacts? Which are the particularly sensitive environments which require special consideration, either on a local or broader scale? What are the environmental issues that arise ater oil and gas production facilities reach the end of their useful life? Does comprehensive as opposed to partial recovery of the marine zone, especially the seabed and associated organisms occur ater OOGP ceases? Is there scope for oil producing companies to take a predominant role in self-management of the areas reserved for them under legislation, and if so, what are the best ways of achieving such self-regulation? What role is there for other stakeholders in the marine zones more or less reserved for ofshore oil and gas production? Factors limiting the comprehensiveness and quality of answers include the complexity in the structure and function of marine eco-systems; their oten considerable natural variability; a lack of suitable sampling and monitoring techniques; limitations of public sector funding; and the understandably self-interested focus of industry-based investigations. REGULATORY REGIMES AND POLICY FRAMEWORKS: GENERAL CONSIDERATIONS Earlier Approaches to Environmental Regulation of OOGP Until the late 1980s, environmental provisions in petroleum legislation tended to be imprecise and oten consisted of no more than a statement that the rights-holder should: “conduct all operations in a diligent, conscientious and workmanlike manner in accordance with … generally accepted standards of international petroleum industry practice designed to achieve eicient and safe exploration and production of petroleum”. Some provisions went further to require that all necessary measures also be taken to protect navigation, safety of life, ishing, the conservation of the resources of the sea and the seabed, safety of life etc7. he focus then was more on security of title for the petroleum operator, repayment of loans for inanciers and a secure revenue low for governments and associated parties. Current Approaches to Environmental Regulation he situation is much changed today due to the range of well-known factors associated with the rise of environmentalism as speciically expressed in the OOGP sector. Drivers of a changed approach include: increased OOGP impacts in highly use intensive ofshore industrial areas, principally the North Sea8 and the Gulf of Mexico9; heightened stakeholder awareness, mobilisational activity10 and enhanced participatory capacity;11 increased competitive pressure from 186 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation other users of the marine zone; improved regulatory implementation capacity and most importantly, the “shadow of the future” cast by impending decommissioning requirements in key areas like the North Sea12 and the Gulf of Mexico13. Given the junction of these developments, the contemporary trend14 is to seek to implement ecological protection through a regulatory pyramid15 constituted as follows: (1) general and comprehensive ecological protection obligations in the core petroleum legislation; (2) more speciic actions and requirements in regulations, guidelines or directions giving signiicant lexibility to the regulator and to a lesser extent regulatees; (3) more detailed as well as highly lexible operational and emergency requirements through enterprise-speciic arrangements. Requirements for pre-project environmental impact assessments have also become central and may be driven by requirements in the core petroleum legislation itself, generic environmental impact assessment legislation as well as other conservation and ecological protection legislation. On-going project monitoring and post-project evaluations may also be required, more typically through the forms of subsidiary instrument identiied immediately above. he opportunity for enterprise self-correction on the basis of improved information is thereby enhanced. In addressing the “balance of power” between regulator and industry, the preferred option has always been open to grant the enterprise signiicant autonomy with respect to environmental obligations. Previously that autonomy was exercised to do the minimum without integrating that minimum coherently and transparently into the ongoing operations of the enterprise. Today the preference for autonomy is still maintained – the diference however is that the scope of obligations imposed within that autonomous space has become much more onerous and is increasingly “policed” by afected communities of interest: NGOs, indigenous rights claimants; ishers holding long-term property rights in the form of commercially valuable quotas; well-organised and active recreational users of the sea etc. At the same time, it is expected that environmental requirements will be seamlessly integrated into enterprise activity. Ecological Aspects Of Exploration And Production Exploration and associated activity As shown by Chapter ?, exploration typically consists of: • geophysical surveys from ships and/or aerial overlights following grid traverses over broad areas; • bottom sampling by various methods from ships; • seismic surveys with explosives or various concussive devices • test drilling for geological data From the point of view of pollution by oil, the characteristics of this phase are: • Well drilling is for a short duration – weeks to a few months • Usually a single well or small set of wells is drilled • Wells are drilled vertically and disturb a relatively small area Other aspects of disturbance relate to non-oil waste discharges, noise from survey sonar equipment; impact on ishing, diving, shipping and tourism areas. Onshore aspects include temporary navigation stations and supply ports. he graphics below explain the multiple ecological impacts further. Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 187 Figure 1 Ecological Aspects – Exploration Operations 1 188 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Figure 2 Ecological Aspects – Exploration Operations 2 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 189 Development Drilling And Related Activity As discussed in Chapter ? , this phase involves a larger number of wells, sunk from ships or platforms into selected structures. Extensive tests are made of well and production characteristics using oil-based muds. his phase may generate many single vertical wells with the whole ield completed through sub-sea activity. Once prospectivity is settled, wells are capped, pending production. he development phase is thus an unfolding process which gradually occupies a sector of the marine zone and adjacent onshore areas Pipelines may be initiated during this period. Impacts have the same proile as in the production phase but are of a lesser dimension. Production drilling and related activity Production activities begin as each well is completed during the development phase. he production complex which emerges has production wells and injection wells (diferent pollution outputs are associated with each type); primary processing and storage facilities; drilling platforms; submersible units and pipelines and onshore support. Production and drilling platforms are self-contained facilities (see graphics presented in Chapter ?) with helicopter pads, living quarters for work crews, power supplies, storage tanks etc. Production also requires an extensive shore-based support system for permanent housing of the work force, supplies, waste disposal and reining. Platforms and drill ships are supplied by both ship and air transport. Initial production is oten transported to shore by tanker or barge. his practice may continue for small ields where construction of a pipeline is not economically, requiring a diferent approach by regulatory authorities and the companies in terms of spill plans and other management measures. Once a full production complex is installed, noise, normal to the operation of a large industrial complex is continuous at both onshore and ofshore facilities. Eluent discharges include treated and untreated drilling muds and cuttings; treated and untreated sanitary and domestic wastes, produced waters and other discharges. Onshore, air emissions result from the operations of inal or intermediate stage processing facilities depending on whether major reineries are established close by. Non-routine catastrophes that may occur include blowouts with ires or release of sour gas (hydrogen sulide), platform collapse, pipeline break and tanker collision. 190 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Figure 3 Ecological Aspects – Production Operations Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 191 At-Sea Impacts of the Physical Presence of Structures and Pipelines Placement of a steel jacket or concrete storage structure/platform on the seabed results in either severe local disturbance of the sediments or obliteration of a small area of the seabed. he disturbed sediments then re-distribute around the structure and may cause changes in sealoor communities. Changes may be short-lived and localised or may have a longer-term character with establishment of new community types. he laying of pipelines has the same efect as production platform construction. he impacts would radiate out a few metres to a few hundred metres from each structure. Platforms also modify wave patterns and efectively act as a large artiicial reef. Fouling organisms are attracted to this artiicial reef structure and together with discharged sewage and garbage may generate enhanced ish shoaling. his efect is regarded as beneicial by some ishers (commercial, sport) and may lead to use conlict and accidents between ishers and ofshore oil interests. hese sites may also become areas of high use of anti-fouling substances and paints leading in some cases to tainting and poisoning of ish. he artiicial reef efect is not conined to platforms but is likely to become generalised in any dense production cluster due to the deposition/dumping of equipment from platform, especially during construction, (ropes, anchors, wire hawser, steel tubing etc. ). Shipping Activity Large numbers of supply vessels, working boats, standby vessels, barges and oil tankers pass through or spend time on ofshore oil-ields. Each ship contributes garbage, sewerage and hydro-carbons to the water column and may also cause seabed damage through repeated anchoring. Socio-economic and cultural issues he issues here include land-use questions; demographic and social considerations associated with large scale inlows of construction workers followed by a drop in numbers (the “boombust” problem), and the impact of OOGP on pre-existing carrying capacity. Once OOGP starts, responsibility for management of these problems lies equally with the regulatory authorities and the oil companies, especially where the oil companies become either the major employer in terms of numbers or the highest paying employers in the region. Management is also a broadscale issue. Environmental Issues Associated With Offshore Oil and Gas Pipelines16 Oil and gas pipelines are installed either ofshore, nearshore and/or overland. his discussion focuses on issues arising in coastal and marine locations although many of the issues addressed would also arise in terrestrial situations. he physical features of pipelines are that they can be up to 2 metres in diameter. hey can range in length up to several thousands of kilometers. Pipelines transport both reined and unreined oil. he major facilities associated with oil or gas pipelines include the pipeline itself, access or maintenance roads, the receiving, dispatch or control station and the compressor station or pump stations. Booster stations are also needed at regular intervals along the pipe to help push the oil along the pipeline as its viscosity makes low sluggish with oil sticking along the sides of the pipe. Compression stations serve the same function for gas-pipelines through maintaining the right pressure levels. 192 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Environmental Aspects of Pipelines in the Marine and Coastal Zone Installation of pipelines is at the bottom of the seabed with anchors provided through concrete blocks or concrete casing. he pipeline is sometimes buried. his may require digging a trench on the bottom of the ocean. Pipelines are laid by barges. Trenches are dug by underwater trench-laying machines. Most oten the natural processes of current and wave action are relied upon to bury pipelines over time. Artiicial burial is however possible. Near the coastline, burial of the pipeline is always advisable due to interference from other uses of the near-shore such as trawling, dreding, ship-anchoring, dumping and diving. Proper pipeline operations require maintenance and checking of equipment on a continuing basis. Periodic inspection even underwater is required to ensure that leaks are kept to a minimum and are promptly repaired. Devices used to clean the inside and outside of pipelines can lead to petroleum deposits alongside the pipeline. Pipelines may also attract ish assemblages because they create artiicial reefs. Increased conlict with ishers may result. Table 1 Direct and Indirect Impacts of Ofshore Pipelines Type of Impact Cause Direct Pipeline installation in ofshore Loss of benthic and bottom-feedand nearshore areas (trenching, ing organisms turbidity associated with pipeline) Direct Direct Construction of pipeline Alter aquatic habitats and lead to – termporary resuspension of bot- changes in species composition tom sediments Signiicance will depend on fragility or critical nature of habitat and species afected – for instance seagrass beds and coral more susceptible than deep ofshore benthic habitat Direct Disturbance of marine sediments Resuspension of toxic or contamicontaining harmful substances nated sediments; - ofshore trenching of areas of long-term disposal of toxic chemicals through dumping and at-sea waste disposal(PCBs, mercury etc.). Impacts Activation of reactivity, corrosiveness or toxicity Temporary lowering of water quality above the pipeline May infect ish assemblages nearby Indirect ppropriation of areas of seabed and Afects all seabed marine uses in a foreclosure of use for other activi- broad or narrow area depending on ties the use afected Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 193 ECOLOGICAL ISSUES IN THE POST-PRODUCTION PHASE17. his phase involves the decommissioning, abandonement and/or removal of platforms and linked structures. he issues arise in minor form at the end of all the phases of operations outlined above. An exploration programme which will not mature into a development or production phase faces this issue as do the other phases which do not evolve further ater a certain point. Fully established production complexes will face this problem ater the life of the ield expires or new platforms come to be installed. he decommissioning of pipelines is also becoming an extremely important issue18. FIELD DECOMMISSIONING/ABANDONMENT It is important to distinguish between the plugging and abandonment of individual well19 and the decommissioning/abandonment of a platform or cluster of platforms. he discussion that follows addresses the measures taken to remove OOGP as a marine use once the decision is taken to completely halt or indeinitely defer production from a ield. One platform may service the ield with multiple wells or there may be multiple platforms and their accompanying wells and sub-sea completions. Whilst the terminology tends to be confused with decommissioning and abandonment tending to be used interchangeably, this discussion adopts the following usages: Decommissioning is deined as the activities related to bringing a platform from an operating condition to a cold, hydrocarbon free condition and include activities related to removal or other methods of disposal. he term abandonment is used interchangeably with decommissioning although increasingly the industry is moving away from use of the term since it suggest a lack of interest or absence of environmental stewardship perspectives. Decommissioning as used here includes the process and/or agreement which brings an installation to its inal location(s), where it is re-used, re-cycled or deposited. Anticipating Decommissioning It is now standard practice for decommissioning to be included in the ield development concepts that are drawn up. Regulators require it whilst investors also desire this kind of information. It is also expected that companies will routinely assesss their decommissioning plans from the point of view of inancial aspects since in many countries it is expected that annual provision will be made to address this future liability given that in some contexts, it is possible to claim a tax deduction in advance against the future decommissioning liability. Another way in which decommissioning may be planned for inancially by regulators is by requiring operators to provide inancial securities or guarantees against the costs of decommissioning costs and liabilities. his is the approach taken in the United Kingdom and is the approach taken by the Ghana regime. Decommissioning – the Deferral Option20 As Appendix III shows, there are a variety of decommissioning options, including the option not to decommission. he decision to defer is an interesting one since it shows that in determining an optimal removal date, for facilities, oil companies have to trade of a number of factors. hus in some situations, companies may decide to keep the platform at sea for quite some time ater closing down production, since essentially the cost of keeping the platform at sea are maintenance costs which can be ofset against any future beneits from being able to re-start the platform or use it in some way in the future. On the other hand competing users of the zone, especially ishers may want full decommissioning to take place so they can resume use of the 194 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation zone. he government may also wish decommissioning to be completed due to other pressures. Osmundsen and Tveteras argue that a signiicant decline in production does not automatically lead to decommissioning given that deferral: may be attractive if it is felt that the beneits of deferral of decommissioning might be signiicant. hese beneits take the form of real options gained by postponing the removal of installations: (1) there may be potential gains in the form of improved technology of removal (this is a new industry that is at the very start of its learning curve) (2) the installations may once again be used for extraction purposes in the event of recovery of new petroleum reserves in the vicinity of the platform or in the event that new technology makes it possible to use existing facilities in producing from more remote reservoirs21. he decision to decommission may also be afected by taxation considerations; issues to do with inancial securities given to regulatory authorities or internal relations with other partners in a consortium. Decommissioning Options Once a decision to decommission is taken, what then are the options? hey are highly diverse as shown by the graphics below Figure 4 Decommissioning Options22 The Practicalities of Decommissioning23 As Chapter ? has shown a typical platform consists of the topsides, which contains the drilling, processing, utilities and accommodation facilities, and the supporting substructure or jacket. Steel jackets can weigh up to 40,000 tonnes and are ixed to the seabed by steel piles. he topsides themselves can weigh up to 40,000 tonnes.24. Concrete gravity base structures are even larger25 and sit on the seabed, stabilised by their own weight and penetration of the skirt into the Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 195 seabed26. Unless the platform has been used for storage of oil, only the topsides of the platform would have been contaminated by hydrocarbons - the substructure or jacket is relatively clean extremely sea-weathered steel or concrete. However once a decision is taken to decommission then the practical aspect of the options are: Table 2 – Decommissioning Options Options Explanation Leave platform(s) in place. • his option involves steps (see chart below) to insure oil extraction activity is shut down as well as preparation of the platform to support other uses. • Platforms are stripped of all equipment directly related to the extraction of oil. • Wells are plugged normally and conductors severed and removed completely to a deined level below the mud-line. • All other parts of the platform remain, including potentially much of the above surface structure. Complete Removal of of- • he material from the platform is removed from the ocean shore platform(s) from the for multiple destinations (scrapping and reuse or onshore ocean disposal)(see Appendix VI). • Wells are plugged and no other part of the platform itself would remain above a deined level below the mud-line • he timing of platform removal varies ranging from one at a time all at once or lagged over time for simultaneous removal of multiple platforms to account for economies of scale. Partial removal of the oil platform(s) with disposal of the material either ofshore or onshore. All scenarios under this option require (1) wells to be plugged and conductors to be severed; (2) that the jacket is removed to a greater or lesser degree. Beyond that partial removal encompasses several possibilities: • • that portion of the jacket removed can be reefed on site; the portion of the jacket removed can be transported and reefed at another location; • the portion of the jacket removed can be disposed of onshore; • the entire jacket structure of the platform might be toppled in place; the entire jacket can be transported to another location and reefed there 196 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Table 3 Analysis of Decomissioning Alternatives 27 Activity/Issue Leave-in-place Complete Removal Partial Removal Engineering and Planning Engineering and planning. Costs are less for this phase Engineering and Planning costs are higher for larger platforms Platform preperation Costs are approximate- Costs are estimated ly 25% to 50% fo costs to be 12% of total refor full removal moval costs according to deck weight and size Costs are the same as for complete removal Plugging and abandonment of wells Complete plugging and Complete plugging abandonment of wells and abandonment of required wells required Complete plugging and abandonment of wells required Conductor severing and recovery Complete severing of conductors and recovery from site(s) required Complete severing of conductors and recovery from site(s) required Complete severing of conductors and recovery from site(s) required Mobilisation /Demobilisation Minimal use of heavy equipment required and therefore less expensive High order costs varying with market conditions for hire of heavy lit vessels and heavy marine construction equipment High order costs varying with market conditions for hire of heavy lit vessels and heavy marine construction equipment Platform and structural removal cost includes the cost of removing top- sides, cutting piles and removing jackets. It depends most critically on structure and consequently the depth Costs depend on exact partial disposition option. Platform and No costs incurred as structural removal decks, jacket and piles would be abandoned in place All partial removal options will entail relatively expensive engineering and planning Complete removal where entire structure is reefed another location would not change the size of the the costs relative to complete removal with onshore disposal Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 197 Activity/Issue Leave-in-place Pipeline and pow- Pipelines and cables er cable decommust be completely missioning dealt with the same as in complete removal option Disposal of materials Complete Removal Partial Removal Pipelines and cables are likely to be let in place as complete removal would escalate costs sharply. No precedents available where water depths greater than 700 t Pipelines and cables must be completely dealt with the same as in complete removal option Minimal costs incurred Material would need to be recycled or disposed of elsewhere onshore Transportation costs for materials on land must be included Costs depend on partial removal option chosen Partial disposal which includes change of location would not difer from complete removal signiicantly Site clearance and veriication A degree of costs to provide minimal safety and environmental conditions relative to new uses of the marine area Signiicant degree of Less than complete recosts to provide safe- moval but depend on ty and environmental partial option chosen conditions relative to new uses Navigational safety issues Visual presence minimizes need for additional measures to assist with navigation Costs incurred will be elative to measures required on basis of proposed new uses for area Minimal to maximal depending on use of area and partial disposal option chosen 198 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Figure 5 Decommissioning – he company perspective 128 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 199 Figure 6 Decommissioning – he regulator’s perspective29 It can be seen from the two graphics above that the regulator and the company may see decommissioning quite diferently. TAXATION AND DECOMMISSIONING Providing a tax framework which encourages companies to plan for decommissioning is regarded as a particularly part of OOGP policy. here are currently three approaches to using the tax system to facilitate company commitment to and participation in planning for and implementing decommissioning/abandonment: • • Actual removal costs are tax deductible at the time they occur; he Norwegian method comprising cost-sharing between government and company in in which the State bears a high proportion of the costs (50-80% typically) using the average tax imposition over the lifetime of the ield as the basis for calculating the state’s share of 200 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation • removal costs – the State share is paid directly to the oil companies at the time of removal; Decommissioning/abandonment expenses credited in company accounts are treated as immediately allowable deductions although removal has not yet occurred - balancing of deductions against actual removal costs happens when removal eventually occurs; he third approach has proven controversial since it allows companies to inlate the deductions claimed for decommissioning (known as gold-plating) with the problem likely to be particularly acute if technological developments have made decommissioning much less expensive at the time of eventual removal. Ghana is yet to develop taxation rules to address decommissioning issues. DECOMMISSIONING BONDS Chapter ? provided a discussion of the use of bonds in OOGP generally. In this discussion, more speciic attention is paid to the use of bonding as part of the decommissioning process. Decommissioning Bonds Decommissioning Bonds (DBs) sometimes referred to as reclamation bonds are a specialized type of environmental bond. DBs require operators to demonstrate – before the fact – that they hold or have access to inancial resources adequate to decommission the areas that they have worked in. Much attention has been paid to their design,30 with an equal level of attention paid to their practical operation in the petroleum and mining sectors,31 the main arena in which they are used. As shown by the graphic below, DBs move decommissioning costs up front-end, toward the beginning of the project and provide host governments, communities and other interested parties with a guarantee that adequate inancial resources (or at least a reasonable proportion of such resources) will be available at the end of the project to clean-up areas affected by the extractive process. In particular, they provide assurance that reclamation and decommissioning of a particular area will occur fully or in part, even if the relevant operators have become insolvent. Finally, they reduce the likelihood that the full burden of remediation will have to be borne by governments and the tax-payer. Figure 7 – Matching DBs to the project proile Figure 7 shows that the bond procedure moves the inancial obligation forward. Bonds need to be addressed ater exploration but before development that is during the appraisal/delineation/ evaluation phase. here are many bond types. However the major forms are: (1) Corporate Surety Bonds; (2) Cash Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 201 Collateral Bonds; (3) Investment Grade Securities Collateral Bonds. Some forms of bonds are the pledged assets of an oil company (cash, securities, real estate, etc.). Others are guarantees for a company’s performance analogous to an insurance policy (surety bonds), and some are instruments that indicate the deposit of cash (CDs) or the existence of a line of credit (LOC´s) (Bryan, 1998). Essential Design Features of the Decommissioning Bonding he speciic technical requirements of decommissioning and the regulatory requirements for an efective bond requires that DBs have their own speciic attributes and requirements. Ordinary insurance although similar is to some degree quite diferent. Features which are essential in both legal and operational terms are that: • he DB must be speciically made payable to (or pledged to) the regulatory authority. • he regulatory agency sets the bond based upon the operator’s cost estimate for decommissioning. • he DB amount needs to be based on estimated costs for decommissioning provided to the regulator by a highly reputable third party and must incorporate not just the market costs of decommissioning but also typical costs arising from a situation of forfeiture – the worst case scenario within which the DB will need to be called upon. • he regulator must also add an amount to cover its costs as well as any other reasonable justiiable and foreseeable costs. • It can only returned to the regulatee ater the actual decommissioning has taken place – this is oten not understood and needs to be properly explained. he Surety Bond32 With the surety bond approach, a surety company guarantees to the regulator that the petroleum company will perform all operations related to the decommissioning process at the required time in the future. Should this fail to happen, the surety company also promises that it will pay the bond sum to the regulator, who will then use that money to pay another company to perform the decommissioning. Surety bonds are similar to insurance policies in that the company taking out the bond is required to pay annual premiums with the annual premium set as a percentage of the bond.33 hese annual premiums are tax deductible. Corporate surety bonds cannot be cancelled, even when the operator fails to pay premiums and/or goes bankrupt. he beneit for the company of using a surety bond is that no large sum of money needs to be found in advance and only the premium has to be paid. he surety bond is purchased to provide a inancial guarantee to the regulatory agency - the decommissioning still has to be paid for at the time that is required. Where the company remains solvent and concludes the required decommissioning, the bond is released to the company and the premium payment ceases. If the bonded company cannot meet the decommissioning costs, then the surety company that issued the bond will pay for the decommissioning. Surety bond companies exist in all advanced economies. Many banks also lend in this arena. Surety bonds should only be accepted from companies operating in a well regulated market, where central governments and surety company associations have tight criteria for surety company qualiication and operations. For their part, surety companies base premiums charged on assessments of the inancial standing of the petroleum company (net worth level), credit rating and experience in the decommissioning of installations. 202 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation he Cash Collateral Bond Approach With this approach, cash collateral is placed in an escrow account insured by government. Under the escrow agreement between the petroleum company, the bank, and the regulator, the regulator has full control over the account until it is released ater decommissioning. he company earns annual interest on the account and the interest is available to as it is earned. Since interest is paid annually, there is no change in the total investment and the interest paid remains the same year ater year. Again, the company cannot use the deposited collateral to fund decommissioning and will have to pay for it directly when it falls due. Ater successful decommissioning, the bond money is returned. Should the company fail to decommission, the regulator then uses the money to undertake contract an independent operator to perform the decommissioning. In virtually all cases, cash deposited will not fully meet the costs of decommissioning. he Use of Investment-Grade Securities An investment grade is a rating that indicates that a bond has a relatively low risk of default. Bond rating irms use diferent designations consisting of upper- and lower-case letters ‘A’ and ‘B’ to identify a bond’s credit quality rating. ‘AAA’ and ‘AA’ (high credit quality) and ‘A’ and ‘BBB’ (medium credit quality) are considered investment grade. Credit ratings for bonds below these designations (‘BB’, ‘B’, ‘CCC’, etc.) means that the entity issuing the bond has a low credit rating with a high likelihood of default. Such bonds are referred to as “junk bonds”. Securities are of diferent types and it is important to identify whether the security being ofered has all the required legal attributes within the relevant legal system to qualify as a security. he security in question must also be a long term security (at least 15 to 20 years). hus Certiicates of Deposit must be self-renewing so that when they mature, they roll over for the next term. Treasury Bills/ Notes must also have a long-term maturity period to avoid the need for frequent substitution. he purchase cost of investment grade securities is tax-deductible. However, the interest will not be available to the company until maturity is reached. Ater successful decommissioning and release of the bond, the security is released to the company along with accumulated interest. In case of forfeiture, the security is released to the regulatory agency which then uses the funds to contract an independent operator to perform the decommissioning. he decommissioning and abandonment Fund (DAF) approach With this option, the regulator arrives at a future amount appropriate to the decommissioning that will be required in the future. his amount is then spread over the life of the project. An annual amount is paid by the petroleum company into a fund which is placed in dedicated or earmarked accounts held and managed by a third party on behalf of the regulator. he annual payments are allowable against tax. here are a number of diferent ways in which interest earned by the fund can be used. It seems best that the interest earned should be re-invested in the account. It may however end up being used in other ways by the regulator. he real question here is whether the fund will accumulate enough resources to be able to meet the eventual true costs of decommissioning. Company insolvency will also mean that there may not be enough money paid into the fund. Mixing and matching of bond instruments Prudence requires that regulators demand a mix of bonding instruments from OOGP operators Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 203 so that long-term risks (15, 20, 30 year) projects are appropriately covered. A prudent mix will combine one or more surety bonds, a trust fund where money is deposited annually in escrow, a DAF as well as security grade letters of credit. CONSTITUTIONAL PROVISIONS ON ENVIRONMENTAL PROTECTION he Constitution of Ghana sets out the irst source of Environmental Protection requirements in Ghana. Under Article 36(9): (9) he State shall take appropriate measures needed to protect and safeguard the national environment for posterity; and shall seek co-operation with other states and bodies for purposes of protecting the wider international environment for mankind. In addition, Article 41 (k) requires that all citizens protect and safeguard the natural environment of the Republic of Ghana. ENVIRONMENTAL PROVISIONS IN PEPA 2016 PEPA 2016 is very much framework legislation since it contains very little detailed operational guidance on the environmental obligations to be assumed by entities licensed to undertake petroleum related activity under the Act. Under the heading, “he Environment and Liability for Pollution Damage” PEPA 2016 sets out broad guidelines for regulation of environmental issues far as OOGP in Ghana is concerned. Sections 81 to 84 lesh out this theme covering the issues of: environmental principles and protection (s. 81); impact assessment (s. 82); liability for pollution damage (s. 83) and compensation for pollution damage (s. 84). he most important references to environmental considerations are at ss. 82 to 84 of the statute. Sections 50(1) and 50(2)(d) complement ss. 82 to 84 by requiring operations to be carried out in accordance with good oil-ield practice. Section 82 links the PEPA 2016 framework to the more speciic and detailed regime that is operated by the EPA. hat regime is discussed in the next Chapter. Broad principles of environmental management and protection Section 82, setting out environmental principles and protection, states that a person who undertakes petroleum activities shall take into account and give efect to the environmental principles prescribed in the Environmental Protection Agency Act, 1994 (Act 490), subsidiary legis¬lation made under that Act and any other applicable enactments: PEPA 2016, s. 81(1). As we see in Chapter ?, there is now an elaborate regime for environmental management of OOGP under the EPA’s drat Ofshore Environmental Regulations. An attempt is also made to set out some broad principles in PEPA 2016 . It will be important to ensure that there is complete consistency across all the statutes which purport to articulate these principles whether broadly or in operational detail. he basic principle is that petroleum sector rights-holders under PEPA 2016 (licensees, contractors, sub-contractors or the Corporation) will be required to (“ shall”) take necessary (not “all necessary”) measures to ensure that petroleum activities are conducted in (1) a safe and secure manner, (2) free from accidents, (3) and without waste dumping and pollution. he second principle is that petroleum sector rights-holders shall establish and implement efective and safe systems for the disposal of their waste as well as its treatment. hey shall also ensure that they prevent pollution: PEPA 2016, s. 81(2). Actions taken by regulates, must be in accordance with applicable enactments and must meet (or perhaps be guided by?) by the standards of best petroleum industry practice.34 Section 81(2) also provides that regulatees must ensure that they manage their hazardous waste streams properly by establishing systems to track the source, 204 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation transport and destina¬tion of any potential hazardous waste from their activities. It is notable that Ghana legislation does not yet refer to broader (and contested) foundational principles. We refer here to principles like: the polluter pays principle; the precautionary principle and the user pays principle. Section 80 on qualiications is also relevant here. It states that the licensee, contractor, sub-contractor and the Corporation shall ensure that a person engaged in petroleum activities possesses the requi¬site qualiications and competence to perform the functions in a prudent manner: PEPA 2016, s. 80. Environmental Impact Assessment he uncontested concept and practice of environmental impact assessment(EIA)35 prior to the approval of petroleum sector operations is addressed in detail by s. 82. It provides that a petroleum rights-holder under the Act, can only conduct petroleum activities in an area ater the required environmental impact assessments have been conducted and any other relevant environmental statutory requirement set out by the Environmental Protection Agency Act, 1994 and other appli¬cable enactments have been complied with: PEPA 2016, 82(1). To avoid any doubt about the core activities to which EIA applies under PEPA 2016, these are speciied by s. 83. he list which is not a closes list sets out the following activities: reconnaissance activities under s. 9; exploration drilling under s. 24; development and operation under s. 27; construction of transportation, treatment and storage facilities under s. 38; decommissioning under s. 43; and plugging and abandonment of a well under s. 46. In a cross-reference back to s. 7 of PEPA 2016 (Area Management by the Minister) s. 82(2) states that a strategic impact assessment shall be undertaken before the opening of a new area under section 7. Liability for pollution damage – strict liability for Contractors, GNPC and unauthorized operators Section 83 is a particularly important part of the Act. It states that any pollution damage36 caused by or resulting from the petroleum activities will engage the strict liability (as applicable to the circumstances) of licensees, contractors or GNPC: PEPA 2016, s. 83(1). Strict liability also extends to pollution caused by or resulting from unauthorized activity. he unauthorized person who is directly responsible for the activity carries such liability together with any persons who took part in the unauthorized activity as well as persons who knew or should have known that the activity was unauthorized: PEPA 2016, s. 83(3). Joint and Several Liability Where several licensees or contractor parties are involved in petroleum activities that generate environmental liability, the parties concerned are to be jointly and severally liable for damage caused by or resulting from their activities: PEPA 2016, s. 83(2). The strict environmental liability of GNPC under PEPA 2016 Sole Responsibility Arrangements GNPC is stated explicitly to be liable where it is conducting petroleum activities as deined Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 205 by s. 11(1) of PEPA 2016. he reference to s. 11(1) activities by GNPC (the Corporation) is important, as this section governs “Sole responsibility” petroleum activities by GNPC. As discussed in Chapter ?, “Sole responsibility” petroleum activities are activities that are undertaken by GNPC under the following terms and conditions: (1) hey take place in an area opened for activity under PEPA s. 7 but which are not covered by a petroleum agreement: PEPA 2016, s. 11(1); (2) hey can only take place on the basis of an authorization by the Minister: PEPA 2016, s. 11(1); (3) his authorization must have been approved by Parliament under Article 268 of the Constitution: PEPA 2016, s. 11(2); (4) Sole responsibility activities can only take place in accordance with annual programmes embedded in long-term exploration and produc¬tion programmes drawn up by the Corporation and approved by the Minister in consultation with the Commission: PEPA 2016, s. 11(3)(b); (5) GNPC may utilize sub-contractors to undertake sole responsibility activity under service contracts with the strict proviso that such sub-contractors are not entitled to any share of the petroleum produced as a result of their operations: PEPA 2016, s. 11(4). Efectively, as a matter of law, production-sharing arrangements are prohibited.37 Operational and financial responsibility for remedial measures to address pollution damage Section 83(4) requires all licensees, contractors, sub-contractors (and where relevant the Corporation) to institute the necessary measures to remedy any pollution caused. Where the remedial measures are not undertaken within the time limit set by the Commission or the Minister, a third party may be engaged to undertake such activity. he defaulting licensee, contractor, sub-contractor or the Corporation will then be liable for any related costs. It is instructive to note that the Ghanaian legislation does not yet mention extended liability to recover pollution costs, an accepted principle of environmental responsibility in the advanced economies.38 Compensation for pollution damage and apportionment of responsibility amongst operators and GNPC Relecting the fact that all petroleum sector exploration, development and production activity in Ghana is undertaken by consortia, PEPA 2016, s. 84(1) requires that claims for compensa¬tion with respect to pollution damage should initially be made against the operator where there are several contractor parties under a petroleum agreement or several licensees under one licence. he consortia are then expected to internally address how compensation issues will be managed. his new provision should ideally lead the various consortia to seriously direct their attention to this matter as soon as possible. It may be that the Petroleum Commission and the EPA will need to direct the attention of the consortia a well as GNPC to this part of the law. Apportionment rules are set out by s. 84(2). It provides that where there are several licensees or contractor parties and one of them fails to pay the share of the compensation, the unpaid amount shall be paid by the other licensees or contractor parties in proportion to their participating interest: PEPA 2016, s. 84(2). Management of Environmental Force Majeure situations and the identification of responsible parties for purposes of payment of compensation Section 84(3) tries to manage this complex and diicult situation. In such situations (where an event of force majeure creates or includes a situation of pollution damage) it is oten diicult to ind a responsible party to pay compensation. It is also oten equally diicult to ind responsible persons to actually remedy the pollution damage. his section of the statute tries to provide 206 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation a framework to manage situations of this type. It states that where an event of force majeure results in pollution damage, the Minister shall, on the advice of the Commission, assess the damage taking into account the scope of the activity; the measures taken to avoid or mitigate the efects of the force majeure event; the situation of the party that has sustained the damage as a result of the force majeure event, and the insurance opportunities for each party. Ater this assessment, and on the basis of it, the Minister has the power to require the person liable for the pollution damage to pay compensation. his clause is a commendable and brave attempt to foresee and try to manage such situations (for example a major oil spill). However it raises more questions than it answers. Two issues immediately spring to mind: (1) does Ghana have the institutional capacity to credibly support Ministerial assessments which sheet home responsibility in this way? (2) will operators (especially the large ones) accept any such assessment and the imposition of responsibility by the Minister, or will they litigate in local and/or foreign fora, including arbitration? Corporate responsibility to immediately respond to major environmental accidents or events Where an accident or emergency may lead to or has resulted in loss of life or personal injury, pollution or major damage to property, licensees, contractors and the Corporation are required, to the extent necessary, suspend their petroleum activities: , s. 78(1)(a). In terms of length of suspension time, the legislation speciically requires the length of time to be determined by the petroleum industry’s operating standards incorporated into Ghana law by PEPA 2016, s. 50. his reference to industry standards is appropriate given that Ghana does not have any speciic experience with a major emergency and has not directed attention to formulating any rules speciic to how the industry operates in Ghana. he reality however is that for many of the types of situations that might occur, there may be conlicting petroleum industry guidance (typically set out in non-binding guidelines from peak industry groups) or inluential regulators: US, UK, EU, Norway and to a lesser extent Canada and Australia. he issue is the extent to which some of these guidelines may even be applicable to a Ghanaian or more broadly, an African context. Finally, operators are also required to immediately (but not later than forty eight hours) inform the Minister and the Commission of any suspension of activity in response to an emergency: PEPA 2016, s. 78(1)(b). Ministerial emergency powers to address major environmental accidents or events Under s. 78(2), the Minister also has a broad power to suspend petroleum activities where an accident or emergency may lead to or has resulted in loss of life or personal injury, pollution or major damage to property. In such situations, the Minister (on the advice of the Commission and to protect the public or national interest) has the power to direct that petroleum activities be suspended. He may also impose particular conditions and/or allow continuation of activities. Section 78(1) requires the Minister and the Commission to act using a “to the extent necessary” test. his will require balancing public safety, environmental considerations, economic considerations, security considerations as well as any other situation speciic considerations. Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 207 JURISDICTIONAL REACH OF THE PEPA 2016 RULES Jurisdictional Reach of the Environmental Provisions of PEPA 2016 – physical area covered and the objects of the statute Article 4(2) of the 1992 Constitution of the Republic of Ghana vests Parliament with the power to provide for the delimitation of Ghana’s territorial sea, contiguous zone, Exclusive Economic Zone (EEZ) and continental shelf. An earlier statute PNDCL 159, established a 200 nautical mile limit for the EEZ and the Continental shelf.39 Under PEPA s. 1, the environmental regime is efective within the following areas of the Republic of Ghana: under and upon its territorial land,40 inland waters, territorial sea, exclusive economic zone and its continental shelf. here is however no speciic reference to environmental protection in the objects section of the Act, section ?. hat section reads: Object of the Act - he object of the Act is to provide for and ensure safe, secure, sustainable and eicient petroleum activities in order to achieve optimal longterm petroleum resource exploitation and utilisation for the beneit and welfare of the people of Ghana. Presumably environmental issues are a subset of safe, secure, sustainable and eicient petroleum activities in Ghana. Section ? is also potentially relevant, even though again, there is on speciic reference to environmental issues. hat section of the Act reads: Management of petroleum resources - the management of petroleum resources by the Republic of Ghana shall be conducted in accordance with the principles of good governance, including transparency and accountability and the object of this Act. One can foresee a situation where transparency and accountability will be central to any environmental problem that occurs in the future. Jurisdictional Reach of the Environmental Provisions of PEPA 2016 – activity covered Under PEPA 2016 the term “Petroleum activity” or “activity” covers any of the following operations: • seismic or other surveys; • drilling; • construction and installation of a facility; • operation of a facility; • signiicant modiication of a facility; • decommissioning, dismantling or removing a facility; • pipeline construction and installation; • operation of a pipeline; • signiicant modiication of a pipeline; • decommissioning, dismantling or removing a pipeline; • storage, processing or transport of petro- • associated/supporting operations or works leum; related to a petroleum activity PERMITS AND TITLES GRANTED UNDER PEPA 2016: ENVIRONMENTAL CONSIDERATIONS As stated in Chapter ? ,the following titles and permits are granted under PEPA 2016 with one of the key distinctions being whether the licence is exclusive or non-exclusive: 208 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Table 4 Licences under PEPA 2016 Exclusive licences Non-exclusive licences An exploration right under the Petroleum Reconnaissance licences Agreement A production licence under the Petroleum Agreement Pipeline licences Infrastructure licences Chapter ? demonstrated the range as well as complexity of decision-making considerations under the PEPA 2016 as a modernised concession regime. he range of matters requiring decisions to be made and approvals to be granted include: grant of acreage; approval of exploration and ield development and production plans etc. Whether the licence is exclusive or not also has signiicant implications for environmental management since exclusive licences more efectively facilitate the devolution of regulatory authority to companies/enterprises. he environmental considerations speciic to each type of licence are discussed in the tables below. We also sign-post how environmental issues can be more efectively operationalised and used by the regulator as an incentive for improved environmental performance. he issue here is whether decision-makers will be prepared to use the permitting process to advance environmental protection and management objectives in an integrated and purposeful way. Environmental Considerations: PEPA 2016 regulator decision-making for exclusive licences Relevant decision-making considerations and critical points for inluencing regulatee behaviour are set out below: Table 5 – Environmental decision-making considerations for exclusive licences Principal Issues covered by the PEPA 2016 Environmental Aspects Invitations to apply for rights under the Act • Ofshore areas identiied by Ghanaian authorities and made available for bidding by interested local and foreign companies • Statutory requirement under s. 7 of the Act for a Strategic Broad scale assessment to be made prior to release of areas for bidding41 • Environmental considerations are relevant in inal selection of areas made open for exploration. • Environmental record of applicant may be taken into account in deciding application- this may be a positive or negative environmental record - currently, this is not speciied in the legislation or the current rules in use as a clear pre-condition. Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 209 Principal Issues covered by the PEPA 2016 Environmental Aspects Grant of exclusive exploration permits to successful applicants with decision-making on conditions to be attached to permit Environmental conditions will need to be attached to licence - may relate to applicants record, special characteristics of the area, the type of oil and gas, special community concerns, conlict with other marine users etc. Environmental considerations will need to be addressed in terms of well decommissioning & capping of wells; removal of obstructions safety of other uses of the zone; seepage from wells; decommissioning etc. Currently not a stated pre-condition for grant of retention leases may be addressed administratively Renewal of permits and Environmental considerations may be of relevance in securing redetermination of connewal ditions in the renewal period Granting of a production licence during the development and production phase of the petroleum agreement Environmental considerations relevant - conditions may be imposed - environmental plans of applicant relevant - Environmental conditions usually attached to licence - may relate to applicants record, special characteristics of the area, the type of oil and gas, special community concerns, conlict with other marine users etc. Granting of pipeline licences Environmental considerations relevant - conditions may be imposed - environmental plans of applicant relevant - Environmental conditions usually attached to licence - may relate to applicants record, special characteristics of the area, the type of oil and gas, special community concerns, conlict with other marine users etc. Granting of infrastructure licences Environmental considerations relevant - conditions may be imposed - environmental plans of applicant relevant - Environmental conditions usually attached to licence - may relate to applicants record, special characteristics of the area, the type of oil and gas, special community concerns, conlict with other marine users etc. ower to impose conditions on grants of title PEnvironmental considerations relevant - Environmental conditions usually attached to licence - may relate to applicants record, special characteristics of the area, the type of oil and gas, special community concerns, conlict with other marine users etc. Environmental Considerations: PEPA 2016 regulator decision-making with respect to non-exclusive licences and other transactions Relevant decision-making considerations and critical points for inluencing regulate behaviour are set out below: 210 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Table 6 – Environmental decision-making considerations for non-exclusive licences Principal Issues cov- Environmental Aspects ered by the PEPA 2016 Issue of non-exclusive li- Environmental considerations relevant and need to be considered cences – reconnaissance before issue of licence licences Applicants may be asked to prepare environmental plans or impact statements Cancellation of titles for Environmental considerations may provide a basis for cancellation non-compliance with of title in that the environmental permit can be cancelled conditions of the title Requirement for adoption of good oilield practices Public access to data submitted by applicants Environmental considerations relevant to the extent that environmental considerations a part of good oilield practice Approval of applications for the registration of legal transactions, including farm-outs and transfers of title Environmental considerations relevant, including management record of applicants conditions may be imposed - environmental plans of applicant may be relevant Environmental considerations not currently a key part of data requirements for petroleum operators No evidence however that taken into account by Ghana authorities Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 211 Exclusive Licence 1: Environmental Issues during the Exploration Phase of a Petroleum Agreement Aspects relevant to exploration discussed in more detail below: Table 7 - Environmental Issues during the Exploration Phase of a Petroleum Agreement Type of Permit/ Licence Rights granted under permit/licence Exploration rights • under a Petroleum Agreement Exclusive licence based on an agreed work programme • • • • Environmental Considerations Exploration permits provide • a titleholder with an exclusive right to carry out operations relating to exploration of petroleum within the bounda• ries of the permit area. Rights include the right to carry out seismic surveys, to drill exploration and appraisal wells and to carry out production tests on any petrole- • um pools in the area Work-programme based exploration permits - hese permits are granted to the company whose work programme is the most attrac- • tive. Each permit is for 7 years with options for renewal with • acreage relinquished at each renewal. Companies are re- • quired to carry out a guaranteed minimum work programme. Environmental considerations are an important part of the process of granting an exploration permit although they are not a paramount consideration Environmental considerations can be made a key parameter of choice in relation to both work programme and cash-based bids. It is possible to specify minimum environmental aspects of the work programme or alternatively require a speciic element of the cash bid to relect environmental management aspects Environmental conditions are normally imposed on exploration permits Environmental plans are now required as part of bids Exclusive character of licence shapes the form in which environmental considerations can be addressed Discovery of petroleum under an exploration permit is followed by the grant of a production licence or a retention lease taking into account company and government strategic options and choices 212 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Exclusive Licence 2: Environmental Considerations during the Development and Production Phase of a Petroleum Agreement Aspects relevant to development and production are discussed in more detail below: Table 8 - Environmental Issues during the Development and Production Phase Type of Permit/Licence Rights granted under permit/licence • Production licences are a mandatory right where a commercial petroleum Exclusive licence discovery has been made. • he licence applies to a deined locaGranted for a term up tion corresponding to the commerto 25 years cial character of the ind • his is an exclusive right to carry out commercial operations for the recovery of petroleum - drilling of development wells, installation of production platforms and ield processing facilities • Further exploration activities allowed provided that these are fully located in the production licence area Retention lease • Awarded where petroleum discovery not commercially viable. • Allows rights holder to maintain Exclusive licence ownership of the licence to explore for extra time - 5 years with renewal periods of ive years • Awarded where discovery is not currently viable but may become so in 15 years • Retention leases are convertible to production licences at any stage • Retention licences may be cancelled by government where it considers that petroleum production is viable but not being undertaken • Production licence can be applied for within 12 months of notice to cancel being given by government • Lessee can also be directed to reassess commercial viability of deposits up to twice during the lease period Production Phase Environmental Considerations • Conditions may be imposed • Environmental plan required before licence is approved • Quality of environmental plan may reasonably be expected to be high given prior experience during exploration phase Conditions can be imposed Environmental plan is required Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 213 Exclusive Licence 3: Environmental Considerations: Infrastructure Licences & Pipeline Licences under PEPA 2016 Section 38-42 Aspects relevant to infrastructure licences and pipeline licences are discussed in more detail below: Table 9 - Environmental Issues during the Development and Production Phase Type of Permit/Licence Rights granted under permit/ Environmental Considerlicence ations • Covers full range of ield processing activity as under a production licence Exclusive licence • Applies inside or outside a production licence area Similar to production li- • Additionally, permits the holdcence er to perform other petroleum processing facilities (e.g. conNew type of licence version of gas to methanol or LNG) which are currently not contemplated under production licences • Granted for a ixed term on a case by case basis • Minister may order interconnections between facilities Pipeline Licences • Covers construction and operation of pipelines to transport petroleum to shore or to anExclusive licence other ofshore facility • Granted for a ixed term on a case by case basis • Minister may order interconnections between facilities • Applies inside and outside a production licence area and may end on land Infrastructure Licences (for eg FPSO) • Conditions can be imposed • Environmental plan is required • Impacts on environment likely to be more complex and cumulative • Conlict with other uses of marine zone • Conditions can be imposed • hird-party access considerations • Conlict with other uses of marine zone 214 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Environmental Issues in non-exclusive licences Aspects relevant to non-exclusive licences are discussed in more detail below Type of Permit/Licence Rights granted under permit/ Environmental Considerations licence Reconnaissance • Issued to petroleum exploralicence tion companies to undertake Non - e x c lu s i v e seismic or other geophysical or right geochemical survey work. It may be in an area subject to a petroleum agreement or in areas not subject to a petroleum agreement. • Environmental plan may be required • Multi-use considerations important • Environmental self-management may be diicult for typical holder - i. e. SME or smaller irm • Conditions will need to be imposed POST-PRODUCTION ISSUES UNDER PEPA 2016 Ghana does not currently have a comprehensive regime for post-production issues relecting the fact that Ghanaian ields are extremely new. However, as shown in more detail, further below the issue is now catered for by ss ? to ? of PEPA. It is also addressed in considerable detail by the drat Ofshore Environmental Regulations. Regulatory Framework for Decommissioning he framework comprises: • • • • • Ghana’s international law rights and obligations. Domestic legislation and subsidiary rules. Regulatory review procedures applied on a case by case basis. Industry guidelines and adherence to best-practice likely, following North Sea and US Gulf of Mexico models as exemplars of good oilield practice in a mature production environment. Company level procedures, manuals and experience The international law framework he international law framework applicable to Ghana has three elements: (1) provisions in the UN Law of the Sea Convention;42 (2) provisions in the London Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (London Convention 1972); (3) provisions of sot law as set out in Guidelines issued by the International Maritime Organisation in 1989.43 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 215 REGULATION OF CESSATION, DECOMMISSIONING AND REMOVAL OF FACILITIES UNDER PEPA 2016 Decommissioning plan and plan funding he decommissioning framework applies to two situations: permanent cessation of operations and license or petroleum agreement expiry: PEPA 43(2). An attempt is thereby made to cover as many of the situations in which decommissioning might be required. Section 43 (1) obliges a licensee or contractor who operates a petroleum facility to submit a decommissioning plan to the Minister. he Minister is then required to seek the advice of the Commission on the proposed plan. he plan must contain a detailed proposal for either: (1) shutdown of operations and the disposal of petroleum facilities; or (2) further use of the facilities in place for petroleum activities. his second option clearly opens up the possibility that facilities may be used for carbon capture and storage operations. However, this option is not then developed further under the statute: PEPA 2016, 43(5). Under Option 1, disposal may include: (1) removal of petroleum facilities for use elsewhere; (2) uses other than petroleum activities; (3) complete or partial removal or abandonment of the facili¬ties: PEPA 2016, 43(6). he plan must also contain information and evaluations to assist Ministerial decision-making with respect to the approvals required under the Act: PEPA 2016, 43(7). he information provided to the Minister must include an environmental and social impact assessment: PEPA 2016, 43(7). Section 43(8) applies the decommissioning obligation to GNPC when it is undertaking Sole Responsibility activity under s. 11(1) of the Act. It is also compulsory for a licensee of contractor to establish a decommissioning fund: PEPA 2016, 45. However, the rules for this fund have not yet been established. Timing of plan submission Section 43(2) provides that the earliest a plan must be submitted is ive years before permanent cessation of operations. he latest is two years before cessation of operations/license/petroleum agreement expiry: PEPA 2016, s. 43(2). he Minister can also specify an alternative time: PEPA 2016, s. 43(2). In those situations where a licence of petroleum agreement is terminated earlier than its expiration date, the decommissioning plan is to be sub¬mitted as soon as is practicable and in any event not later than ninety days ater the termination date: PEPA 2016, s. 43(3). Under 43(4) they must also immediately notify the Minister where it becomes obvious that use of a facility is likely to occur before the date set out in the licence or agreement. Ministerial approval/disapproval of decommissioning plans Section 44(3) provides that the Minister in approving a plan, must consider the consider the various interests involved, including the impact of the decision on local communities, agriculture, isheries and other afected interests and the environmental, safety, technical and economic consequences of the disposal alternatives. Where the Minister approves a plan, they must also set out a schedule for plan implementation: PEPA, s. 44(1). Ministerial disapproval, requires notiication in writing to the licensee or contractor of the reasons for disapproval together with required next steps which are (1) that certain conditions be satisied by the contractor or licensee; or (2) that a new or amended plan be resubmitted to the Minister: PEPA 2016, s. 44(2). Obligations and liability with respect to decommissioning plans 216 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation PEPA 2016 at s. 44(4), requires a licensee or contractor to ensure that they implement an approved plan in accordance with its terms and conditions. hey must also provide a report to the Minister ater the decommissioning plan has been implemented: PEPA 2016, s. 44(5). he obligation to implement the plan and also to report on it are stated by s. 44(6) to be binding on the licensee or contractor ater the expiration of the applicable licence or the petroleum agreement. Section 48(1) imposes strict liability on contractors or licensees. he liability is towards the Republic itself and applies to situations of non-implementation of an approved plan as well as situations of loss or damage caused, in connection with the decommissioning of the facility or with respect to any other aspect of plan implemen¬tation: PEPA 2016, s. 48(1). Again this section applies to the Corporation where it undertakes petroleum activities under section 11 (1): PEPA 2016, s. 48(2). Secondary Liability - Holders of Participating Interests and Holders of Assigned Rights Assignors with a participating interest in a petroleum agree¬ment have secondary liability with respect to the inancial obligations associated with the decommissioning plan: PEPA 2016, s. 44(7). his responsibility is limited to a share of the costs calculated on the basis of the size of their participating interest: PEPA 2016, s. 44(7). Assignors under a licence (whether assigned in whole or in part) also have secondary liability. It is however limited to costs related to petroleum facilities, including wells, which existed at the time of the assignment: PEPA 2016, s. 44(7). Ministerial assumption of responsibility for decommissioning Licensee or contractor failure to implement a decommissioning plan within its stipu-lated time limit and/or in accordance with its terms and conditions compels the Minister (in consultation with the Commission) to take necessary measures to implement the plan for and on behalf of the licensee or contractor. Such implementation will be at the account and risk of the licensee or contractor and extends to the engagement of sub-contractors to carry out the plan: PEPA 2016, s. 44(9). Plugging and abandonment of wells Section 46(1) provides that a contractor who intends to plug and abandon a well must immediately submit notiication of such intention to the Commission. he closure or plugging of a well can only be carried out with the prior written approval of the Commission and must be undertaken in a manner consistent with international best practice and as approved by the Commission: PEPA 2016, s. 46(3). Contractors are required to carry out periodic surveys of wells plugged and abandoned: PEPA 2016, s. 46(4). Detailed rules will be prescribed at some time in the future. Again this section applies to the Corporation where it undertakes petroleum activities under section 11 (1): PEPA 2016, s. 46(5). Restoration of affected areas Section 47(1) imposes a duty on contractors and licensees to ensure that they restore afected areas ater they terminate petroleum activities in such areas. hey must also remove any causes of damage or danger to the environment in accordance with applicable enactments. Again this section applies to the Corporation where it undertakes petroleum activities under section 11 (1): PEPA 2016, s. 47(2). Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 217 CHAPTER SUMMARY his Chapter has described the ecological aspects of the ofshore oil and gas industry in considerable detail demonstrating that essentially environmental management as practised in OOGP focues on control of pollution from sites and technologies which combine elements of (1) the factory; (2) the mine; and (3) the ship. he activity is undertaken in remote and hazardous locations subject to signiicant variations in external operating conditions in an industry with signiicant economic uncertainties including extremely sharp variations in prices. he material presented has discussed: • • • • • Environmental impacts in the immediate region of drilling platforms and production complexes Environmental management issues associated with the post-production phase of oil and gas ields and production facilities he environmental issues associated with ofshore oil and gas pipelines Regulatory regimes in Ghana under PEPA 2016. General considerations of an economic, geographical and other character. It has been shown that the environmental aspects of OOGP relect the industrialized character of the activity as well as the varying impacts of diferent phases of OOGP. he industry requires broad-scale environmental management because in general oil and gas industry operations prevent other users from utilizing the speciic regions occupied by and adjacent to the oil and gas focus of activity. Although catastrophic events associated with the industry are rare, the impacts of such events can be severe. Accordingly considerable resources have to be devoted to planning for such an eventuality whilst an extremely broad range of considerations have to be taken into account. 218 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. See generally, J. M. Swan, J. M. Nett and P. C. Young (eds) Environmental Implications of ofshore oil and gas developments in Australia, (1994) Australian Petroleum Association Sydney; For more general discussion, see (1) Stanislav Patin, Environmental Impact of the Ofshore Oil and Gas Industry. EcoMonitor Publishing, New York, (1999); (2) Z. Gao, “International Petroleum Exploration and Exploitation Agreements: a Comprehensive Environmental Appraisal” Vol 12 No 2 Journal of Energy and Natural Resources Law: 240-256, (1994). See this Chapter ? - Appendix II - Types of Waste Discharges, Emissions and Debris from Ofshore Oil and Gas Installations See this Chapter - Appendix I - Ofshore Oil and Gas Production: - Near-Region Environmental Impacts; & Appendix II - Issues in Broad-Scale OOGP Environmental Mangement in Chapter ?. See this Chapter - Appendix III Habitat and Resource Sensitivities to Pollution from Ofshore Oil and Gas Installations & the Appendix on Habitat and Bio-Diversity Disturbance from Oil Platforms in Chapter ? Vallega. A. Fundamentals of Integrated Coastal Management 1999 Chapter 7, 109. Vallega. A. Fundamentals of Integrated Coastal Management 1999 Chapter 7, 109. See Onorato, Legislative Frameworks Used to Foster Petroleum Development AMPLA Yearbook 1997 247285, 259-260. See for instance, Herriot-Watt University, An analysis of U.K Ofshore Oil & gas Environmental Surveys 197595 (2001)http://www.oilandgas.org.uk/issues/ukbenthos/docs/analysissurveys.pdf See for instance, LGL Ecological Research Associates/American Petroleum Institute, Environmental Trends in the Gulf of Mexico in the Twentieth Century: he Role of the Ofshore Oil and Gas Industry (1997) - http:// api-ep.api.org/ilelibrary/LGL_Report.pdf; American Petroleume Institute, Meeting the Environmental Challenge: Oil and Natural Gas Operations in the Gulf of Mexico http://www.api.org/ehs/gulf he two most striking examples are the global mobilization against Shell with respect to its activity on Ogoni lands in Nigeria and the Europe-wide mobilization against Shell with respect to its proposal to dump the Brent Spar production platform on the High Seas. For the inal Shell proposals for Brent Spar disposal, see, Anonymous, Shell picks re-use option for Brent Spar Oil and Gas Journal (February 91998) 30-32. See the reports of the various International Petroleum Industry Environmental Conservation Association (IPIECA) workshops and roundtables between industry, regulators and other communities of interest:: (1) IPIECA Workshop Environmental issues over the next 25 years, April 1999 Dallas, Texas; (2) IPIECA Workshop on Corporate Responsibility 12th April 2000 Paris France; (3) IPIECA Stakeholder Dialogue 22-24 April 2003 Durdent Court UK Final Report 5 June 2003; (4) IPIEA he oil and gas industry from Rio to Johannesburg and beyond. See Auris Environmental, Report to UKOOA, An assessment of the environmental impacts of decommissioning options for oil and gas structures in the UK North Sea (1995); Corcoran, A. he abandonment of ofshore oil and gas ields, Vol1: he regulatory framework. Oilield Publications Limited; Ashley Pittard, Abandoment Costs Vary Widely Worldwide Oil and Gas Journal (March 17 1997) 84-91. Ron Twatchman, Ofshore Platform Decommissioning perceptions change Oil and Gas Journal (December 8 1997) 38-41; Ashley Pittard, Abandoment Costs Vary Widely Worldwide Oil and Gas Journal (March 17 1997) 84-91. Onorato, Legislative Frameworks Used to Foster Petroleum Development AMPLA Yearbook 1997 247-285, 259-260. he regulatory pyramid approach to environmental regulation is elaborately set out in Ayers. I. and Braithwaite, J Responsive Regulation: Transcending the De-regulation debate. Oxford University Press, New York (1992). See J. B. Hinwood and L.R. Dennis, “Environmental issues in pipeline facility abandonment” he APPEA Journal 1998, Part 2 172-177. See generally, U.S. Department of the Interior, Minerals Management Service, Decommissioning and Removal of Oil and Gas Facilities - Ofshore California: Recent Experiences and Future Deepwater Challenges Ventura, California September 23-25, 1997; Kemp, Economic and iscal aspects of oil and gas ield abandonment: he UK Continental Shelf Energy Policy (1992); Michael Vincent McGinnis, Linda Fernandez and Caroline Pomeroy, he Politics, Economics, and Ecology of Decommissioning Ofshore Oil and Gas Structures OCS Study MMS 2001-006, 28-29; Petter Osmundsen and Ragnar Tveterås Disposal of Petroleum Installations Major Policy Issues January 2000, mimeo (Copy with author); H. B. Gof Decommissioning: An alternative approach he APPEA Journal 1997 560-564; Reggio, W.C. Jr. (1987). Rigs to Reefs. Fisheries. 12, pp. 2-7; Gurney, J. (1992). Abandonment of Ofshore Rigs. Experience in the Gulf of Mexico. Petroleum Review. 46, 237-239; Auris Environmental, Report to UKOOA, An assessment of the environmental impacts of decommissioning options for oil and gas structures in the UK North Sea (1995); Corcoran, A. he abandonment of ofshore oil and gas ields, Vol 1: he regulatory framework. Oilield Publications Limited; Ashley Pittard, Abandoment Costs Vary Widely Worldwide Oil and Gas Journal (March 17 1997) 84-91; Ron Twatchman, Ofshore Platform Decommissioning perceptions change Oil and Gas Journal (December 8 1997) 38-41; Ash- Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 219 ley Pittard, Abandoment Costs Vary Widely Worldwide Oil and Gas Journal (March 17 1997) 84-91. 18. See J. B. Hinwood and L.R. Dennis, “Environmental issues in pipeline facility abandonment” he APPEA Journal 1998, Part 2 172-177. 19. See for example Australian procedures for abandoning a well as set out in APPEA Guidelines for Well Suspension and Decommissioning Ofshore (1999). 20. See Appendix III – Strategic Choices – Abandonment and Decommissioning. 21. Petter Osmundsen and Ragnar Tveterås Disposal of Petroleum Installations - Major Policy Issues January 2000, mimeo, 5 (Copy with author) 22. Source: U.S. Department of the Interior, Minerals Management Service, Decommissioning and Removal of Oil and Gas Facilities - Ofshore California: Recent Experiences and Future Deepwater Challenges Ventura, California September 23-25, 1997, 40. 23. Petter Osmundsen and Ragnar Tveterås Disposal of Petroleum Installations - Major Policy Issues January 2000, mimeo, 3 (Copy with author) 24. See B. C. Gerwick Jr, Construction of Marine and Ofshore Structures, Chapter 20 - Removal and Salvage, (2000); Corcoran, A. he abandonment of ofshore oil and gas ields, Vol1: he regulatory framework. Oilield Publications Limited, 321-394. 25. For example the Troll concrete gravity platform on the Norwegian continental shelf weighs some 700,000 tonnes –see Petter Osmundsen and Ragnar Tveterås Disposal of Petroleum Installations - Major Policy Issues January 2000, mimeo (Copy with author), 3. 26. Petter Osmundsen and Ragnar Tveterås Disposal of Petroleum Installations - Major Policy Issues January 2000, mimeo (Copy with author), 3. 27. Source: Michael Vincent McGinnis, Linda Fernandez, Caroline Pomeroy, he Politics, Economics, and Ecology of Decommissioning Ofshore Oil and Gas Structures OCS Study MMS 2001-006, 28-29. 28. Adapted from Corcoran, A. he abandonment of ofshore oil and gas ields, Vol1: he regulatory framework. Oilield Publications Limited, 321-360. 29. Department of Trade and Industry (UK), Guidance Notes for Industry Decommissioning of Ofshore Installations and Pipelines under the Petroleum Act 1998 (2003), 77. 30. Gerard, D and Wilson, E.J. (2009) Environmental bonds and the challenge of long-term carbon sequestration. Journal of Environmental Management 90 (2): 1097–1105; Boyd, J (2001) Financial responsibility for environmental obligations: are bonding and assurance rules fulilling their promise? Discussion paper. Washington, DC: Resources for the Future; Gerard, D (2000) he law and economics of reclamation bonds. Resources Policy 26: 189–197; Cornwell, L. (1997) Policy tools for environmentally sustainable development: environmental bonds and participatory modeling. College Park, Ph.D. Dissertation, University of Maryland at College Park; Cornwell, L., Costanza, R. An experimental analysis of the efectiveness of an environmental assurance bonding system on player behavior in a simulated irm. 11 Ecological Economics (1994) 213–226; Shogren et al. “Limits to Environmental Bonds”. 8 Ecological Economics (1993) 109–133; Webber, B. and Webber, D. (1985) Promoting economic incentives for environmental protection in the surface mining control and reclamation act of 1977: an analysis of the design and implementation of reclamation performance bonds. 25 Natural Resources (1977) 390–414 31. Doneivan et al Analysis of Environmental Bonding System for Oil and Gas Projects, 12 Natural Resources Research (2003) 273–290; Ferreira, D.F. and Suslick, S.B. (2001) Identifying potential impacts of bonding instruments on ofshore oil projects. Resources Policy 27, 43–52; Ferreiraa et al (2004) A decision model for inancial assurance instruments in the upstream petroleum sector, Energy Policy, vol. 32, pp. 1173–1184; Miller, G.C (2000) Use of environmental surety instruments in mining. International Council on Metals and the Environment Newsletter, vol. 8, issue 1; Miller, G.C. (1998) Use of inancial surety for environmental purposes, for International Council on Metals and the Environment, available online: www.icme.com/icme/ LimitedEditions/insurety.htm (04/11/2001) 32. Appendix IV provides an example of surety documentation in use in the United States. 33. he Surety Association of America (USA) suggests US$ 12.50 per US$ 1,000 per year as the premium (1.25%). 34. See further below for speciic discussion of the meaning of the term “best petroleum industry practice” in the Ghanaian environmental management context. 35. Numerous environmental impact assessments have been conducted in Ghana’s OOGP. See for example: 36. “pollution damage” is deined under PEPA 2016 to mean damage or loss caused by alteration of the physical, thermal, chemical, biological or radioactive properties of any part of the environment by discharging, emitting or depositing substances or wastes so as to afect any beneicial use adversely, cause a condition which is hazardous or potentially hazardous to public health, safety or welfare, or to animals, birds, wildlife, ish or aquatic life, or to plants or to cause a contravention of any condition, limitation or restriction which is subject to a licence under this Act. Again, it will be necessary to ensure that all deinitions of pollution damage across all relevant statutes and regulations are consistent. 37. he question is whether this a priori prohibition of production sharing arrangements is appropriate as there may be situations where a production sharing approach may be the better way to engage the services of a 220 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation sub-contractor with respect to risky areas. 38. See further on extended responsibility for environmental remediation and recovery of costs: Mfodwo, K., “Risk-based management of historically contaminated land in NSW: An analysis of the regime under the Contaminated Land Management Act 1997(NSW) 11 Australasian Journal of Natural Resources Law and Policy (2006) 43-107; Mfodwo, K., “Voluntary Agreements in Environmental Regulation: Part I” 3 Australasian Journal of Natural Resources Law and Policy (1996) pp. 271-338. (with Gaines, S.); Mfodwo, K., “Environmental Issues and Australian Financial Institutions: Applicable Laws and Practical Management Measures”. (Chapter 16 of Clark and Blay, Australian Law of Financial Institutions 2nd. ed. (Harcourt, Brace, Jovanovich Australia 1996); Mfodwo, K., “he Environmental Liability of Lender and Financial Institutions in New Zealand: An Analysis of current and proposed regimes” 2 Australasian Journal of Natural Resources Law and Policy (1995) pp. 1-49; Mfodwo, K., “Current Developments in Lender Liability for Environmental Harm” in Rowe and Seidler (eds) Toxic Waste Sites in Australia: Challenges for Law and Policy (Allen and Unwin, 1994); Mfodwo, K., “Lender Liability for Environmental Impairment and Remediation in New South Wales” 8 Environmental and Planning Law Journal (1991) pp. 108-132; Mfodwo, K., “Hazardous Waste Clean-up, Compensation and Remediation in Victoria: Recent Legislative and Policy Developments Afecting Companies and Financial Institutions” 8 Environmental and Planning Law Journal (1991) pp. 211-225. 39. he Maritime Zones (Delimitation) Law (PNDCL 159 of 1986). 40. In the PEPA interpretation section, “land” includes land beneath water, seabed and the subsoil. 41. PEPA Section 7 reads: (1) he decision to open an area for petroleum activities shall be made by the Minister; (2) he Minister shall, in collaboration with the Commission and other agencies, undertake an evaluation of the various interests in the relevant area before the area is opened for petroleum activities; (3) he Minister shall prepare a report on the evaluation which shall include a strategic assessment of: the impact of the petroleum activities on local communities: (a) the impact of petroleum activities on the environment, trade, agriculture, isheries, shipping, maritime and other industries and risk of pollution, and (b) the potential economic and social impact of the petroleum activities; (4) he Minister shall publish the evaluation report in the Gazette and in at least two state-owned daily newspapers and may publish the report in any other medium of public communication; (5) he report shall specify the area proposed to be opened for petroleum activities, and the nature and extent of the petroleum activities. 42. he relevant clause is Article 60(3) which reads as follows: “Any installations or structures which are abandoned or disused shall be removed to ensure safety of navigation, taking into account any generally accepted international standards established in this regard by the competent international organisation. Such removal shall also have due regard to ishing, the protection of the marine environment and the rights and duties of other States. Appropriate publicity shall be given to the depth, position and dimensions of any installations or structures not entirely removed.” 43. IMO Guidelines and Standards setting out the minimum global standards for the removal of ofshore installations 1989. 44. Source: Corcoran he Abandonment of Ofshore Oil and Gas Fields 1997, 321. Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 221 Appendix I Offshore Oil and Gas Production: - Near-Region Environmental Impacts Activity Environmental Impacts Exploration drill- 1. Major discharges in exploration phase: drilling luids and drill cuting tings and related activ- 2. Many such wells require decommissioning and may be abandoned ity 3. Issues of removal of platforms 4. disturbance of sealoor from bottom sampling D e v e l o p m e n t 1. Major discharges: drilling and relat• drilling luids ed activity • drill cuttings • well-treatment luids 2. Minor discharges • Sanitary and domestic waste • Production sands • Deck drainage • Cement residues • Cooling water • Gas and oil-processing wastes • Test water 3. Many such wells require decommissioning • May be abandoned • Issues of removal of platforms 4. disturbance of seabed loor from platform siting and pipeline laying etc. Production drill- 1.Major discharges: (quantity and/or toxicity) • drilling luids ing and related activity • drill cuttings • well-treatment luids • Produced water; • Ballast water • Storage displacement water 2. Minor discharges to water (quantity and/or toxicity) • Sanitary and domestic waste • Production sands • Deck drainage • Cement residues • Cooling water • Gas and oil-processing wastes • Test water • Slop oil 3. Many such wells require decommissioning and may be abandoned 4. Issues of removal of platforms 5. disturbance of seabed loor - platform siting and pipeline laying etc . 222 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Appendix II Types of Waste Discharges, Emissions and Debris from Offshore Oil and Gas Installations Wastes Generated by Ofshore Drilling Description Disposal/Transfer to Marine Zone and Waters Materials/luids with diverse essential uses in • May be recycled continuing circulation in drills and associ- • Where drilling occurs ated pipes in well: in a sensitive zone, Once formulated • piped down the well to maintain pressure drilling muds may be and in use drilland prevent blow-outs when oil is struck, transported to an ofing luids are re- • cool down and lubricate drill bits; shore disposal site or ferred to as drill- • carry drill cuttings back to the surface; treated onshore and ing muds • stabilise the walls of the well during drilling then sent to a inal Two types: disposal site • Oil-based • Oil-based muds are muds generally recycled • Water-based and reprocessed a muds number of times before inal disposal ofshore or onshore • Water-based muds are usually dumped into the sea at the end of well drilling cycle Drilling luids/ Drilling Muds • May be recovered and lubricate drilling activity recycled or disposed typically have a hydro-carbon base of ofshore or onshore May be added to drill as a “slug” or “pill” in special facility Introduces an oil element into water-based muds • May be dumped along with water-based • Increases the oil-content of oil-based muds muds at end of drilling cycle Drilling luid-lubricants • • • • Production Water water • Brought up during production of oil and • Production cannot be completegas ly collected and dis• Contains brine (very strong salt-water conposed of and lows centrations) oil and gas, formation water, into the sea injection water and any chemicals circulat• Can be actively maning downhole or added aged by oil/water sep• Proportion of water to petroleum will vary arators which reduce with particular characteristics of oil-ield the proportion of oil • Proportion of water generally increasreturned to marine es with age of oil ield and water may waters pre-dominate Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 223 Wastes Generated by Ofshore Drilling Description Disposal/Transfer to Marine Zone and Waters Produced Sands • Accumulated sands from drilling process • Transfer to onshore and slurry (ine semi-solid mixtures) disposal • Produced sands are coated with petroleum • Disposal ofshore in particles designated areas Other Debris • Rig stubs, steel pilings etc. Drilling • hrown into sea or accidentally lost during operations C o n c e n t r a t e d Oil/water separators are used to • Discharge from oil/ o i l - d i s c h a r g e s • clean oil from production water, produced water separators disfrom oil/water sands, completion luids, storage-displaceposed of by following separators ment water, ballast water, deck drainage routes: and bilge water; • Overboard • clean water from oil before consignment to • Piped to an ofshore pipelines outfall • Injected back into the oil and gas formation M i s c e l l a n e o u s • Desalination waste, cooling water, domesnon-oil waste watic liquid wastes, chemically treated water ters • Chemically treated water or “inhibited water”` typically contains a biocide, an amine And additives corrosion inhibitor and bisulphite salt • hese additives are designed to combat corrosion of steel structures by inhibiting oxidisation of these structures, growth of bacteria and corrosion generally • Additives are oten designed to have low acute toxicity and high degradability A t m o s p h e r i c • Aromatic hydrocarbons and other emissions associated with laring of gas from emissions – oil platforms and other chem• Exhausts from generating plant and maicals chinery • Combustible wastes burnt on board when not shipped to shore • Evaporation of oil at transfer and loading points and from barges or tankers • Major releases from blowouts, tank collisions, pipeline ruptures Commonly discharged untreated • Emitted to air • Key source of poly-aromatic hydrocarbons in some oil and gas production zones • Not regulated • High impacts in sensitive regions (e. may form a heavy oil residue on nearby ice or coral reefs with same chemical composition as pure oil pumped from source wells) 224 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Wastes Generated by Ofshore Drilling Pipeline discharges and ruptures Description Disposal/Transfer to Marine Zone and Waters • Consists of chemically treated water, clean- Discharge occurs during: ing agents (methanol), other lubricants and • Construction, testing facilitators of product movement in the and maintenance of pipeline (gels, other substance presentapipelines tions) • onshore export of oil and gas Discharge incidents infrequent but may be large scale in nature short duration (hours to days) Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 225 materials Asset Recovery Disposal of Reconstruct Reconstruct Maintain Future Use Future Use Abandon In Situ Relocate Mothball Facilities Decommission Partial Removal Total Removal Appendix III - Strategic Choices Decommissioning/Abandonment Source: Corcoran he Abandonment of Ofshore Oil and Gas Fields 1997, 321. 226 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Appendix IV – A US Surety Performance Bond covering plugging and abandonment of a well SURETY PERFORMANCE BOND No.___________________ FOR MISSISSIPPI STATE OIL AND GAS BOARD CLASS II OR OIL AND GAS WELLS FINANCIAL RESPONSIBILITY REQUIREMENT BOND COVERS THE PLUGGING OF CLASS II OR OIL AND GAS WELLS Date bond executed: _________________________________ Efective date: Principal: (Legal Name of owner or operator) (Business address of owner or operator) Type of organization: (Individual, joint venture, partnership, or corporation) State of incorporation: Surety(ies): (Name) (Business address) Operator, API identiication number, name of ield, county, well name & Permitted location description and plugging and abandonment amount(s) for each well guaranteed by this bond. (Indicate plugging and abandonment amounts for each well. Attach separate list as Schedule A if necessary). Well Information Plugging & Abandonment Amount Well Name Field or County_____________________API No.________________________________ Sec. Township Range Total penal sum of bond: $ : Surety’s bond number: Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 227 KNOW ALL PERSONS BY THESE PRESENT, that we, the Principal and Surety(ies) hereto are irmly bound to the Mississippi State Oil and Gas Board (hereinater called MSOGB), in the above penal sum for the payment of which we bind ourselves, our heirs, executors, administrators, successors, and assigns jointly and severally; provided that, where the Surety(ies) are corporations acting as co-sureties, we, the Sureties, bind ourselves in such sum “jointly and severally” only for the purpose of allowing a joint action or actions against any or all of us, and for all other purposes each Surety binds itself jointly and severally with the Principal, for the payment of such sum only as is set forth opposite the name of such Surety, but if no limit of liability is indicated, the limit of liability shall be the full amount of the penal sum. WHEREAS said Principal is required, under the Mississippi Oil and Gas Board Regulations, as amended, to have a permit or comply with provisions to operate under rule for each well identiied above, and WHEREAS said Principal is required to provide inancial assurance for plugging and abandonment as a condition of the permit or approval to operate under rule, and NOW THEREFORE, the conditions of this obligation are such that if the Principal shall faithfully perform plugging and abandonment, whenever required to do so, of each well for which this bond guarantees plugging and abandonment, in accordance with the plugging and abandonment plan and other requirements of the permit or provisions for operating under rule and other requirements of the permit or provisions for operating under rule as may be amended, pursuant to all applicable laws, statutes, rules and regulations, as such laws, statutes, rules, and regulations may be amended, Or, if the Principal shall provide alternate inancial assurance and obtain the MSOGB Supervisor’s written approval of such assurance, within 15 days ater the date of notice of cancellation is received by both the Principal and the MSOGB Supervisor from the Surety(ies), then this obligation shall be null and void. Otherwise it is to remain in full force and efect. he Surety(ies) shall become liable on this bond obligation only when the Principal has failed to fulill the conditions described above. Upon notiication by the MSOGB Supervisor that the Principal has been found in violation of the plugging and abandonment requirements of the MSOGB Rules and Regulation, for a well which this bond guarantees performances of plugging and abandonment, the Surety(ies) shall either perform plugging and abandonment in accordance with the plugging and abandonment plan and other permit requirements or provisions for operating under rule and other requirements or place the amount for plugging and abandonment into the MS Oil and Gas Board Emergency Plugging Fund as directed by the Supervisor. he Surety(ies) hereby waives(s) notiication of amendments to plugging and abandonment plans, permits, applicable laws, statutes, rules, and regulations and agrees that no such amendment shall in any way alleviate its (their) obligation on this bond. he liabilities of the Surety(ies) shall not be discharged by any payment or succession of payments hereunder, unless and until such payment or payments shall amount in the aggregate to the penal sum of the bond, but in no event shall the obligation of the Surety(ies) hereunder exceed the amount of said penal sum. 228 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation he Surety(ies) may cancel the bond by sending notice by certiied mail to the owner or operator and to the MSOGB Supervisor in which the well(s) is (are) located, provided, however, that cancellation shall not occur during the 120 days beginning on the date of receipt of the notice of cancellation by both the Principal and MSOGB Supervisor, as evidenced by the return receipts. he Principal may terminate this bond by sending written notice to the Surety(ies); provided, however, that no such notice shall become efective until the Surety(ies) receive(s) written authorization for termination of the bond by the MSOGB Supervisor in which the bonded well(s) is (are) located. (he following paragraph is an optional rider that may be included but is not required). Principal and Surety(ies) hereby agree to adjust the penal sum of the bond yearly so that it guarantees a new plugging and abandonment amount, provided that the penal sum does not increase by more than 20% in any one year, and no decrease in the penal sum takes place without the written permission of the MSOGB Supervisor. IN WITNESS WHEREOF, the Principal and Surety(ies) have executed this Performance Bond and have aixed their seal on the date set forth above. he persons whose signatures appear below hereby certify that they are authorized to execute this surety bond on behalf of the Principal and Surety(ies) on the date this bond was executed. PRINCIPAL: CORPORATE SURETY(IES): .............................................. (Name) ............................................... (Name) ............................................. (Address) ............................................... (Address) .............................................. (Signature(s)) ............................................... (Signature(s)) .............................................. (Name) ............................................... (Name) ............................................. (Title(s)) ............................................... (Title(s)) Corporate Seal Corporate Seal Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 229 ................................................. State of Incorporation ................................................ State of Incorporation $................................................ Bond Premium ................................................ Liability Limit (For every co-surety, provide signature(s), corporate seal, and other information in the same manner as for surety above). 230 Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation Regulating Environmental Matters – General Considerations and Regulation through Petroleum Legislation 231 7 7 REGULATING SAFETY & SECURITY MATTERS Regulating Safety & Security Matters 233 INTRODUCTION & OBJECTIVES OF CHAPTER Management of safety and security of the personnel and installations associated with an Ofshore Industrial Area is a complex matter and one of increasing importance. It has to be conducted from the point of view of speciic platforms or facilities as well as from the point of view of the entire ofshore area. he task is made more diicult by the fact that the safety threat in OOGP is increased by more and more intensive multiple use of coastal space as well as the search for oil and gas resources in deeper waters. A closely related but distinct issue is that of the security of ofshore installations from intentional attacks or threats to their security. Since the attacks on the United States of September 11 2001 the increased threat from politically motivated or terrorist attack has raised the proile of security considerations in OOGP to a very high level indeed. he Chapter addresses these two closely related themes: (1) safety in the traditional sense; (2) security from intentional attack, whilst maintaining the essential diferences between the two. SAFETY IN OOGP: AN OVERVIEW Safety issues are present at all stages of OOGP although they take diferent forms. hey are probably less crucial at the appraisal or drilling stage but are noticeably high in the ield delineation and development as well as decommissioning/abandonment phases. hey are also particularly prominent during deepwater operations due to the harshness and unpredictability of operational conditions. Major safety hazards associated with ofshore production operations include1: • • • • • • • • • • • • ire and explosion; blowouts; oil spills (small and large); ship collisions; iceberg impacts; dropped objects; helicopter crashes; structural failure; mooring failure; loss of stability; extreme weather; seismic event.s Stakeholders in Safety Stakeholders in the safety arena include: • • • • • • • Workers and trade unions Adjacent OOGP enterprises Other users of the zone, especially ishers and navigation interests he Public generally Regulators Associations representing other users of the zone Insurance interests he Safety Case framework requires that irms take account of this wide circle of stakeholders. 234 Regulating Safety & Security Matters SECURITY IN OOGP: AN OVERVIEW Threats to Energy Infrastructure hreats to the energy infrastructure are of many types as shown below. In response energy enterprises pro-actively plan or seek to manage most of these threats. Security threats to OOGP infrastructure have heightened since September 11 and attacks on a number of oil terminals and installations by organisations ailiated with Al Quaeda. Impacts of Threats or Crisis he impacts of threats or crisis are complicated and unpredicatable although to some degree they can be anticipated and modelled. Physical impacts Physical impacts encompass the set of direct consequences lowing from a major security incident. he potential efects of paramount importance include personal injury or loss of life. Other efects include the loss of property (including data) or damage to the environment. Economic impacts Economic impacts are a second-order efect. Physical impacts could result in repercussions to system operations, which in turn inlict a greater economic loss on the facility or company. On a larger scale, these efects could negatively impact the local, regional, national, or possibly global economy. Social impacts Another second-order efect, the consequence from the loss of national or public conidence in an organization is many times overlooked. Social impacts may possibly lead to heavily depressed public conidence or the rise of popular extremism. hreats to Energy Infrastructure2 Normal Accidents Abnormal Accidents Natural Accidents Economic Crisis Physical Crisis Personnel Criminal Crisis Crisis Information Crisis Reputation Crisis Natural Disasters Recessions Industrial accidents Strikes Product tampering het of proprietary information Rumour-mongering or slandering Earthquakes Stock market crashes Hostile takeovers Supply breakdowns Product failures Exodus of key personnel Kidnapping or hostage situations Tampering with compa- Logo tamperny records ing Workplace Acts of terviolence or rorism vandalism Cyberattacks Floods Fires Regulating Safety & Security Matters 235 REGULATING SAFETY ISSUES The Safety Case Approach A goal-based approach to regulation called the Safety Case approach has emerged as the principal way to address safety issues in OOGP. A Safety Case can be described as: “A documented body of evidence that provides a convincing and valid argument that a system is adequately safe for a given application in a given environment3” he Safety case regime essentially operates within a “co-regulatory structure”. One side of the equation is represented by the operator who prepares a detailed safety plan together with a management and technical system to implement the plan. On the other side is the regulator who assesses and, accepts or rejects the safety case based on its overall adequacy and “itness for purpose”. he regulator also audits the safety case periodically. he safety case approach is an example of goal-based safety regulation as opposed to prescriptive regulation in that it sets a state to be achieved without mandating a solution and then leaves the enterprise to plan to address the goal. A safety case has three aspects: • It provides a comprehensive working document against which the ‘operator’ and the ‘regulator’ can check that the accepted risk control measures and safety management systems have been properly put into place and continue to operate in the way in which they are intended. • he process of its design and its ongoing execution in accordance with what was originally proposed (or as amended) gives the regulator the conidence that the operator has the ability, commitment and resources to properly assess and efectively control risks to the health and safety of staf and the general public; • It is intended to be a ‘living’ document which describes the safety of an operation for the duration of the whole project—from initial concept design to termination of the operation and abandonment of any facilities and drives the continuous improvement of the risk management arrangements. he Safety Case concept was initially developed for the nuclear power industry in the United Kingdom in the 1960s. However, following the loss of the North Sea platform Piper Alpha in 1988, the technique was also adopted by the ofshore petroleum industry in Europe, Australasia and elsewhere. Goal-Based v Prescriptive Regulations Goal-based safety regulations are supposed to be more efective than prescriptive safety regulations for a variety of reasons: • Firstly, with prescriptive regulations, the service provider is only required to carry out the mandated actions to discharge his legal responsibilities. If these actions then prove to be insuicient to prevent a subsequent accident, it is the regulations and those that set them that are seen to be deicient. hus safety is viewed as the responsibility of the regulator and not the service provider whose responsibility, in law, it actually is.4 • Secondly, prescriptive regulations tend to be a distillation of past experience and, as such, can prove at best to be inappropriate and at worst to create unnecessary dangers in industries that are technically innovative. It is the innovator that is best placed to ensure the safety of their design, not the regulator. Clearly prescriptive safety regulations are unable to cope with a diversity of design solutions.5 • hirdly, prescriptive regulations encode the best engineering practice at the time that they 236 Regulating Safety & Security Matters were written and rapidly become deicient where best practice is changing e.g. with evolving technologies. In fact it is quite probable that prescriptive regulations eventually prevent the service provider from adopting current best practice. • Another driver for adopting goal-based regulation, from a legal viewpoint, is that overly-restrictive regulation may be viewed as a barrier to open markets. Various international agreements are intended to promote open markets and equivalent safety across nations. Whilst it is necessary to prescribe interoperability requirements and minimum levels of safety, prescription in other areas would defeat the aim of facilitating open markets and competition. • Finally, from a commercial viewpoint, prescriptive regulations could afect the cost and technical quality of available solutions provided by commercial suppliers. here are thus in theory clear beneits from adopting a goal-based approach as it gives greater freedom in developing technical solutions and accommodating diferent standards. Outline of the Safety Case Structure6 he safety case concept requires the operator to formally document how risk is to be managed in its operations and across its facilities, to demonstrate that the major hazards of the operation have been identiied and appropriate controls provided and that adequate provision has been made to ensure the safety of personnel in the event of an emergency. 7 here are three broad categories of information required in a safety case: • general information about the facility, its activities and operation and its interaction with other facilities or operations (the Facility Description); • the system by which safety is to be achieved and maintained in design, construction and operation of the facility, (the safety management system — SMS); • reasoned arguments and judgements about the nature, likelihood and impact of • potential major hazards which may impact the facility and the means to prevent realisation of these hazards, or minimise their consequences should they occur (the Formal Safety Assessment—FSA). he Facility Description8 he safety case should contain suicient information about the facility to verify that the design and operating philosophy is consistent with the Safety Management System (SMS) and the assumptions and outputs of the Formal Safety Assessment (FSA). he Safety Management System9 he SMS should ensure that all necessary linkages between system elements are identiied and, where appropriate, should draw on the principles of quality management. Formal Safety Assessment10 A FSA entails the identiication and evaluation of hazards over the life of the project from the initial feasibility study through the concept design stage, to construction and commissioning, then to operation, decommissioning and abandonment of the facility. It is a demonstration that, so far as is reasonably practicable, the risks to personnel have been minimised. It should: • provide reasoned arguments and judgements about the risk acceptance criteria including the rationale for their acceptance, references used and details of the risk acceptance studies Regulating Safety & Security Matters 237 conducted into potential major accident events that may occur during the life of the facility; • demonstrate that the operator has identiied the nature, likelihood and consequence of potential major accident events that may occur at the facility; • state the associated risks of fatality with respect to employees at the facility, and that the likelihood of these events and/or consequences have been minimised over the life of the facility. he FSA should also demonstrate that all reasonably practicable steps have been taken to ensure the safety of employees in the event of an emergency and during transit to a place of safety. It should demonstrate in particular that the integrity of the temporary refuge, escape and evacuation routes and embarkation points and escape crat is maintained in the case of a major accident event and that all reasonably practicable steps have been taken to ensure the safety of employees in the event of an emergency and during transit to a place of safety. As low as is reasonably practicable (ALARP)11 One of the objectives of a safety case is to demonstrate that risk from potential major accident events has been reduced to a level as low as reasonably practicable (ALARP). he term is used in recognition of the fact that, in practice, there has to be a limit set on the amount of efort and resources that can be applied to the continued reduction of risk. It is not possible to deine ALARP in purely objective and absolute terms. A working deinition when a risk is ALARP includes: • the use of best available technology capable of being installed, operated and maintained in the work environment by the people prepared to work in that environment; • the use of the best operable and maintainable management systems relevant to safety; • the maintenance of the equipment and management systems to a high standard; and • exposure of employees to a level of risk which is low. Additionally, the concept of reasonable practicability recognises that the cost and physical dificulty of avoiding the risk plays a part in the decision as to whether or not the risk levels associated with control measures adopted by the operator are acceptable. he decision willalso take into consideration prevailing standards and the knowledge of the hazards and risks by personnel at the facility12 . Preparation of Safety Cases13 he preparation of a safety case involves close interaction between the operator and the regulator (assessor), with regular meetings ensuring that the expectations of each party are reasonably in line as the development of the safety case proceeds. Australian regulators operate on the premise that issues should be resolve with the operator during the development or amendment of the safety case, and that there should be no surprises when the safety case is formally submitted. he safety case need not contain detailed procedures, calculations, drawings or plans, but should contain suicient information to allow the regulator to assess whether the systems and conclusions presented in the safety case are reasonable. General documentary evidence that supports the conclusions reached in the safety case should be referenced, and the regulator given access to the relevant documentation where necessary. he use of external specialist resources to assist in the preparation of the safety case is commonplace. he operator is however expected to be involved in all facets of the preparation of the safety case.14 238 Regulating Safety & Security Matters Assessment/Acceptance Of An Offshore Safety Case15 he regulator/assessor has a responsibility to assess the safety case material submitted by the operator. In the ofshore situation, the regulator is required by legislation to “accept” the safety case ater satisfying itself that the safety case objectives have been achieved. he responsibility for the quality of the safety case and its outcomes remains with the operator. In the ofshore situation, Safety Case guidelines have been developed to underpin the objective-based regime and to assist in the preparation, assessment and acceptance of a safety case. Whilst they are non-mandatory, they serve a number of functions. Firstly, to assist operators in the preparation of safety cases. Secondly, they serve as a guide to the government regulator responsible for assessing safety cases; thirdly, the content provides the basis of further system analysis during the subsequent follow up veriication - i.e., audits which take place before the issue of the necessary acceptance by the regulator16. he Safety Case Assessment Procedures provide a series of prompt question under each of these system headings which serve as a guide to a regulator in the analysis of the way in which the operator manages each system.17 Each of the questions seeks information or directs the reviewer to examine the way in which the systems employed by the operator are: • planned - what objectives exist, what procedures and standards are in place? • organised - who is responsible for actioning the procedures and to what level and expected outcome ?; • implemented - how are the procedures implemented, resourced and how are competencies of personnel ensured; • controlled - how the system is monitored, reviewed and audited and the results are used to update and improve the system’s ability to produce the desired outcome. Questions also prompt the reviewer to check for system linkages - that is, the way the operator ensures that where changes occur in work systems, other work systems register the change and adjust accordingly. Inspectors are engaged both in onsite appraisal of the delivery of improvements and assessing the complex technical arguments put forward for alternative approaches.18 Ongoing Monitoring of the Safety Case19 A principal feature of the safety case regime is the review and subsequent audit of the safety case against the performance standards stipulated in the safety case document. Audit and review will generally take two forms. he irst is associated with the acceptance of the initial safety case. Selected safety management systems will be the subject of an on-site review by the regulator to assess the adequacy of the arrangements stated by the operator prior to the formal Acceptance of the safety case. he second, conducted over the operational life of the facility, will be targeted audits of the operator’s SMS based on a combination of performance measures including:20 • the operator’s incident/accident experience and causal factors, complaints, legislative compliance reviews and the operator’s internal audit results; • the combined national experience of operators; • national and international trends and experience; and • general industry experience and developing standards. Regulating Safety & Security Matters 239 hese performance measures will also assist in highlighting the need for regulatory guidelines to support the objective-based regulations. Key aspects of inspection/auditing will be to monitor the efectiveness with which the commitments in the safety case are being implemented, monitoring the efectiveness of SMS and operator audits of them, and critically examining the eforts made by management to actively involve the workforce in the safety case process.21 he quality movement has been a signiicant worldwide trend over the last several decades. A quality system shits emphasis away from an individual task focus to a system-wide focus on quality. his is particularly relevant to inspectorial activity under a safety case regime. Prior to the advent of the safety case approach (and quality systems), the emphasis of inspections was placed on identifying areas of noncompliance with speciic regulatory requirements, such as checking that the correct numbers of ire extinguishers were present and that they were all ‘in test’. Under the new approach, the inspectorate emphasis is placed at a much higher level - with rigorous analysis of the overall safety management and hardware systems to uncover any potential weaknesses in the fundamental and comprehensive design of such systems. he inspectors task now, therefore, is rather to examine the design of the ire management system, and ensure that its structure includes mechanisms for ensuring and checking the adequacy and serviceability of the ire ighting infrastructure.22 THE APPLICATION OF THE SAFETY ZONE CONCEPT TO VARIETIES OF OOGP INFRASTRUCTURE23 Safety Zones and Surface Structures A safety zone or protection area is used to protect surface structures such as oil platforms, drilling rigs, storage tankers and their loading buoys. It is designed principally to prevent accidental collisions between ships and ofshore installations. It is also intended to keep ishing vessels away from ofshore installations. he extent is typically 500 metres measured from the perimeter of each structure. It should be noted that the anchors for loating production storage and oloading (FPSO) vessels oten extend well beyond their 500 metre safety zones. Figure 1 - Images of an FPSO and a Fixed Platform FPSO Anasuria 240 Regulating Safety & Security Matters North Cormorant Platform Figure 2 - FPSO symbol on Admiralty charts (with additional circle indicating extending chains and anchors) he symbol in Figure 2 is used to show a 500 metre safety zone for a loating production storage and ofloading facility (FPSO) on British admiralty charts. When attached to an FPSO (above) there may be anchors extending well beyond the 500m safety zone and the symbol will show an extra circle around the original. Safety Zones around individual and multiple sub-surface structures Subsea structures form a major part of ofshore oil and gas infrastructure. hese structures come in a variety of shapes and sizes which include valves on pipelines, tee pieces, production manifolds, templates, active and suspended wells, etc. heir common feature is that they are not visible from the surface. However if they present a hazard to other uses, they do need to generate a safety zone or be protected by one. As a rule of thumb, most subsea structures have a 500m safety zone, which is measured from the center of the location of the structure or the installation. Figure 3 provides an example of this type of subsea structure he production item is a manifold which is additionally covered by a protection structure. Such a structure generates a safety zone from the middle of the installation and is shown on an admiralty chart as follows Regulating Safety & Security Matters 241 Figure 3 Subsea structure: Manifold with protection structure Figure 4 - Representation on an admiralty chart of a sub-sea structure his is how a subsea template is shown on an admiralty chart. he igure (78) indicates the charted depth above the installation Figure 5 Safety Zones and Protection Areas generated by a complex of subsea equipment As shown by Figure 5 there may also be several pieces of equipment within the safety zone. he image below shows a 500 metre safety zone as the outer circle. he subsea equipment within this zone extends to almost 200 metres from the centre of the zone. here are also pipelines which also generate their protection area running alongside with the pipeline in the middle 242 Regulating Safety & Security Matters THE INTERNATIONAL LAW REGIME GOVERNING TE SAFETY OF OFFSHORE PETROLEUM INSTALLATIONS UNCLOS Provisions Various provisions of the United Nations Convention on the Law of the Sea 1982 are relevant to the safety of OOGP installations as show in more detail below. Safety zones in the territorial sea he LOSC is silent about safety zones around ofshore facilities located in the territorial sea. Arguably, the coastal state, by virtue of its sovereignty and Article 21(1)(b), may adopt measures for the protection of ofshore facilities in the territorial sea such as the establishment of ‘safety zones’, ‘security zones’ or ‘exclusion zones’ around ofshore facilities, and take in those zones whatever measures are necessary for the protection of facilities. he breadth of such zones does not have to be limited to 500m, which is the limit for the safety zones in the exclusive economic zone and on the continental shelf, so a coastal state can establish security zones of any breadth it deems necessary, as long as such zones do not hamper the innocent passage of foreign ships through the territorial sea and safety of navigation is preserved. he LOSC does not expressly mention the need to seek the IMO endorsement for safety zones larger than 500m around ofshore facilities in the territorial sea, which could be understood that such an endorsement is not required. he size of a security zone and nature of the protection measures in such a zone may depend on the type and nature of the ofshore facility in question. For example, strategically important ofshore oil and gas facilities, such as major ofshore export terminals, may be subjected to security arrangements of a high order and may warrant larger safety, security, or exclusion zones around them. To protect ofshore facilities in the territorial sea, coastal states can use the right to designate and prescribe sea lanes and traic separation schemes for the regulation of passage (for example, in areas of high concentration of ofshore facilities) and require foreign ships exercising the right of innocent passage through its territorial sea to use such sea lanes and traic separation schemes. he coastal state also has a right to suspend temporarily the innocent passage of foreign ships in speciied areas of its territorial sea if such suspension is essential for the protection of its security, (and the protection of ofshore oil and gas facilities can arguably be essential to the security of the coastal state) or it can take the ‘necessary steps’ in its territorial sea to prevent passage of foreign ships through the territorial sea which is found to be not innocent passage,20 for example, where such passage is connected to or involves any act aimed at interfering with ofshore facilities. he coastal state can also rely on LOSC Article 27 to exercise criminal jurisdiction on board the foreign ship involved in deliberate interference with an ofshore facility, which causes a security incident or attack on an ofshore facility in the territorial sea, and arrest persons responsible because the consequences of such unlawful acts extend to the coastal state and/or disturb the peace of the country or the good order of the territorial sea. Safety zones in the Exclusive Economic Zone he UNCLOS rules are set out at Articles 56, 60 and 80 of the Convetion and invest the Coastal State with extensive sovereign rights regarding (1) the production and use of ofshore oil and gas resources; (2) jurisdiction and control over the establishment and use of those artiicial islands, installations and structures,24 which may be used to explore for and produce petroleum resources. Article 60 within the EEZ section of the Convention sets out the detailed regime of control over ofshore installations with Article 80 applying the same rules (mutatis mutandis) Regulating Safety & Security Matters 243 to ofshore installations on the continental shelf, thereby covering the situation of those States which have not declared an EEZ and also applying these rules to situations in which the continental shelf extends beyond the EEZ. Article 60 provides that in the exclusive economic zone, the Coastal State has exclusive rights over all aspects of the construction and use of: (a) artiicial islands; (b) installations and structures for the purposes provided for in article 56 and other economic purposes; (c) installations and structures which may interfere with the exercise of the rights of the coastal State in the zone. Article 60(2) goes further to explicitly provide exclusive jurisdiction over such artiicial islands, installations and structures, including jurisdiction with regard to customs, iscal, health, safety and immigration laws and regulations. Article 60(4) allows the Coastal State where necessary, to establish reasonable safety zones around such artiicial islands, installations and structures in which it may take appropriate measures to ensure the safety both of navigation and of the artiicial islands, installations and structures. Article 60(5) states that the breadth of such safety zones shall be determined by the coastal State, taking into account applicable international standards. Such zones shall be designed to ensure that they are reasonably related to the nature and function of the artiicial islands, installations or structures, and shall not exceed a distance of 500 metres around them, measured from each point of their outer edge, except as authorized by generally accepted international standards or as recommended by the competent international organization. Due notice must be given of the extent of safety zones. Finally, Article 60(6) states that all ships must respect these safety zones and must comply with generally accepted international standards regarding navigation in the vicinity of artiicial islands, installations, structures and safety zones. MULTILATERAL TREATY INSTRUMENTS COVERING UNLAWFUL ACTS OF VIOLENCE AGAINST OFFSHORE PETROLEUM INSTALLATIONS AND VESSELS Other relevant international law instruments cover unlawful acts of violence against ofshore facilities against this background of the exclusive jurisdiction of the Coastal State over ofshore oil facilities. hey are:25 • the Rome Convention for the Suppression of Unlawful Acts against the Safety of Maritime Navigation 1988 (the SUA Convention)26 • the SUA Convention Protocol for the Suppression of Unlawful Acts against the Safety of Fixed Platforms located on the Continental Shelf 1988 – (the Fixed Platforms Protocol).27 Ghanaian legislation currently only gives partial efect to these instruments (i.e. provides coverage for both mobile and ofshore facilities) as Ghana is not a party to these treaties. The SUA Convention he SUA Convention at Article 1 deines a “ship” as “a vessel of any type whatsoever not permanently attached to the sea-bed, including dynamically supported crat, submersibles, or any other loating crat”. It then lists a number of acts which, if done, attempted, abetted, or threatened unlawfully and intentionally, constitute an ofence. Such acts include: • seizing a ship by force;28 244 Regulating Safety & Security Matters • • • • • • violence that is likely to endanger navigation;29 destroying or damaging a ship or its cargo;30 placing a destructive device on a ship;31 destroying or damaging navigational facilities;32 passing false information that endangers safe navigation;33 injuring or killing any person in connection with the commission of any of these other offences.34 Under Article 6 of the Convention, States which become party to it are required to pass laws which will ensure that they can establish jurisdiction over such ofences when they are: (1) committed against or on board a ship lying the lag of the relevant State; (2) committed in the territory of that state; (3) committed by a national of that state. Articles 7, 8, 10, and 11 of the Convention also set out procedures dealing with arrest, extradition and prosecution of ofenders or alleged ofenders. Finally, the Convention at Articles 12, 13 and 14 also requires States parties to establish a framework for cooperation, assistance and information exchange with respect to: (1) the prevention of any of the described ofences; (2) criminal proceedings arising from such ofences. The Protocol for the Suppression of Unlawful Acts Against the Safety of Fixed Platforms Located on the Continental Shelf 1988 35 (Fixed Platforms Protocol) Under the Fixed Platforms Protocol a “ixed platform” is deined as “an artiicial island, installation or structure permanently attached to the sea-bed for the purpose of exploration or exploitation of resources or for other economic purposes.” Relecting the close relationship with the SUA Convention, Article 1 of the Fixed Platforms Protocol makes provisions of the SUA Convention (speciically Articles 5 and 7 and also Articles 10 to 16) directly applicable to the speciic ofences relating to ixed platforms set out at Article 2 of the Protocol. hese ofences at Article 2(2) are: • seizing or exercising control over a ixed platform by force or threat of force or any other form of intimidation;36 • performing an act of violence against a person on board a ixed platform if that act is likely to endanger its safety;37 • destroying a ixed platform or causing damage to it which is likely to endanger its safety;38 • placing or causing to be placed on a ixed platform, by any means whatsoever, a device or substance which is likely to destroy that ixed platform or likely to endanger its safety;39 • injuring or killing any person in connection with the commission or the attempted commission of any of the ofences set forth in (a) to (d):40 All these acts are an ofence if committed, attempted, abetted or threatened unlawfully and intentionally. he Fixed Platforms Protocol ofences do however difer from those set out in the SUA Convention in that no reference is made to acts which impact on cargo or navigational safety. his is potentially an important omission given the multiple uses to which ixed ofshore platforms may be put. Regulating Safety & Security Matters 245 THE GHANA OFFSHORE SAFETY REGIME – PEPA 2016 Provisions under PEPA 2016 Safety Zones Section 65 of PEPA 2016 provides that every petroleum facility and well shall be surrounded by a safety zone, unless otherwise determined by the Commission, and the Commission shall, in consultation with relevant authori¬ties, determine the delimitation of the safety zone. Any unauthorised vessels, vehicles, ishing gear or other objects or crats shall not enter a safety zone established under this section. he Commission may permit lawful activities to take place in the zone or in parts of the zone if the activities can be conducted without threatening safety or interfering with the exercise of the petroleum activities and determine and establish the boundaries of the safety zone as prescribed before the placement of petroleum facilities. Finally, in the event of accidents and emergencies, the Commission may establish or extend a safety zone including in respect of abandoned wells, abandoned or decommissioned facilities or parts of those facilities. Safety Requirements and Standards Section 61 of PEPA 2016 sets out the safety requirements and standard that will govern petroleum activities. It states that petroleum activities are to be conducted in a manner that ensures that a high level of safety is achieved, maintained and further developed in accordance with technological developments and latest interna¬tional practice and applicable enactments relating to health, safety and labour. Additionally, a plan and related documents for implementation of safety measures of petroleum activities shall be submitted to the Commission before the commencement of the relevant petroleum activities which shall be updated when required. Section 62 of PEPA 2016 further states that a licensee, contractor, sub-contractor and the Corporation shall identify the hazards and evaluate the risks associated with any work performed in the course of petroleum activities which constitute a hazard to the health and safety of persons employed for purposes of that work, and of persons otherwise present at or in the vicinity of the facility, and the steps that need to be taken to comply with the provisions of this Act and Regulations. his is in order to ensure the safety of relevant persons and prevent their exposure to hazards, or where prevention is not reasonably practicable, minimize their exposure; and ensure that any relevant persons are duly informed of the safety precautions. Emergency Preparadness and Suspension of Activities when required by an Emergency In respect of emergency preparedness, Section 63 of PEPA 2016 provides that a person conducting petroleum activities shall at all times (a) maintain eicient emergency preparedness to prevent, control, handle and minimize accidents and emergencies which may lead to loss of life or personal injury, pollution or major damage to property including ire, oil spills, gas leakages, blow-outs, accidents or other emergency situations; and (b) ensure that necessary measures are taken to prevent or reduce harmful efects, including the measures required to return the environment to the condition it was before the accident occurred. Emergency preparedness against deliberate attacks is provided for under Section 64 of the PEPA Act. It provides that a licensee, contractor, sub-contractor or the Corporation shall implement and maintain preventive security measures, including control of personnel and goods, to protect their petroleum facilities and wells from deliberate attacks and shall have contingency plans to deal with those attacks. Suspension of petroleum activities is dealt with by Section 66 of PEPA 2016. Notably, where an accident or emergency may lead to or has resulted in loss of life or personal injury, pollution or 246 Regulating Safety & Security Matters major damage to property, the licensee, contractor, sub-contractor or the Corporation shall, (a) to the extent necessary, suspend the petroleum activities for as long as required by the petroleum operating standards under section 50; and (b) immediately but not later than forty eight hours, inform the Minister and the Commission of the suspension. In the event of emergencies or accidents under subsection (1), the Minister may, acting on the advice of the Commission, (a) direct that petroleum activities be suspended to the extent necessary if required in the public or national interest; or (b) impose particular conditions to allow continuation of the activities. Assumption of responsibility for Safety Measures by the Petroleum Commission PEPA 2016, Section 67 provides for measures to ensure safety. To this end, the provision states that where a licensee, contractor, sub-contractor or the Corporation fails to conduct the activities in a safe manner in accordance with applicable enactments and best international practice, the Commission may take necessary measures to ensure safety and may recover the costs and expenses of doing so from the licensee, contractor, sub-contractor or the Corporation. Additionally, the Commission may take measures under subsection (1) only ater giving the contractor, sub-contractor, licensee or the Corporation reasonable notice. THE GHANA OFFSHORE SAFETY REGIME – THE GHANA SHIPPING (PROTECTION OF OFFSHORE OPERATIONS AND ASSETS) REGULATIONS, 2012 Establishment and protection of safety zones Section 1 of the Protection of Ofshore Operations and Assets Regulations authorises the Minister by notice published in the Gazette to establish safety zones around an ofshore installation to protect the installation during and ater its installation on on the seabed within Ghana’s maritime jurisdiction: Protection of Ofshore Operations and Assets Regulations, s. 1(1)(a). he Minister may also prescribe such measures as he/she considers necessary for the protection of such ofshore installation or device as has been emplaced on the seabed and which lies within the safety zone that has been established: Protection of Ofshore Operations and Assets Regulations, s. 1 (1)(b). He may also regulate or prohibit the entry of a ship or any speciied class of ships, vessels or persons into the safety zone: Protection of Ofshore Operations and Assets Regulations, s. 1 (1)(c). Relecting the fact that FPSOs are fabricated elsewhere and are then towed to Ghana before installation in Ghana’s EEZ or territorial sea, the Regulations state that a safety zone may be established in anticipation of the arrival of an installation on station, so as to commence at the time of its arrival on station: Protection of Ofshore Operations and Assets Regulations, s. 1 (2). Geo-location of permanent and temporary installations by reference to co-ordinates of latitude and longitude he Regulations require the use of co-ordinates of latitude and longitude to establish the precise position (to the extent possible) of both the installation itself as well as the safety zone generated by it. hese co-ordinates must be published in the Gazette with respect to installations that are permanently ixed to the sea loor as well as those that are temporary: Protection of Ofshore Operations and Assets Regulations, s. 1(3) and (4). Regulating Safety & Security Matters 247 Determining where the safety zone starts and ends In accordance with the international law requirements, the area of the safety zone around a permanent installation located in the EEZ consists of an area extending to a distance of ive hundred metres measured from each point of the outer edge of such installation: Protection of Ofshore Operations and Assets Regulations, s. 1(3). here is no mention of the distinction between the territorial sea and the EEZ. As we have seen however, in principle safety zones in the territorial sea can be very extensive as the territorial sea is a zone in which the Coastal State enjoys full rights of sovereignty as distinct from sovereign rights. Deining the safety zone area around a loating ofshore installation is much more complex as discussed previously. Under s. 1(4) of the Protection of Ofshore Operations and Assets Regulations, the area of a safety zone around a loating ofshore installation is also determined by co-ordinates of longitude and latitude. hese must encompass: (a) the loating installation rotation zone; and (b) the annular, ring-shaped area next to the loating installation rotation zone: (i) bounded on its inner edge by the outer edge of the loating installation rotation zone; and; (ii) bounded on its outer edge by a line ive hundred metres from the outer edge of the loating installation rotation zone: Protection of Ofshore Operations and Assets Regulations, s. 1(4). Notification of Location to the Seafaring Community and the Public at Large Notiication of the location of safety zones is to be provided to the seafaring community and the public by the Director-General of the Ghana Maritime Authority through various media. For seafarers this is to be via oicial nautical charts, Notices to Mariners as well as navigational warnings. he public is to be advised through publication of information in at least two stateowned national daily newspapers: Protection of Ofshore Operations and Assets Regulations, s. 1(5). his implements s 235 of the Ghana Shipping Act (2003) Act (Act 645). Prohibition of Entry into Proclaimed Safety Zone Areas Entry into a proclaimed and notiied safety zone by any ship, vessel or person is strictly prohibited by s. 2 of the Protection of Ofshore Operations and Assets Regulations unless that entity or person has an entry consent in writing issued by the Director-General of the GMA. Entry without such a consent in writing is however permitted where the entity or person is engaged in constructing, repairing or servicing (a) a loating or ixed installation; (b) a submarine pipeline connected or to be connected to the loating installation; (c) facilities associated with the loating installation or the pipeline: Protection of Ofshore Operations and Assets Regulations, s. 2(a). Similarly, entry without a consent in writing is allowed where entry is required by a tanker authorized by the operator of the installation to enter the zone to load crude oil or other petroleum products: Protection of Ofshore Operations and Assets Regulations, s. 2(b). Establishment of exclusion zones An exclusion zone is diferent from a safety zone in that an exclusion zone by deinition is larger than the accepted area of a safety zone and is temporary in character. It is intended to help the Coastal State to manage emergency events and to exclude other users from the area, so that the emergency event can be properly managed. To give efect to these requirements, the Minister (under this Act, the Minister for Transport) may, by notice published in the Gazette, establish a temporary exclusion zone in an area within Ghana’s maritime jurisdiction, basing such establishment on the following rationales: (a) safety, (b) danger or imminent danger to: the state, a person, a vessel, an installation, a structure, a device, or an item of equipment; (c) protection 248 Regulating Safety & Security Matters of the environment; (d) to mitigate the efects of an oil spill: Protection of Ofshore Operations and Assets Regulations, s. 3. he Regulations do not set any a priori limits on the size of such an exclusion zone or the length of time it is to be in place as these matters will be context and situation dependent and cannot be determined in advance. his power is necessarily to be read with the emergency powers provided to the Minister in charge of PEPA 2016, the Minister for Energy, under s. 78 of PEPA 2016. Incorporation of IMO Measures into Ghana law and publicity for such measues through the Gazette he International Maritime Organisation periodically updates its rules and measures. he Director-General may therefore publish the details of a protection mechanism established by the International Maritime Organisation where such mechanism has efect in an area within Ghana’s maritime jurisdiction: Protection of Ofshore Operations and Assets Regulations, s. 4 (1). he nature and location of the protection mechanism and the restrictions imposed by that protection mechanism both need to be set out in the Gazette: Protection of Ofshore Operations and Assets Regulations, s. 4 (2). Protection areas around subsea pipelines41 By their very nature, some subsea pipelines cannot have safety zones around them. he alternative is to proclaim a protection area that more precisely its their physical characteristics and the way they are located on the seabed. he Minister may, therefore by notice published in the Gazette, establish a protection area around a subsea pipeline to protect any pipeline (whether or not permanently attached to an ofshore installation) where such pipeline is not protected by a safety zone established under regulation 1 (Protection of Ofshore Operations and Assets Regulations, s. 5(1)). he subsea pipeline protection area established under5 (1) is also to be deined in the Gazette and cannot extend more than one hundred metres on either side of the centre line of the speciied pipeline. his pipeline must itself also have its co-ordinates of latitude and longitude speciied in the Gazette (Protection of Ofshore Operations and Assets Regulations, s. 5(2)) Protection areas around subsea cables he Minister may, by notice published in the Gazette, establish a protection area around a subsea cable or any length of the cable to protect any subsea cable: Protection of Ofshore Operations and Assets Regulations, s. 6(1). he protection area established under subregulation (1) shall be deined in the Gazette and shall extend not more than ity metres on either side of the centre line of the speciied cable which has the co-ordinates of latitude and longitude speciied in the Gazette (Protection of Ofshore Operations and Assets Regulations, s. 6(2)) Prohibition of certain activities within protection areas he main activities prohibited are (1) ishing operations conducted from a ship whilst it is in the protection area; (2) anchoring in the protection area. However where such anchoring is necessary for the purpose of saving life or a ship it is permitted: Protection of Ofshore Operations and Assets Regulations, s. 7. Regulating Safety & Security Matters 249 Requirements for safety permits A person who intends to (a) operate a vessel, (b) site an installation, (c) site a storage facility, or (d) lay a pipeline, cable, an equipment or any other structure or device, on the seabed in an area within Ghana’s maritime jurisdiction shall obtain a permit from the Ghana Maritime Authority: Protection of Ofshore Operations and Assets Regulations, s. 10 (1). he Director-General shall issue a safety permit in the form speciied in the Second Schedule to a person who complies with the necessary requirements: Protection of Ofshore Operations and Assets Regulations, s. 10 (2). A safety permit is valid for a period of one year from the date of issue and may be renewed, subject to an annual inspection by the Authority: Protection of Ofshore Operations and Assets Regulations, s. 10 (3). Where a person does not comply with the necessary requirements, the Authority shall give notice to the person to take remedial steps speciied in that notice within the time speciied in the notice: Protection of Ofshore Operations and Assets Regulations, s. 10 (4). Where a person does not take the remedial steps within the time speciied in the notice, the Authority shall in writing revoke the permit of that person: Protection of Ofshore Operations and Assets Regulations, s. 10 (5). A person whose safety permit is revoked by the Authority may re-apply to the Authority for the safety permit ater taking the remedial steps: Protection of Ofshore Operations and Assets Regulations, s. 10 (6). Regulation of mobile offshore drilling units Both the territorial sea and the EEZ are the subject of exploration and production activity. Industry practice of Africa is to use mobile units rather than ixed intallations for production purposes, whilst exploration is always undertaken by mobile drilling units. Accordingly the Regulations provide that a person shall not locate, move or relocate a mobile ofshore drilling unit from or to a location in Ghana’s maritime jurisdiction without prior written notiication to the Authority: Protection of Ofshore Operations and Assets Regulations, s. 8 (2). A person shall also not operate or locate a mobile ofshore drilling unit in Ghana’s maritime jurisdiction unless that person: (a) obtains a mobile ofshore drilling unit safety operating permit from the Ghana Maritime Authority, and (b) complies with the design, construction and equipment requirements of the Code for the Construction and Equipment of Mobile Ofshore Drilling Units, 1979, (IMO Resolution A.414 (XI) as amended by MSC/Circ.561; (the 1979 Mobile Ofshore Drilling Unit Code) and has in force a Mobile Ofshore Drilling Unit Certiicate (1979); or the Code for the Construction and Equipment of Mobile Ofshore Drilling Units, 1989, (IMO Resolution A.649 (16) as amended by MSC/Cir.561 and Resolution MSC.38 (63); (the 1989 Mobile Ofshore Drilling Unit Code) and has in force a Mobile Ofshore Drilling Unit Certiicate (1989): Protection of Ofshore Operations and Assets Regulations, s. 8 (1). Requirements for mobile offshore drilling unit safety operating permit he GMA Director-General issues safety operating permits for mobile drilling units as they are deined to be vessels. A person who seeks to operate a mobile ofshore drilling unit must apply in writing (with the relevant documents) to the Director-General where they seek a safety operating permit: Protection of Ofshore Operations and Assets Regulations, s. 9 (1). he Director-General is required to issue a mobile ofshore drilling unit safety operating permit to a person who complies with the necessary requirements: Protection of Ofshore Operations and Assets Regulations, s. 9 (2). he operating permit is valid for a year from the date of issue and may be renewed, subject to an annual inspection by the Authority: Protection of Ofshore Operations and Assets Regulations, s. 9 (3). Where a person does not comply with the necessary requirements, the Authority shall give notice to the person to take remedial steps speciied 250 Regulating Safety & Security Matters in that notice within the time speciied in that notice: Protection of Ofshore Operations and Assets Regulations, s. 9 (4). Where a person does not take the remedial steps within the time speciied in the notice, the Authority shall in writing revoke the permit of that person: Protection of Ofshore Operations and Assets Regulations, s. 9 (5). A person whose mobile ofshore drilling unit safety operating permit is revoked by the Authority may re-apply to the Authority for the mobile ofshore drilling unit safety operating permit ater taking the required remedial steps: Protection of Ofshore Operations and Assets Regulations, s. 9 (6). Offences and penalties he owner of a ship or a vessel or a person who is in charge of a ship or a vessel or a person that (a) enters or remains in a safety zone in contravention of regulation 2, or (b) carries out an operation prohibited in an area deined as a protection area in accordance with regulation 5 or 6 commits an ofence and is liable on summary conviction (c) in the case of an individual, to a ine of not less than ity penalty units and not more than seven thousand ive hundred penalty units or a term of imprisonment of not more than iteen years or to both the ine and the imprisonment, and (d) in the case of a body corporate, to a ine of not less than ive hundred penalty units and not more than ten thousand penalty units: Protection of Ofshore Operations and Assets Regulations, s. 11 (1). A person who enters or remains in a temporary exclusion zone commits an ofence and is liable on summary conviction to a ine of not more than ten thousand penalty units or to a term of imprisonment of not more than ive years or to both the ine and the imprisonment: Protection of Ofshore Operations and Assets Regulations, s. 11 (2). A person who does not comply with the restrictions imposed in a protection mechanism established under regulation 4 commits an ofence and is liable on summary conviction to a ine of not more than ive hundred penalty units: Protection of Ofshore Operations and Assets Regulations, s. 11 (3). A person who operates a mobile ofshore drilling unit within Ghana’s maritime jurisdiction and fails to (a) register the mobile ofshore drilling unit with the Ghana Maritime Authority, or (b) obtain a mobile ofshore drilling unit safety operating permit, commits an ofence and is liable on summary conviction to a ine of not more than ive thousand penalty units or to a term of imprisonment of not more than ive years or to both the ine and the imprisonment: Protection of Ofshore Operations and Assets Regulations, s. 11 (4). A person who (a) operates a vessel, (b) sites an installation, (c) sites a storage facility, or (d) lays a pipe, cable, equipment or any other structure or device, on the seabed or in an area within Ghana’s maritime jurisdiction without registering with the Ghana Maritime Authority or obtaining a safety permit from the Ghana Maritime Authority commits an ofence and is liable on summary conviction to a ine of not more than ive thousand penalty units or to a term of imprisonment of not more than ive years or both the ine and the imprisonment: Protection of Ofshore Operations and Assets Regulations, s. 11 (5). Defences It is a defence to a charge of an ofence cited in regulation 11, if it is established that the ofence occurred because (a) of factors beyond the control of the person charged, (b) it was necessary to secure the safety of, or appeared to be the only way of averting a threat to human life; or (c) it was necessary to secure, or appeared to be the only way of averting a threat to the safety of a ship at sea or of an ofshore installation: Protection of Ofshore Operations and Assets Regulations, s. 12. Regulating Safety & Security Matters 251 IMPLEMENTING THE SAFETY CASE APPROACH IN GHANA - THE OFFSHORE PETROLEUM (HEALTH AND SAFETY) BILL 2010 A Bill which has not yet been passed into law, he Ofshore Petroleum (Health and Safety) Bill 2010 seeks to implement the Safety Case approach in Ghana. According to the preamble, the Act seeks to provide for the health and safety of persons in the operation of ofshore installations for petroleum exploration and for related matters. he Bill does not deine the term “ofshore”, nonetheless “ofshore installation” is deined in the interpretation section to include: (a) “any artiicial structure (including a loating structure that is not a ship) used or intended to be used in or on, or anchored or attached to the seabed for the purpose of the exploration for, or the exploitation or associated processing of, petroleum and (b) other works within 500m of any part of the structure or vessel used in conjunction with the petroleum operation: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 32. Subject to an inspection by an inspection body, a Safety Case is to be prepared for every installation for the design and construction, operation and abandonment of the installation: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 15 (1)(a), (b), and (c). he Bill provides that an inspection body (not however named in the Bill) shall examine installations and equipment which are ixed or associated with the installations and issue certiicates of itness in relation to the safety of the structure of the installation and other equipment which is necessary for the safe operation of the installation: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 17. Even though no speciic inspection body is named in the Bill, only the Minister42 has the power to recognise a person or organisation as an inspection body if he is satisied that the person or organisation is accredited through a recognised industry standard: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 18 (c). In addition, the Minister has to be satisied that such organisation or person operates with a requisite quality assurance programme and has appropriate experience relating to certiication work: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 18(a) and (b). Alternatively, an employer can dispense with the need for a Certiicate of Fitness (COF) if he can provide, to the satisfaction of the Minister, that a Veriication Scheme (VS) for the installation has been suiciently veriied by an independent and objective veriier. here is a marked diference between the Veriication Scheme process and a Certiicate of Fitness. Whereas the Minister oversees the qualiications of an inspection body in relation to a Certiicate of Fitness, it is the duty of an employer who operates a veriication scheme to appoint competent and independent persons to carry out the veriication work and to implement, maintain, review and revise the Veriication Scheme and to audit safety critical elements. Employers have a duty to prepare reports of various audits on their installations and to make a record of the action(s) taken as a result of the indings of the audits: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 18(a) and (b). A key feature of the Bill is the provision for the appointment of managers by employers to manage petroleum operations and to “supervise the health and safety aspects of the petroleum operation personally on every day on which an employee is at work.” Ofshore Petroleum (Health and Safety) Bill 2010, Clause 1. he Bill also has provisions for emergency procedures under which a principal or any other person in charge of work is expected to develop procedures for dealing with emergencies that may arise. Ofshore Petroleum (Health and Safety) Bill 2010, Clause 3(1). 252 Regulating Safety & Security Matters he Bill goes further to indicate that the procedures shall identify the person or persons responsible for instructing petroleum workers in the emergency procedures which must be sent to the Minister for approval before the beginning of petroleum operations and be reviewed periodically: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 3(2) (a), (b), and (c). In pre-emption of major accidents, the employer also has a duty to immediately notify the Minister in writing of a failure of any primary pressure containment system of a well, including the steps being taken to remedy the situation: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 13(a) and (b). here are also provisions for managing hazards on installations, special provisions relating to Mobile Ofshore Drilling Units (MODUs) and criminal sanctions for non-compliance with the Act: Ofshore Petroleum (Health and Safety) Bill 2010, Clauses 26, 27 and 28. he Minister has power to make regulations for the efective implementation of the Act.: Ofshore Petroleum (Health and Safety) Bill 2010, Clause 31. OFFSHORE SECURITY -– FIRST STEPS TOWARDS ESTABLISHING A REGIME UNDER PEPA 2016 The Limited Security Regime under PEPA 2016 Ghana currently has a very limited legal regime for security under PEPA 2016. he sole provision is s. 64 governing emergency preparedness against deliberate attacks. It provides that a licensee, contractor, sub-contractor or the Corporation shall implement and maintain preventive security measures, including control of personnel and goods, to protect their petroleum facilities and wells from deliberate attacks and shall have contingency plans to deal with those attacks. Section 64 relects existing practice in which the international oil companies have various programmes based on industry best practice standards. Examples can be found in the API standards and guidelines which arguably constitute “good oilield practice” with respect to security matters. hese include: API, Security Guidance for the Petroleum Industry (2005);43 API Security Risk Assessment Methodology for the Petroleum and Petrochemical Industries (2013);44 API Recommended Practice 70, Security for Ofshore Oil and Natural Gas Operations (2003 and renewed in 2010)45 he approach taken in these guidance documents fuses threat assessment methodologies drawn from the national intelligence and corporate security arena with a step-by-step enterprise implementation methodology drawn from the well-known International Standardisation Organisations series of risk management and quality management standards. Is there a role for the Maritime Security Act 2004? Coverage could possibly be provided by the Maritime Security Act 2004. However that statute primarily regulates ships and ports as shown by the text of Section 1 of the Act which reads: Scope of application (1) his Act applies to (a) the following types of ships on international voyages (i) passenger ships, including high speed crat, and (ii) cargo ships, including high speed crat of 500 gross tonnage or more; (b) mobile of-shore drilling units that are not located within Ghanaian waters; (c) pleasure crat; and (d) port facilities within the country that serve a ship or a mobile of-shore drilling unit speciied under paragraph (a), subject to subsection (2). (2) he Minister may, (a)’ ater due consideration of a port facility security assessment conducted in accordance with this Act, and (b) having regard to the level of security required to be achieved under this Act, extend by notice published in the Gazette the application of this Act to speciied port facilities within the country which although used primarily by ships not engaged on international voyages, are required occasionally, to serve ships that arrive from or depart on an international voyage. Regulating Safety & Security Matters 253 It is reasonable to conclude that at the moment there is no fully elaborated legal regime governing the security of OOGP in Ghana. Elaboration of a regime has to await ratiication of the SUA Conventions by Ghana and their passage into law. 254 Regulating Safety & Security Matters CHAPTER SUMMARY his Chapter has addressed two closely related themes: (1) safety of ofshore operations in the traditional sense; (2) the protection of OOGP infrastructure from intentional politically or maliciously motivated attack. It has shown that these two aspects of government policy and corporate strategic management as well as day to day procedures are extremely important as well as increasingly complex. he overlap between safety and security matters has become quite signiicant since politically motivated attacks intend to cause fear, damage and destruction and inevitably end up afecting the safety of the infrastructure itself, other critical infrastructure associated with it as well as the safety of employees and other persons in the vicinity of the afected infrastructure. Even so, the requirements of safety management are signiicantly diferent from those of security management and it is appropriate to address the two areas separately. Best practice approaches in both domains would require that companies, governments and other interested parties focus on company-government action with respect to the full planning and implementation of safety case regimes and critical infrastructure protection plans and regimes. In terms of legal regimes, whilst the safety case regime seems now to be reasonably settled, operating through PEPA 2016 and the Protection of Ofshore Operations and Assets Regulations 2010, the regime for security is still in evolution. here is in short a probably adequate regime based on statutes and government-private sector arrangements with the relationship between the various elements appearing to be quite uneven. his is unsurprising given the incremental and post-hoc development of the regime over the last decade. Indeed it may well be that the appropriate balance between the various elements will only become clear once a major incident clariies complementarities as well as conlicts within the regime. Regulating Safety & Security Matters 255 Endnotes 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. Monash University, Course on Safety and Reliability of Ofshore Systems, July 1990 - Survey of Losses – Exploration and Development Prodution – Andrew E Potts Source: Ian Mitroll and Murat Alpaslan “Preparing for Evil” Harvard Business Review (April 2003); Felix Kwamena “Critical Infrastructure Protection: a Canadian Perspective” International Association of Energy Economists (IAEE) Conference, Mexico City October 20 2003. Developing Safety Cases - http://www.adelard.co.uk/iee_pn/safety_case_approach.htm;J Penny, A Eaton CAA (SRG), PG Bishop, RE Bloomield (Adelard), he Practicalities of Goal-Based Safety Regulation in Aspects of Safety Management: Proceedings of the Ninth Safety-Critical Systems Symposium Bristol, UK, 6-8 February 2001, Felix Redmill and Tom Anderson (eds.) at 35-48. Developing Safety Cases - http://www.adelard.co.uk/iee_pn/safety_case_approach.htm Developing Safety Cases - http://www.adelard.co.uk/iee_pn/safety_case_approach.htm http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ http://www.industry.gov.au/ For discussion of the evolution of the safety zone concept see Stuart Kaye, ‘International Measures to Protect Oil Platforms, Pipelines, and Submarine Cables from Attack’, Tulane Maritime Law Journal, vol. 31, no. 2, 2007, pp. 382-386; Hossein Esmaeili, he Legal Regime of Ofshore Oil Rigs in International Law, Ashgate Dartmouth, Aldershot, 2001, pp. 126-128. See also Assaf Harel, ‘Preventing Terrorist Attacks on Ofshore Platforms: Do States Have Suicient Legal Tools?’, Harvard National Security Journal, vol. 4, no. 1, 2013, pp. 143-149. Article 56(1)(b)(i) LOSC. It should be noted that for these purposes mobile ofshore platforms are ships or vessels. he SUA Convention was adopted on 10 March 1988 at a conference in Rome convened by the International Maritime Organisation (IMO) and came into force on 1 March 1992. It entered into force for Australia on 20 May 1993 and is implemented by the Crimes (Ships and Fixed Platforms) Act 1992. It was drated in response to a perceived world-wide escalation in acts of terrorism, and was directly in response to Resolution 40/61 of the General Assembly of the United Nations of 9 December 1985 which speciically invited the International Maritime Organization to ‘study the problem of terrorism aboard or against ships with a view to making recommendations on appropriate measures’. he increased importance of the SUA Convention ater the September 11 attacks is demonstrated by the fact that 95 States are now parties with 37 ratiications received since September 11th. he Legal Committee of the IMO is currently reviewing the Convention in light of changed international conditions and needs since the September 11 events. he amendments proposed by the Legal Committee would signiicantly broaden the range of ofences under the SUA Convention and make it more relevant to current international conditions including introducing provisions allowing the boarding of vessels suspected of being involved in terrorist activities. Conferences to address these amendments are likely to be held in 2005 or 2006. See http://www.imo.org/Newsroom/mainframe.asp?topic_id=280&doc_id=2966 he Fixed Platforms Protocol entered into force on the same date as the Convention, 1 March 1992. As of January 2004 there were 95 Parties to the Protocol. Entry into force for Australia was on 20 May 1993. It is also currently under revision together with the SUA Convention. Article 3(1)(a) SUA Convention. Article 3(1)(b) SUA Convention. Article 3(1)(c) SUA Convention. Article 3(1)(d) SUA Convention. Article 3(1)(e) SUA Convention. 256 Regulating Safety & Security Matters 33. Article 3(1)(f) SUA Convention. 34. Article 3(1)(g) SUA Convention. 35. he split between the two instruments recognises the technical, social and economic reality that ixed platforms (of which OOGP facilities are a subset) are a distinctive use of the marine zone similar to but diferent from navigation. he Fixed Platforms Protocol nevertheless beneits from its close relationship with the more generic SUA Convention which covers navigation generally. 36. Article 2(2)(a)) Fixed Platforms Protocol. 37. Article 2(2)(b)) Fixed Platforms Protocol. 38. Article 2(2)(c)) Fixed Platforms Protocol. 39. Article 2(2)(d)) Fixed Platforms Protocol. 40. Article 2(2)(e)) Fixed Platforms Protocol. 41. he deinition of pipeline includes: (a) pipe used or intended to be used for the conveyance of gas including natural gas, petroleum, oil, water, or any other mineral, liquid, or substance; (b) all ittings, pumps, tanks, appurtenances, or appliances used in connection with a pipeline. 42. he responsible Minister is the Minister for Transport and not the Minister for Energy. 43. http://www.nj.gov/dep/enforcement/security/downloads/API%20Security%20Guidance%203rd%20Edition. pdf 44. http://standards.globalspec.com/std/1603209/api-ansi-api-std-780 45. https://global.ihs.com/doc_detail.cfm?document_name=API%20RP%2070 Regulating Safety & Security Matters 257 258 Regulating Safety & Security Matters g GLOSSARY OF TERMS & CONCEPTS OFFSHORE OIL AND GAS1 Glossary of Terms and Concepts - Ofshore Oil and Gas 259 his Chapter contains an extended Glossary. he information provided is to be read together with the preceding Chapters. Abandon To cease work on a well which is non-productive, to plug of the well with cement plugs. Access rights Authorizations given to a user by a competent management authority or by legislation, to exploit a resource, including the use of the environment as a sink. Access rights can be granted against payment or may be granted free of charge. Access rights are called licences, permits, resource consents, use rights and a variety of other names depending on the resource type, country and legal tradition. Annulus he space between the drillstring and the well wall, or between casing strings, or between the casing and the production tubing. Anticline Rock layers folded in the shape of an arch. Anticlines sometimes trap oil and gas. And salvage all recoverable equipment Also used in the context of ield abandonment. Appraisal Well A well drilled as part of an appraisal drilling programme which is carried out to determine the physical extent, reserves and likely production rate of a ield. Associated Gas Natural gas that over-lies and contacts crude oil in a reservoir. It may be dissolved in the oil at reservoir conditions or may form a cap of free gas above the oil. Where reservoir conditions are such that the production of associated gas does not substantially afect the recovery of crude oil in the reservoir, such gas may also be reclassiied as non-associated gas by a regulatory agency. Also called associated free gas. Barrel A unit of volume measurement used for petroleum and its products (7.3 barrels = 1 to 6.29 barrels = 1 cubic metre). Basement rock Igneous or metamorphic rock, which seldom contains petroleum. Ordinarily, it lies below sedimentary rock. When it is encountered in drilling, the well is usually abandoned. Bbl One barrel of oil; 1 barrel = 35 Imperial gallons (approx.), or 159 litres (approx.); 7.5 barrels = 1 tonne (approx.); 6.29 barrels = 1 cubic metre. Bcf Billion cubic feet; 1 bcf = 0.83 million tonnes of oil equivalent. Bcm Billion cubic metres (1 cubic metre = 35.31 cubic feet). Block A section of ofshore or onshore petroleum area. he standard measurment drawn from the North Sea is approximately 10 x 20 kms. Blocks form part of a quadrant. e.g. Block 9/13 is the 13th block in Quadrant 9. Blow-out An uncontrolled low of gas, oil, or other well luids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pres- 260 Glossary of Terms and Concepts - Ofshore Oil and Gas sure applied to it by the column of drilling luid. A kick warns of an impending blowout. Blow-out preventers (BOP) High pressure wellhead valves, designed to shut of the uncontrolled low of hydrocarbons. Borehole he hole as drilled by the drill bit. Cap gas Natural gas trapped in the upper part of a reservoir and remaining separate from any crude oil, salt water, or other liquids in the well. Capex Capital expenditure. Caprock Impermeable rock overlying an oil or gas reservoir that tends to prevent migration of oil or gas out of the reservoir. Casing string he steel tubing that lines a well ater it has been drilled. It is formed from sections of steel tube screwed together. Christmas tree he assembly of ittings and valves on the top of the casing which control the production rate of oil. Commercial ield An oil and/or gas ield judged to be capable of producing enough net income to make it worth developing. Completion he installation of permanent wellhead equipment for the production of oil and gas. Concrete gravity rigid platform rig A rigid ofshore drilling platform built of steel-reinforced concrete and used to drill development wells. he platform is loated to the drilling site in a vertical position. At the site, one or more tall caissons that serve as the foundation of the platform are looded so that the platform comes to rest on bottom. Because of the enormous weight of the platform, the force of gravity alone keeps it in place. Condensate Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons. Connate water Salt water occurring with oil and gas in the reservoir. Contact 1. In geology, any sharp or well-deined boundary between two diferent bodies of rock. 2. In a petroleum reservoir, a horizontal boundary where diferent types of luids meet and mix slightly; for example, a gas-oil or oil-water contact. Also called an interface. Conventional mud A drilling luidcontaining essentially clay and water; no special or expensive chemicals or conditioners are added. Glossary of Terms and Concepts - Ofshore Oil and Gas 261 Core analysis Laboratory analysis of a core sample to determine porosity, permeability, lithology, luid content, angle of dip, geological age, and probable productivity of the formation. Coring Taking rock samples from a well by means of a special tool known as a “core barrel”. Crane barge A large barge, capable of liting heavy equipment onto ofshore platforms. Also known as a “derrick barge”. Creaming heory A statistical technique which recognises that in any exploration province ater an initial period in which the largest ields are found, success rates and average ield sizes decline as more exploration wells are drilled and knowledge of the area matures. Crude oil Unreined liquid petroleum. It ranges in gravity from 90 API to 550 API and in color from yellow to black, and may have a parain, asphalt, or mixed base. If a crude oil, or crude, contains a sizable amount of sulfur or sulfur compounds, it is called a sour crude; if it has little or no sulfur, it is called a sweet crude. In addition, crude oils may be referred to as heavy or light according to API gravity, the lighter oils having the higher gravities. Cuttings Rock chippings cut from the formation by the drill bit, and brought to the surface with the mud. Used by geologists to obtain formation data. Delineation well A well drilled in an existing ield to determine, or delineate, the extent of the reservoir. Deplete To exhaust a supply. An oil and gas reservoir is depleted when most or all economically recoverable hydrocarbons have been produced. Depth he distance to which a well is drilled, stipulated in a drilling contract as contract depth. Total depth is the depth ater drilling is inished. Derrick he tower-like structure that houses most of the drilling controls. Derrick A large load-bearing structure, usually of bolted construction. In drilling, the standard derrick has four legs standing at the corners of the substructure and reaching to the crown block. he substructure is an assembly of heavy beams used to elevate the derrick and provide space to install blowout preventers, casingheads, and so forth. Because the standard derrick must be assembled piece by piece, it has largely been replaced by the mast, which can be lowered and raised without disassembly. Development drilling Drilling that occurs ater the initial discovery of hydrocarbons in a reservoir. Usually, several wells are required to adequately develop a reservoir. Development phase he phase in which a proven oil or gas ield is brought into production by 262 Glossary of Terms and Concepts - Ofshore Oil and Gas drilling production (development) wells. Development well A development well is a well that is generally drilled in or next to a proven part of a pool to optimize petroleum production.Development wells are drilled ater hydrocarbons have been discovered by successful exploration.A development well is a well drilled for the production of oil or gas from a ield that is known to be suitable because appraisal drilling has already been done. Deviation Departure of the wellbore from the vertical, measured by the horizontal distance from the rotary table to the target. he amount of deviation is a function of the drit angle and hole depth. he term is sometimes used to indicate the angle from which a bit has deviated from the vertical during drilling. Diamond bit A drill bit that has small industrial diamonds embedded in its cutting surface. Cutting is performed by the rotation of the very hard diamonds over the rock surface. Directional drilling Intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It oten involves the use of delection tools. Discovery well he irst oil or gas well drilled in a new ield that reveals the presence of a hydrocarbon-bearing reservoir. Subsequent wells are development wells. Dissolved gas Natural gas that is in solution with crude oil in the reservoir. Dissolved water Water in solution in oil at a deined temperature and pressure. Drill To bore a hole in the earth, usually to ind and remove subsurface formation luids such as oil and gas. Drilling luid Circulating luid, one function of which is to lit cuttings out of the wellbore and to the surface. It also serves to cool the bit and to counteract downhole formation pressure. Although a mixture of barite, clay, water, and other chemical additives is the most common drilling luid, wells can also be drilled by using air, gas, water, or oil-base mud as the drilling mud. Also called circulating luid, drilling mud. Drilling mud Specially compounded liquid circulated through the wellbore during rotary drilling operations. Drilling rig A drilling unit that is not permanently ixed to the seabed, e.g. a drillship, a semi-submersible or a jack-up unit. Also means the derrick and its associated machinery. Dry A hole is dry when the reservoir it penetrates is not capable of producing hydrocarbons in commercial amounts. Glossary of Terms and Concepts - Ofshore Oil and Gas 263 Dry Gas Natural gas composed mainly of methane with only minor amounts of ethane, propane and butane and little or no heavier hydrocarbons in the gasoline range. Dry gas 1. Gas whose water content has been reduced by a dehydration process. 2. Gas containing few or no hydrocarbons commercially recoverable as liquid product. Also called lean gas. Dry hole A well which has proved to be non-productive. Dry hole Any well that does not produce oil or gas in commercial quantities. A dry hole may low water, gas, or even oil, but not in amounts large enough to justify production. E&A Abbreviation for exploration and appraisal. E&P Abbreviation for exploration and production. Enhanced oil recovery A process whereby oil is recovered other than by the natural pressure in a reservoir. Exploration he search for reservoirs of oil and gas, including aerial and geophysical surveys, geological studies, core testing and drilling of wildcats. Exploration drilling Drilling carried out to determine whether hydrocarbons are present in a particular area or structure. Exploration phase he phase of operations which covers the search for oil or gas by carrying out detailed geological and geophysical surveys followed up where appropriate by exploratory drilling. Exploration well A well drilled either in search of an as-yet-undiscovered pool of oil. Exploration well A well drilled in an unproven area. Also known as a “wildcat well”. Farm in When a company acquires an interest in a block by taking over all or part of the inancial commitment for drilling an exploration well. Fault trap A subsurface hydrocarbon trap created by faulting, in which an impermeable rock layer has moved opposite the reservoir bed or where impermeable gouge has sealed the fault and stopped luid migration. Field A geographical area under which an oil or gas reservoir lies. Field A geographical area in which a number of oil or gas wells produce from a continuous reservoir. A ield may refer to surface area only or to underground productive formations as well. A single ield may have several separate reservoirs at varying depths. 264 Glossary of Terms and Concepts - Ofshore Oil and Gas Fixed platform A structure made of steel or concrete, irmly ixed to the bottom of the body of water in which it rests. Flare An arrangement of piping and burners used to dispose (by burning) of surplus combustible vapors, usually situated near a gasoline plant, reinery, or producing well. v. to dispose of surplus combustible vapors by igniting them in the atmosphere. Flaring is rarely used, because of the high value of gas and the stringent air pollution controls. Flare gas Gas or vapor that is lared. Floating ofshore drilling rig A type of mobile ofshore drilling unit that loats and is not in contact with the sealoor (except with anchors) when it is in the drilling mode. Floating units include barge rigs, drill ships, and semisubmersibles. Floating production and system oloader (FPSO) A loating ofshore oil production vessel that has facilities for producing, treating, and storing oil from several producing wells and which puts (ofloads) the treated oil into a tanker ship for transport to reineries on land. Some FPSOs are also capable of drilling, in case they are termed loating production, drilling, and system oloaders (FPDSOs). Flowing well A well that produces oil or gas by its own reservoir pressure rather than by use of artiicial means (such as pumps). Formation pressure he pressure at the bottom of a well when it is shut in at the wellhead. Formation water Salt water underlying gas and oil in the formation. Fracturing A method of breaking down a formation by pumping luid at very high pressures. he objective is to increase production rates from a reservoir or gas (a wildcat well) or to extend greatly the limits of a known pool. It involves a relatively high degree of risk. Exploratory wells may be classiied as (1) wildcat, drilled in an unproven area; (2) ield extension or step-out, drilled in an unproven area to extend the proved limits of a ield; or (3) deep test, drilled within a ield area but to unproven deeper zones. Gas cap A free-gas phase overlying an oil zone and occurring within the same producing formation as the oil. Gas ield A ield containing natural gas but no oil. Gas injection he process whereby separated associated gas is pumped back into a reservoir for conservation purposes or to maintain the reservoir pressure. Gas pipeline A transmission system for natural gas or other gaseous material. he total system comprises pipes and compressors needed to maintain the lowing pressure of the system. Glossary of Terms and Concepts - Ofshore Oil and Gas 265 Gas processing he separation of constituents from natural gas for the purpose of making salable products and also for treating the residue gas to meet required speciications. Gas reservoir A geological formation containing a single gaseous phase. When produced, the surface equipment may or may not contain condensed liquid, depending on the temperature, pressure, and composition of the single reservoir phase. Gas sand A stratum of sand or porous sandstone from which natural gas is obtained. Gas well A well that primarily produces gas. Gas/oil ratio he volume of gas at atmospheric pressure produced per unit of oil produced. Gas-cap drive Drive energy supplied naturally (as a reservoir is produced) by the expansion of the gas cap. In such a drive, the gas cap expands to force oil into the well and to the surface. Gasoline A volatile, lammable liquid hydrocarbon reined from crude oils and used universally as a fuel for internal-combustion, spark-ignition engines. Geophone An instrument placed on the surface that detects vibrations passing through the earth’s crust. It is used in conjunction with seismography. Geophones are oten called jugs. Gusher An oilwell that has come in with such great pressure that the oil jets out of the well like a geyser. In reality, a gusher is a blowout and is extremely wasteful of reservoir luids and drive energy. In the early days of the oil industry, gushers were common and many times were the only indication that a large reservoir of oil and gas had been struck. Horizontal drilling Deviation of the borehole at least 800 from vertical so that the borehole penetrates a productive formation in a manner parallel to the formation. A single horizontal hole can efectively drain a reservoir and eliminate the need for several vertical boreholes. Hydrocarbons n pl: A compound containing only the elements hydrogen and carbon. May exist as a solid, a liquid or a gas. he term is mainly used in a catch-all sense for oil, gas and condensate. More technically organic compounds of hydrogen and carbon whose densities, boiling points, and freezing points increase as their molecular weights increase. Although composed of only two elements, hydrocarbons exist in a variety of compounds, because of the strong ainity of the carbon atom for other atoms and for itself. he smallest molecules of hydrocarbons are gaseous; the largest are solids. Petroleum is a mixture of many diferent hydrocarbons. Impermeable Preventing the passage of luid. A formation may be porous yet impermeable if there is an absence of connecting passages between the voids within 266 Glossary of Terms and Concepts - Ofshore Oil and Gas it. Injection well A well used for pumping water or gas into the reservoir. Interstice A pore space in a reservoir rock. Jacket he lower section, or “legs”, of an ofshore platform. Jackup drilling rig A mobile bottom-supported ofshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the sealoor. A jackup rig is towed or propelled to a location with its legs up. Once the legs are irmly positioned on the bottom, the deck and hull height are adjusted and leveled. Also called self-elevating drilling unit. Kick A well is said to “kick” if the formation pressure exceeds the pressure exerted by the mud column. Lay barge A barge that is specially equipped to lay submarine pipelines. Liqueied natural gas (LNG) Oilield or naturally occurring gas, chiely methane, liqueied for transportation. Natural gas is liqueied to make it easy to transport if a pipeline is not feasible (as across a body of water). LNG must be put under low temperature and high pressure or under extremely low (cryogenic) temperature and close to atmospheric pressure to liquefy. Liqueied petroleum gas (LPG) Light hydrocarbon material, gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling. Commercial liqueied gas consists essentially of either propane or butane, or mixtures thereof. Log (noun): a systematic recording of data, such as a driller’s log, mud log, electrical well log, or radioactivity log. Many diferent logs are run in wells to discern various characteristics of downhole formation. (verb) to record data. Mineral rights n pl: the rights of ownership, conveyed by deed, of gas, oil, and other minerals beneath the surface of the earth. Mmcfd Millions of cubic feet per day (of gas). Moonpool An aperture in the centre of a drillship or semi-submersible drilling rig, through which drilling and diving operations can be conducted. Mud he liquid circulated through the wellbore during rotary drilling and workover operations. In addition to its function of bringing cuttings to the surface, drilling mud cools and lubricates the bit and the drill stem, protects against blowouts by holding back subsurface pressures, and deposits a mud cake on the wall of the borehole to prevent loss of luids Glossary of Terms and Concepts - Ofshore Oil and Gas 267 Natural gas to the formation. Although it originally was a suspension of earth solids (especially clays) in water, the mud used in modern drilling operations is a more complex, three-phase mixture of liquids, reactive solids, and inert solids. he liquid phase may be fresh water, diesel oil, or crude oil and may contain one or more conditioners. A highly compressible, highly expansible mixture of hydrocarbons with a low speciic gravity and occurring naturally in a gaseous form. Besides hydrocarbon gases, natural gas may contain appreciable quantities of nitrogen, helium, carbon dioxide, hydrogen sulide, and water vapor. Although gaseous at normal temperatures and pressures, the gases making up the mixture that is natural gas are variable in form and may be found either as gases or as liquids under suitable conditions of temperature and pressure. Nonporous Containing no interstices; having no pores and therefore unable to hold luids. Ofshore drilling Drilling for oil or gas in an ocean, gulf, or sea. A drilling unit for ofshore operations may be a mobile loating vessel with a ship or barge hull, a semisubmersible or submersible base, a self-propelled or towed structure with jacking legs (jackup drilling rig), or a permanent structure used as a production platform when drilling is completed. In general, wildcat wells are drilled from mobile loating vessels or from jackups, while development wells are drilled from platforms or jackups. Ofshore production platform An immobile ofshore structure from which wells are produced. Ofshore rig Any of various types of drilling structures designed for use in drilling wells in oceans, seas, bays, gulfs, and so forth. Ofshore rigs include platforms, jackup drilling rigs, semisubmersible drilling rigs, submersible drilling rigs, and drill ships. Oil A simple or complex liquid mixture of hydrocarbons that can be reined to yield gasoline, kerosene, diesel fuel, and various other products due to the substances involved having diferent molecular weights. Oil ield A geographic area under which an oil reservoir lies. Oil in place An estimated measure of the total amount of oil contained in a reservoir, but that has not yet been produced.and, as such, a higher igure than the estimated recoverable reserves of oil. Oil pool Loose term for an underground reservoir where oil occurs. Oil is actually found in the pores of rocks, not in a pool. A mixture of base substance and additives used to lubricate the drill bit and to counteract the natural pressure of the formation. Oil seep A surface location where oil appears, the oil having permeated its subsurface boundaries and accumulated in small pools or rivulets. Also called oil spring. 268 Glossary of Terms and Concepts - Ofshore Oil and Gas Oil shale A shale containing hydrocarbons that cannot be recovered by an ordinary oilwell but that can be extracted by mining and processing. Oil slick A ilm of oil loating on water; considered a pollutant. Oil spill A quantity of oil that has leaked or fallen onto the ground or onto the surface of a body of water. Oil zone A formation or horizon of a well from which oil may be produced. he oil zone is usually immediately under the gas zone and on top of the water zone if all three luids are present and segregated. Oilwell A well from which oil is obtained. Operator he company that has legal authority to drill wells and undertake production of hydrocarbons are found. he Operator is oten part of a consortium and acts on behalf of this consortium. Opex Operating expenditure. Payzone Rock in which oil and gas are found in exploitable quantities. Permeability 1. A measure of the ease with which a luid lows through the connecting pore spaces of rock or cement. he unit of measurement is the millidarcy. 2. Fluid conductivity of a porous medium. 3. Ability of a luid to low within the interconnected pore network of a porous medium. Permeable rock A porous rock formation in which the individual pore spaces are connected, allowing luids to low through the formation. Petroleum 1. A substance occurring naturally in the earth in solid, liquid, or gaseous state and composed mainly of mixtures of chemical compounds of carbon and hydrogen, with or without other nonmetallic elements such as sulfur, oxygen, and nitrogen. 2. A generic name for hydrocarbons, including crude oil, natural gas liquids, natural gas and their products. Petroleum geology he study of oil and gas-bearing rock formations. It deals with the origin, occurrence, movement, and accumulation of hydrocarbon fuels. Petroleum reservoir A rock formation that holds oil and gas. Petroleum rock Sandstone, limestone, dolomite, fractured shale, and other porous rock formations where accumulations of oil and gas may be found. Petroleum window he conditions of temperature and pressure under which petroleum will form. Also called oil window. Platform An ofshore structure that is permanently ixed to the seabed. Glossary of Terms and Concepts - Ofshore Oil and Gas 269 Play 1. he extent of a petroleum-bearing formation. 2. he activities associated with petroleum development in an area. Pool A reservoir or group of reservoirs. he term is a misnomer in that hydrocarbons seldom exist in pools, but, rather, in the pores of rock. v to combine small or irregular tracts into a unit large enough to meet state spacing regulations for drilling. Porosity 1. he condition of being porous (such as a rock formation). 2. he ratio of the volume of empty space to the volume of solid rock in a formation, indicating how much luid rock can hold. Porosity he percentage of void in a porous rock compared to the solid formation. Possible reserves hose reserves which at present cannot be regarded as ‘probable’ but are estimated to have a signiicant but less than 50% chance of being technically and economically producible. Potential he maximum volume of oil or gas that a well is capable of producing, calculated from well test data. Primary recovery Recovery of oil or gas from a reservoir purely by using the natural pressure in the reservoir to force the oil or gas out. Probable reserves hose reserves which are not yet proven but which are estimated to have a better than 50% chance of being technically and economically producible. Producer 1. A well that produces oil or gas in commercial quantities. 2. An operating company or individual in the business of producing oil; commonly called the operator. Production 1. he phase of the petroleum industry that deals with bringing the well luids to the surface and separating them and with storing, gauging, and otherwise preparing the product for the pipeline. 2. he amount of oil or gas produced in a given period. Proved reserves of crude oil n according to API standard deinitions, proved reserves of crude oil as of December 31 of any given year are the estimated quantities of all liquids statistically deined as crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves of natural gas According to API standard deinitions, proved reserves of natural gas as of December 31 of any given year are the estimated quantities of natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known natural gas reservoirs under existing economic and operating conditions. 270 Glossary of Terms and Concepts - Ofshore Oil and Gas Proven ield An oil and/or gas ield whose physical extent and estimated reserves have been determined. Proven reserves hose reserves which on the available evidence are virtually certain to be technically and economically producible (i.e. having a better than 90% chance of being produced). Recoverable reserves hat proportion of the oil and/gas in a reservoir that can be removed using currently available techniques. Recovery factor he ratio of recoverable oil and/or gas reserves to the estimated oil and/or gas in place in the reservoir. Reserves he unproduced but recoverable oil or gas in a formation that has been proved by production. Reservoir he underground formation where oil and gas has accumulated It consists of a porous rock to hold the oil or gas, and a cap rock that prevents its escape. Reservoir rock A permeable rock that may contain oil or gas in appreciable quantity and through which petroleum may migrate. Resources Concentrations of naturally occurring liquid or gaseous hydrocarbons in the earth’s crust, some part of which are currently or potentially economically extractable. Riser (drilling) A pipe between a seabed BOP and a loating drilling rig. Riser (production) he section of pipework that joins a seabed wellhead to the Christmas tree. Risk analysis he activity of assigning probabilities to the expected outcomes of drilling venture. Royalty payment he cash or kind paid to the owner of mineral rights. Samples 1. he well cuttings obtained at designated footage intervals during drilling. From an examination of these cuttings, the geologist determines the type of rock and formations being drilled and estimates oil and gas content. 2. small quantities of well luids obtained for analysis Sandstone A sedimentary rock composed of individual mineral grains of rock fragments between 0.06 and 2 millimetres (0.002 and 0.079 inches) in diameter and cemented together by silica, calcite, iron oxide, and so forth. Sandstone is commonly porous and permeable and therefore a likely type of rock in which to ind a petroleum reservoir. Glossary of Terms and Concepts - Ofshore Oil and Gas 271 Secondary recovery Recovery of oil or gas from a reservoir by artiicially maintaining or enhancing the reservoir pressure by injecting gas, water or other substances into the reservoir rock. Sedimentary rock A rock composed of materials that were transported to their present position by wind or water. Sandstone, shale, and limestone are sedimentary rocks. Seep he surface appearance of oil or gas that results naturally when a reservoir rock becomes exposed to the surface, thus allowing oil or gas to low out of issures in the rock. Seismic Of or relating to an earthquake or earth vibration, including those artiicially induced Seismic data Detailed information obtained from earth vibration produced naturally or artiicially (as in geophysical prospecting). Seismic survey An exploration method in which strong low-frequency sound waves are generated on the surface or in the water to ind subsurface rock structures that may contain hydrocarbons. he sound waves travel through the layers of the earth’s crust; however, at formation boundaries some of the waves are relected back to the surface where sensitive detectors pick them up.Relections from shallow formations arrive at the surface sooner than relections from deep formations, and since the relections are recorded, a record of the depth and coniguration of the various formations can be generated. Interpretation of the record can reveal possible hydrocarbon-bearing formations. Seismic wave he record of an earth tremor by a seismograph. Semisubmersible drilling rig A loating ofshore drilling unit that has pontoons and columns that, when looded, cause the unit to submerge to a predetermined depth. Living quarters, storage space, and so forth are assembled on the deck. Semisubmersible rigs are self-propelled or towed to a drilling site and anchored or dynamically positioned over the site, or both. In shallow water, some semisubmersibles can be ballasted to rest on the seabed. Semisubmersibles are more stable than drill ships and ship-shaped barges and are used extensively to drill wildcat wells in rough waters such as the North Sea. Two types of semisubmersible rigs are the bottle-type and the column-stabilized. Shale A ine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. Shallow gas Natural gas deposit located near enough to the surface that a conductor or surface hole will penetrate the gas-bearing formations. Shallow gas is potentially dangerous because, if encountered while drilling, the well usually cannot be shut in to control it. Instead, the low of gas must be diverted. 272 Glossary of Terms and Concepts - Ofshore Oil and Gas Show he appearance of oil or gas in cuttings, samples, or cores from a drilling well. Shutdown A production hiatus during which the platform ceases to produce while essential maintenance work is undertaken. Sour gas Gas containing an appreciable quantity of hydrogen sulide. Spud-in he operation of drilling the irst part of a new well. Stratigraphic test A borehole drilled primarily to gather information on rock types and sequence. Stratigraphic trap A petroleum trap that occurs when the top of the reservoir bed is terminated by other beds or by a change of porosity or permeability within the reservoir itself. Structural trap A petroleum trap that is formed because of deformation (such as folding or faulting) of the reservoir formation. Structure A geological formation of interest to drillers. For example, if a particular well is on the edge of a structure, the wellbore has penetrated the reservoir (structure) near its periphery. Suspended well A well that has been capped of temporarily. Sweet crude oil Oil containing little or no sulfur, especially little or no hydrogen sulide. Syncline A trough-shaped coniguration of folded rock layers. Tar sand A sandstone that contains chiely heavy, tarlike hydrocarbons. Tar sands are diicult to produce by ordinary methods; thus it is costly to obtain usable hydrocarbons from them. TCF Trillion Cubic Feet (of gas). hermal decomposition he breakdown of a compound or substance by temperature into simple substances or into constituent elements. Tight formation A petroleum- or water-bearing formation of relatively low porosity and permeability. Topsides he superstructure of a platform. Trap A body of permeable oil-bearing rock surrounded or overlain by an impermeable barrier that prevents oil from escaping. he types of traps are structural, stratigraphic, or a combination of these. Water-producing interval Glossary of Terms and Concepts - Ofshore Oil and Gas 273 he portion of an oil or gas reservoir from which water or mainly water is produced. Well he hole made by the drilling bit, which can be open, cased, or both. Also called borehole, hole or wellbore. Well completion 1. he activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more low paths for hydrocarbons are established between the reservoir and the surface. 2. he system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon low path or paths. Well control he methods used to control a kick and prevent a well from blowing out. Well log A record of geological formation penetrated during drilling, including technical details of the operation. Well logging he recording of information about subsurface geologic formations. Wildcat A well drilled in an area where no oil or gas production exists. Wildcat well A well drilled in an unproven area. Also known as a “exploration well”. Workover Remedial work to the equipment within a well, the well pipework, or relating to attempts to increase the rate of low. ABBREVIATIONS GJ GL Gm3 Gt GWh LNG ML Mt PJ t NGL Tcf gigajoule gigalitre gigacubic metre gigatonne giga watt-hours liqueied natural gas megalitre megatonne petajoule tonne Natural gas liquids trillion cubic feet 274 Glossary of Terms and Concepts - Ofshore Oil and Gas Endnotes 1. his glossary is adapted from the following sources: (1) Petroleum Extension Service of the University of Texas at Austin Dictionary for the Petroleum Industry 3rd Edition 2001, http://www. utexas.edu/cee/petex/. (2) Britain’s Ofshore Oil and Gas Book http://www.oilandgas.org.uk/issues/ storyofoil/index.htm; (3) Schlumberger Oilield Glossary at http://www.glossary.oilield.slb.com/. Glossary of Terms and Concepts - Ofshore Oil and Gas 275