Risk Mitigation Using Joint Venture Agreement in the Upstream Petroleum Industry

The concept of risk and Joint venture in the petroleum industry is a common phenomenon and has evolved over the years basically because of the peculiarity of the industry and the environment in which it operates. Risks extend to geological circumstances like the size of the discovery, topography of the proposed oil fields and the location of the field (onshore or offshore).

Recent innovations have made possible for oil and natural gas extraction in deep waters which before time had been quite difficult. The risk involved is quite enormous and can only be matched by a viable prospect or a field with great potential, sufficient enough to generate positive economic rents.

Others include oil and gas prices, regulatory and legislative changes, fiscal (tax) policy changes including the increased cost of compliance, depletion of new discoveries or replacement reserves, operational hazards like injuries, spills and blow outs, inaccurate reserve estimates, extreme weather conditions, environment restrictions and regulations, reduction in demand for oil and natural gas, competition from alternative sources of energy, increased operating cost, inadequate or unavailable insurance coverage, inadequate liquidity or access to capital, shortage of rigs, equipment and personnel, uncertain energy policy, worsening and supply and demand shocks etc. Joint venture businesses and agreements are more inclined towards resources, cost and reward sharing and its introduction into the petroleum industry has been adopted by both International oil companies (IOC) and National oil companies (NOC) as a negotiation tool to implement exploration and production

. 1. 2MOTIVATION - CONCEPTUAL FRAMEWORK In the light of the fundamental and background issues above, specifically the potential impact of the risks and uncertainties in executing activities in the oil and gas industry cannot be ignored.

Taking a close look at the industry, it is easier to assume that International oil companies (IOC) and national oil companies (NOC) are not faced with the risk and as such the industry is seen to be thriving. However in an effort to diversify the risks identified, over the years oil companies have adopted methods to manage risks and maximise their gains by integrating and disintegrating activities along the supply chain line, having full knowledge of the prospects of an oil field before embarking on investments, initiating contractual relationships with national oil companies aimed at either sharing risks or obtaining incentives relative to unprofitable investments etc.

Some IOCs have signed contractual agreements indicating a form of partnership with explicit details of level of participation in potential oil field developments. The idea is simple, funds and resources are pooled together and combined interests are initiated in the investments such that anticipated cash flows, profits and incentives as well as risks, losses, fines and penalties are shared based on predetermined agreement. Thus the conceptual framework here is the extent to which these agreements can influence decision making relative to the existing risk and uncertainties on one hand and the participating firms’ ultimate goal of maximising its benefits to investors. 1. 3RESEARCH QUESTIONS

Throughout the study, the fundamental questions sought to be answered will include; * Why do Joint venture agreements exist? * Why are most joint ventures unincorporated rather than incorporated? * For potential new joint ventures, what are the incentives that encourage their start-up and how is the welfare optimization of all partners factored into agreements to avoid conflict of interest? * For existing joint ventures, how receptive should partners be to modifications in existing agreements by way of fiscal, political and economic changes? * What are the reasons for unsuccessful joint ventures and the possibilities of avoiding the failures? 1. 4SIGNIFICANCE OF STUDY

The research addresses itself to: Scholars – that they may gain valuable insight and improved knowledge of the risk profile of oil and gas fields and appreciate a modelling approach of how certain variables contribute to viability of the field; Investors – to assist toward building a diversified portfolio with investments in an optimal mix of oil and gas fields while trying as much as possible to reduce potential losses from investments; Independent oil and gas companies – to provide differing and alternative options for embarking on development and production projects in the wake of limited capital and resources, and to have a background knowledge of the important elements (e. g. choice of venture partner) of a potential joint venture agreement; Policy makers and regulators – to identify reasons for joint venture failures and proffer potential solutions and recommendation on a case basis; Energy analyst – to appreciate a modelling approach of how elements of risks, investment, portfolio management and contractual agreements interplay to give an understanding of upstream development. 1.

5SCOPE AND LIMITATION The study will lay much emphasis on risk and joint venture agreements in the upstream sector of the oil industries as it affects project development. In order to streamline our valuation indices, revenue streams from crude oil (excluding gas) alone will be used. The implication is that the appraisal of the field development will be limited to income streams from the sale of crude oil. There will be two (2) case study reviews to illustrate risk and joint venture activities at the exploration and development phase. The purpose is to expand on the theoretical dynamics of risks and joint venture agreements using real life case analysis.

To demonstrate upstream project appraisal of joint venture projects, this study will adopt hypothetical indices relative to the oil prices, tax and fiscal system, capital and operating expenditures, reserves, field life and weighted average cost of capital. The rationale behind the estimates, the underlying assumptions as well as their limitations will be discussed in CHAPTER 3. A royalty plus a corporate tax system will be used as a tool to determine governments take from each oil field. This will help to demonstrate in our model, the impact of unanticipated fiscal adjustments and also ensure that government take is directed at the output. The model will involve the development of 8 hypothetical oil fields, equally divided into onshore and offshore.

From these fields the following (3) scenarios will be modelled separately and each result compared and discussed in line with the research questions and aim of the dissertation: Scenario1: Interest in the 8 fields is shared between a single IOC and the host country’s NOC (i. e. 2 Joint venture partners) and the IOC have the entire investments in its portfolio. The investment appraisal will measure the viability of the entire project from the point of the IOC. Scenario 2:There are multiple Joint Venture Partners (i. e. NOC and several IOC interests). The appraisal will be from the standpoint of an IOC with differing interest in each field while the aggregate position of the IOC across the 8 fields will be measured and discussed. Scenario 3:An improvement on Scenario 2 indicating capital budget allocation.

The proposed IOC above has joint venture investment options across the 8 fields and certain budgeted capital expenditure to which to maximise the company’s wealth. 1. 6OUTLINE OF DISSERTATION Chapter 2: This will begin with understanding the risk and investment issues in the upstream petroleum industry and an introduction into joint venture agreements, a review of the types of agreement and the reasons behind venture relationships. A critical review and assessment of two real case studies - a successful and unsuccessful joint venture will be discussed with an aim of highlighting the risks discussed earlier and the impact of joint venture activities at identifying and managing the risks.

Chapter 3: The data and methodology required to develop the model from which to demonstrate joint venture agreements and operations on the upstream development projects will be specified. The relevant parameters and assumptions to help validate the model will also be specified. Results of each of the 3 case scenarios by way of charts and diagrams will be included in the chapter. This will also include results of the sensitivity analysis. Chapter 4: The result from chapter 3 will be discussed extensively in this chapter and the three scenarios will be compared in line with the aim of the dissertation. The limitations of the parameters used for model will also be discussed.

Chapter 5: The dissertation will be concluded in this chapter by bringing together all the information gathered from the study. It discussed the implication of the case studies in line with the models. We revisit the risk issues in the upstream with the intention of identifying future risk diversification strategies like real options etc. CHAPTER 2LITERATURE REVIEW & CASE STUDY 2. 1BACKGROUND Knowledge will be drawn from existing literature on Joint venture and the oil and gas industry with emphasis on risk profile, investment decision-making and investment appraisal in the upstream sector. The literature review is structured to focus on explaining theoretically, the research questions clearly stated in chapter 1. 2. 2JOINT VENTURE – AN INTRODUCTION

In the upstream industry, it is extremely rare for a single company to execute an exploration and production activity by itself. The general norm is via Joint venture and partnerships. Venture alliances have received increased attention since the 1990s and have seen oil companies on a search for new ways of doing business in order to increase performance. The hostile and difficult economic environment has further ensured companies are not far from this objective. Furthermore, joint ventures have opened up opportunities in many countries especially where exploitation has been restricted to national companies (Jenkins 2000). The concept involves two or more companies operating together by pooling their asset or properties for a limited purpose or time (Hardy 2002).

Burrows (2011) citing the case between United Dominion Corporation Ltd v Brian (1985) defined it as “…an association of persons for the purposes of particular trading, commercial, mining or financial undertaking or endeavour with a view to mutual profit, with each participant usually (but not necessarily) contributing money, property or skill”. 2. 3TYPES OF JOINT VENTURE There are several forms of joint venture but the legal classification falls into three (3) (Abduljaami 2011): * Contractual Joint Venture * Corporate Joint Venture * Unincorporated Venture Contractual joint ventures are good choices for one-off and short term business agreements.

Usually set to terminate within a short term future date, it requires no form of legal registration or formal dissolution procedure to terminate and is applicable when very few assets are involved. Corporate joint venture requires that a new corporation be set-up which will be separate and independent from the businesses of the participating companies. The new company will be used as a tool for driving the business and does this by itself (Hardy 2002, Abduljaami 2011). Unincorporated joint venture is quite similar to the corporate joint venture because it also requires the establishment of an entity. It however differs based on the type of entity as unincorporated joint venture exists in the form of “limited liability Company”.

Burrows (2011) describes it as “an association of participants” lacking form and equity capital. This is common in upstream oil and gas development and the reason will be discussed below. 2. 4CHOICE OF JOINT VENTURE Hardy (2002) distinguished between the two latter types of joint venture and the rationale for each. The incorporated JV oversees its activities via the appointees on the board of directors and the new company levies its partners for expenses and projects cost while their percentage interest are reflected in their shareholdings. Upon completion, the assets are distributed or sold to the Joint Venturers. The fact that unincorporated JV does not use a separate entity translates to them operating as partners.

In fact both forms of JV are assumed to be disguised partnership since the law provides that any form of relationship that subsists between persons carrying a business in common with a view to making profit is a partnership (UK Partnership Act 1890 c39. ). The purpose of this is to make the parties liable for each other’s action. As a limited liability partner or limited liability company the extent of the liability of a venture partner is limited to the amount invested in the business by the unincorporated venturer. Corporate JV who have legal issues have each co-venturer fully liable to the JV creditors (Abduljaami 2011). This has been seen to be a major reason why most oil company joint ventures are unincorporated. 2. 5JOINT VENTURE RELATIONSHIPS IN THE OIL INDUSTRY

Traditionally, most joint ventures exist in the upstream industry (Hardy 2002) and were usually between two major international companies focused on exploration and production in particular geographic areas (Jenkins 2000). Examples of these existed between shell and Exxon in Northwest Europe, Chevron and Texaco in Southeast Asia and BP and shell in Africa (Jenkins 2000: Yergin & Stanislaw 1993). The previous belief about JV is that partners refuse to cooperate and thus behave as an independent entity. Usually there is an operator in the JV while others work independently, though keeping checks on activities of the operator to ensure their shareholders interest are protected. This is because the shareholders are divergent in their separate interest.

However in recent times, the new style of working is that a joint team drawn from staff from all venture partners are integrated into a supporting role (Jenkins 2000). An exploration and production venture between contemporary oil companies includes pooling of acreage holdings and contracts to take part in specific license rounds in individual countries. The basis for this according to Jenkins (2000) is to “enhance financial capability and risk sharing”. Another benefit includes gaining synergy from harnessing individual partner skills and complimenting each other’s capability. At some time, a strategic venture between BP and Statoil specifically defined the countries to jointly participate in seeking exploration ventures.

The venture sought to ensure risks are shared between the partners and also to benefit from partners expertise and political influence; a number of successful projects were traceable to this arrangement. Other joint venture agreements that has successfully been executed and still exist include; Chevron-Schlumberger venture in the California Lost Hills field in 1990, Lasmo-Schlumberger venture in the Dacion field in Venezuela, Andrew Well Venture in the North sea which included, BP, Schlumberger, Baker Hughes, Transocean and Santa Fe. The Hibernia venture in Canada had Mobil, Chevron, Petro-Canada, Norsk Hydro and Murphy led to HMDC (Hibernia Management Development Company Ltd) (Cameron et al 2000).

The success of the upstream joint venture is usually a function of the relationship between partners aimed at arriving at a “win-win” situation for all partners. On a field basis, this will include benefits from reduced field development costs, enhanced well production, improved resource optimization, lower learning cost and reduced cycle time (Cameron et al 2000). This study is focused more on how JV can be used as a tool for risk mitigation in the upstream industry; therefore discussion about the relationship between partners is excluded. However the extent of cooperation between the partners cannot be discounted at achieving a successful venture. 2.

6RISK ANALYSIS OF THE UPSTREAM INDUSTRY Anderson et al (1981) defines risk and uncertainty as “… a situation in which one has no knowledge about which of several states of nature has occurred or will occur…” while Humphreys and Berkley (1985) further breaks down the components of uncertainty as the lack of ability to affirm with confidence an act or event sequence, a future preference or action, or an ability to influence future e events. In a brief explanation of risk, Lathrop and Watson (1982) described it as a potential for adverse consequences. Exploration and production of oil and natural gas require huge capital expenditure and involves numerous risks.

It is subject to natural hazards and other uncertainties some of which are related to the physical characteristics of oil or natural gas fields. Exploration activities involve numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons (Van Vactor 2010). In a high profile, capital intensive, resource driven project like the upstream industry, there is little tolerance for the potential impact of not thoroughly accessing the risk and uncertainties of an exploration and development project. In very realistic settings, risks and uncertainty constitute a key impediment to successful capital investment and decision-making (Simpson et al. , 2000 and 1999; Lamb et al.

, 1999; Ball and Savage, 1999; Watson; 1998; Murtha, 1997; Newendorp, 1996; McCaskey 1986; Corbin, 1980). Smith (1997) in his report on future opportunities and challenges of the upstream oil and gas industry in the 21st century agrees emphatically that the upstream oil and gas industry is founded on uncertainty and risk. He related most of the risks to declining reserves, environmental challenges and competition from alternative sources of energy, oil prices and technology and geographical frontiers amidst various reasons. Kemp (1988) highlighted the risks at the development stage as development cost risk, oil price risk, political risks and reservoir risks. 2. 6.

1OIL PRICE RISK: Economists argue that prices are generally determined by the forces of demand and supply, but a deeper analysis of current trend as depicted by Vactor (2010) reflects high fluctuation and unpredictability in oil prices beyond the impact of demand and supply. This has been complimented by unstable political events in the Middle East and Caspian region, changing economic growth in Asian countries like china, revised resource assessment and consumer reactions all of which are quite difficult to forecast. The attention brought about by volatile oil prices has increased in recent years, even Hamilton (2009) suggested that price was a contributing factor to the recession between 2007 and 2009. Characterising the relationship between investment and prices has been difficult with no precise consensus emerging.

Skjerpen, Ringlund and Rosendahl (2004) tried to explain the relationship by reviewing why supply has not responded strongly to higher prices in recent times and this led to observing seven (7) important regional differences in supply elasticities. Cathsassus, Collin_Dufresne and Routledge (2005) paper which was mostly concerned with modelling of oil price behaviour revealed empirical findings which supported the notion of “lumpiness and non-linearity in oil investment” relating it to the impact of fixed adjustment cost. By modelling oil prices as a regime-switching process, the model was able to confirm significant features of oil prices (e. g. backwardation).

Furthermore, the impact of oil prices is very important in investment appraisal since majority of the income streams is determined by the prevailing oil prices over the life of the project, thus the need to adopt a forecasting approach for future prices. The IDB 2010 confirmed that the oil price volatility in the last 4 years to 2008 was a credible reason for sluggish investment activities by oil producers despite some periods having persistent high prices. Once an investment has been made, the price risk becomes a constant unavoidable companion. 2. 6. 2POLITICAL/REGULATORY RISK: These are adverse circumstances suffered by IOCs and can be linked to decisions made by the host government. This occurs by way of expropriation, state intervention, lack of legal clarity, and unanticipated alteration to existing regulations and agreements (Daniel et al, Kindle Edition, and Marsh (n. d. )).

The ideal purpose of regulations amongst other things is to manage the way the natural resources are extracted and produced and this differs by location or countries. It is normal for IOCs to prefer counties with stable political and legislative system and also generous long term lease agreements; however some investors still invest wherever the oil and gas is despite the location not matching their preference. This may lead to sudden nationalisation or frequent regulatory changes by the government especially when the capital has been invested. Furthermore countries characterised by political restlessness and upheaval poses security issues to staff and operations of the companies, thus there is an important need to consider the political situation prior to operation by any IOC.

Kemp’s (1989) manuscript on “Development of National Policies towards Oil and Gas Exploration in the UK and their Effects” sited three conditions under which these political risks materialises; * When certain discontinuities exist in the business environment * When the discontinuities above are difficult to anticipate * When the discontinuities result from a political change Taking the UK for example, oil price increases in the late 1970s from $14 to $39 was followed by rising adjustment in the UKs petroleum and fiscal regime when the SPD (Supplementary Petroleum Duty) was introduced in 1981. This is an example of a discontinuity brought about by unstable oil price.

Some countries with recent political upheaval include Liberia, Nigeria, Libya and Egypt on the African continent. 2. 6. 3GEOLOGICAL/RESERVOIR RISK: Oygard (2005) describes this as an evaluation of geological factors critical to discovering and recovery of commercial quantities of hydrocarbon by relating probability of discovery to the probability of reservoir, a trap mechanism, a hydrocarbon charge and retention of hydrocarbon after accumulation. The easy to get reserves have either been fully extracted or still being extracted and thus exploration and production activities have now been focused on less friendly environments usually by way of a platform in the center of a surging ocean (Beattie 2012).

The totality of geological risk is not limited to the difficulty and challenges of extraction but also includes the possibility that recoverable reserves in a field may not be commercial or perhaps a well may be a dry hole. 2. 6. 4ACCESS TO AVAILABLE RESOURCES: An interesting characteristic of oil distribution is that the biggest deposits are far from population centers Vactor (2010). Once located, it is usually a distance from the market. The BP statistical review 2012 shows that the current world proven reserves is distributed as follows; Middle East – 48. 1% , South and central America – 19. 7%, North America – 13. 2%, Europe and Asia – 8. 5%, Africa – 8% and the Asian Pacific – 2. 5%.

Recent estimation confirms that 75% of global proven reserves are in the control of national oil companies thus making them gatekeepers of world’s oil supplies (Jessen 2008). The implication is that both the NOCs and the IOCs now compete for reserves and this constitutes a threat to the latter. 2. 6. 5ENVIRONMENTAL RISKS: The importance of tackling environmental risks is becoming a more central issue for oil industries and regulators. The process of petroleum extraction carries adverse environmental impact on a regional and global scale. These includes, oil spills, volatile organic compounds, air pollution and soil surface and ground water toxicity (Kharaka & Dorsay 2005).

In a bid to regulate these activities, governments have factored in certain environmental standards into the contractual agreements with investors. International environmental community is always alert to wade into potential issues that come up from exploration and production activities (see case study). 2. 6. 6COST RELATED RISK: All other risks are assumed to fit into the cost implication of any project. Both operational and capital costs greatly influence the potential development of oil fields. The upstream capital cost index measuring cost inflation in oil projects has increased by 79% since 2000 (Vactor 2010). Inability to manage and control costs will undermine the competitiveness of oil companies. Burdensome regulations and difficulties with drilling make projects more expensive.

Oil companies still struggle with shortage of qualified manpower required during boom times and are sometimes required to pay more to retain existing workers (Beattie 2012). All these costs have made the industry capital intensive thereby reducing the number of players. Other risks include, demand and supply shocks, inflation, exchange rate, climate concerns, uncertain energy policies and competition from renewable energy sources. (Jessen 2008). 2. 7RISK DIVERSIFICATION - SYSTEMATIC & UNSYSTEMATIC RISK Brealy & Myers (2007) recommended diversification as a means to reduce the risk profile of a portfolio. Introducing it as a strategy designed to reduce risk by distributing the portfolio across a wide range of investments. The risks were divided into “systematic” and “unsystematic” risk. Ross et al (2005)

sums up the total risk of any investment as the addition of its systematic and unsystematic risk and further defined systematic risk as “…any risk that affects a large chunk of assets, each to a greater or lesser degree…” Also referred to as a market risk brought about by economy wide (macroeconomic) sources and affects the overall industry. The unsystematic risk known as the unique risk is usually related to specific investment or project and has peculiarities attributable to the investment alone (Brealy & Myers 2007). The fundamental aim of diversification is to eliminate the unique risks or unsystematic risks some of which are listed as exploration risks, reserves, recovery, production, drilling and operations (Kemp 2012). Chart 2. 1: Chart distribution of systematic & Unsystematic risk: Adapted from Kemp (2012) Chart 2. 1: Chart distribution of systematic & Unsystematic risk: Adapted from Kemp (2012)

The market risks are brought about by macroeconomic indices like inflation, crude oil prices, foreign exchange, material and resource costs etc. , and cannot be diversified. Figure (2. 1) shows that the level of the systematic risk remains constant for every combination of portfolio (i. e. any accumulation of investments in oil fields) while the unsystematic risk reduces up to the point where it is entirely eliminated and the investment has only the systematic risk to deal with. 2. 8UPSTREAM RISK AND PROJECT EVALUATION Sequel to identifying the risk factors and understanding how to diversify them, the viability of a potential joint venture development project is important otherwise the purpose of the venture will be defeated.

Appraisal techniques commonly used at the development stage include the use of NPV and IRR which are discounting methods. The advantage they proffer is that they acknowledge the time value of money and consider all cash flows throughout the life of the project. The fundamental issue at this point is the choice of discount rate. The Weighted average cost of capital (WACC) usually an aggregate reflection of the forms of capital employed by organisations is usually adopted. But having justified the existence of certain risk factors, it is normal for investors to require a level of compensation for these risks (Newendorp 1996). Therefore oil risk preferences are usually

incorporated into the choice of discount rates such that the discounting is an addition of the opportunity cost of capital and a certain risk premium to compensate investors. The credibility of NPV as decision tool has been questioned severally. Michel (2001) criticised the assumption of forecasted cash flows adding that unanticipated variations are not accounted for by NPV. The choice of discount rate has been questioned as well. While some literatures recommend discount rates of similar projects having same risk profile (ACCA 2008, Kruger et al 2011), others lay emphasis on the capital structure or the average risk profile of the entire company portfolio (Brealy & Myers 2008).

However the latter does not consider potential changes to investors’ future capital structure and the fact that project with greater risk will be discounted by a lower discount factor. They have totally neglected the effect of diversification. In oil production terms when we assume an existing portfolio of oil fields with specific risks and an additional field project in a different country, having a political risk (e. g. Society upheaval) or economic risk (inflation or exchange rate), it is unprofessional to ascribe the existing risk profile of the portfolio to the new field since its own risk structure is different and investors might require a higher return on the investment.

Without a specific discount rate that portrays both the risk profile of the project and the capital structure over the life of the investment, the NPV is vulnerable to manipulations and thus, the viability of the project (Michel 2001). In recent times, sensitivity analysis has been used, where the NPV is examined after several simulations of a distribution of discount rate. 2. 9MITIGATING RISK THROUGH VENTURE AGREEMENTS Jenkins (2000) highlighted 4 potential forms of agreements and their peculiarities in managing risks. The first is in the form of technological ventures where partners set up joint industry projects (JIPs). Example is the alliance between Mobil, BP, Texaco and Chevron which was given the acronym “MoBPTeCh”.

The idea behind MoBPTeCh stems from the notion that the nature of technology in the upstream industry leads to rapid technology transfer and the competitive advantage is in being an early user. Furthermore a review of IOCs research and development programs shows that there is considerable duplication of work done. The implication is that more cost is being incurred and technological joint venture is a way to harness the individual efforts and thus accelerate the pace of innovation while utilising resources efficiently. The second venture exists solely for project development. We discussed the capital intensive nature of the upstream industry and its associated risk.

Stating that a key component of the venture agreement was the financial contribution of partners, Jenkins (2000) added that the implication is that partners enter a risk-reward sharing agreement that is structured to ensure alignment with objectives of performance. The third form of joint venture exists between oil companies and service companies. While the oil companies want an improved rate of recovery and production at a lower cost, the servicing company’s objective is to increase its profit per equipment supplied. The importance of an effective agreement between the two parties is important to tackle exploration, development and production challenges. The fourth and final is the IOC and NOC joint ventures.

We established earlier that in some countries, the NOCs are routes for preferential access to the oil and gas resources. The fundamental question is how to initiate a mutually beneficial agreement with the NOC. It is easy to assume that same ideology behind private sector joint ventures should apply, however the political dimension that accompanies NOCs who operates as vehicles of the state should be considered. Most IOCs have resorted to using the benefit of technology and modern business skill transfer as bargaining chips to initiate venture relationships. 2. 10CASE STUDY 1 CONOCO POLAR LIGHTS JOINT VENTURE IN THE RUSSIAN FEDERATION – A SUCCESSFUL STARTUP EXPERIENCE. (Buolos, A. J.

2000) Learning point: There is a possibility of credible partnership agreements between International oil companies and host governments national oil companies especially when objectives are common and executed in the interest of both venture partners. 2. 10. 1Structure of the Joint Venture The Polar lights venture was a combined interest of Conoco (an international petroleum company) with 50% interest, Arkhangelskgeoldobycha (AGD) - 30% and Rosneft (20%) and it was the first Russian-American Joint venture since establishment of the Polar Lights area in 1992. It was for the development and production of crude oil in the Ardalin fields in northern Russia’s Timan Pechora Basin.

Conoco, a US based International Corporation founded in 1875 and about the 10th largest oil and Gas Company in the world had great experience in technological processing of floating structures and tension leg platforms. It has a successful track record initiating and implementing seamless partnership with host governments and their national companies. This as discussed later was a platform for the success of the joint venture. Rosneft was a Russian state enterprise established by a presidential decree in 1992. AGD was a leader in discovery of major petroleum reserve in Russia having discovered an estimated 500 deposits of natural resource of which about 70 are oil and gas fields. 2. 10. 2Partners’ selection and choice

The choice of venture partners does call for a review, or better still, why did the three companies select each other as partners? In Conoco’s case, the knowledge of the Ardalin geographic area was necessary to build a feasibility study for a start-up process and this was obtainable via the achievement and experience of the AGD. It was established that proximity to pipelines was favourable and so also was access to export facilities. This was enough to encourage Conoco to enter into a joint venture with AGD. 2. 10. 3Contractual Terms The basic terms of the Joint Venture provided that partners share investment costs and profits based on participating interest in the venture.

The proposed structure to be adopted by the venture was to stem up from intense negotiation and discussions as partners had decided earlier not to adopt any existing model structure. As a result of this, fundamental issues regarding mutuality, cooperation and commercial agreements were built from the scratch. 2. 10. 4Venture Related Risks Political Risk: This was tackled from the inception as there was encouragement from both governments (i. e. US government for Conoco and the Russian government). The presidents at the time; Boris Yeltson (Russia) and Bill Clinton (US) at a 1993 summit held discussions where the Polar lights venture was singled out for financial support and government backing. This

was actually in anticipation of the financial set back the venture was expected to experience. Financial Risk: With an investment cost of about $350milion - $400 million to bring the field to optimal production level, there was a need for a financial plan. The venture was faced with securing funds and making necessary arrangements for the project financing. Private financing by an international institution was opted for and this was complimented by the choice of the partners (Conoco and Russian partners) to participate in negotiating the risk requirements and providing necessary collaterals that were required by the financial institution after due support from their governments.

Environmental Risk: The presence of the Arctic Tundra (biological organism) was supposed to be a setback during the field development. The Tundra was always frozen in winter and spongy in summer, thus it was unable to support equipment and facilities required for petroleum operations. As a result, construction works were limited to winter months. Drilling rigs and equipment were built on earthen pads 6. 5feet - 10feet (i. e. 2-3 m) thick to protect the organism from weight and heat. The ability to manage their environmental setback was the effort of harnessing wealth of experience from the venture partners. Conoco contributed a high level of experience relative to safety procedures and respect for the environment.

The company also provided well trained geoscientists, engineers and the necessary technical support for the project. The Russians were willing partners in complimenting the standards of safety, environmental and operational conduct. Geological Risk: The venture had less to bother on the geological uncertainties of the oil field. This was as a result of AGD’s experience of the distribution of Russian natural resource (a leader in the industry) and the confirmation of significant discoveries prior to commencing the venture. To discount this knowledge and expertise, will require a whole new approach to the venture and might include a new exploration process to discover the commercial viability of the field.

Furthermore, a contact made by the management of Conoco and the Russian Ministry of Geology was a platform for information exchange and also to develop an understanding amongst participants of the venture including the local community. Fiscal, legal and legislative Risk: Conoco had mixed experiences under this agreement. For instance, as at the time the decision to invest was made by Conoco, the system had no export tax and just a few local and federal taxes. By the time the investment was initiated, there was an increase in export tax and creation of new taxes leading to over 200% increases in taxes paid per barrel of oil. These posed a lot of issues for the IOC and called for constant re-negotiation. 2. 10. 5Learning Highlights

Both partners brought to fore their knowledge and expertise thus, serving as a spring board for the successful execution of the venture. The structure, power sharing, international financing, and cooperation from the US and Russian government helped with developing and implementing the Joint venture agreements. ADG had a very good record exploration achievement in the region which was a relevant contribution to the JV while Conoco’s experience in the international petroleum development, projects and dealings with host government and natural oil companies complimented ADG’s effort. Stability of contract and good relationship are necessary to provide incentives for continuous investment in all international joint ventures.

Uncertainties change of laws, additional taxes, financial impositions and unilateral changes by host government are unacceptable risks to the private investor and results in inevitable failure of the venture. Boulus (2000) recommended that future Joint venture of this structure should be considered as precedents for both countries and its success should serve as incentives for other companies to invest in Russia. 2. 11CASE STUDY 2 ECUADOR ORIENTE BASIN BLOCK 16: AN EXPLORATION AND PRODUCTION JOINT VENTURE (Forrest, M. C. 2000) Learning Point: Considering above ground risk factors prior to exploration and production processes and the importance of factoring win-win fiscal and regulatory terms into joint venture agreements. 2. 11.

1Structure of the Joint Venture The exploration and development of Block 16 in the Ecuador Oriente basin was an initial partnership between, Conoco Corporation a US based international oil company, Maxus Energy also from Texas US and Petroecuador. Conoco was the initial operator from 1986 to 1991 before Yacimentos Petroliferos Federodes (YPF) an Argentinian oil company (the largest in South America at the time) took over in 1991 when the former backed out and sold its interest to its partner Maxus Energy. As at mid-1998 the field was producing 50,000 barrels of oil per day while total recoverable reserves was estimated to be 200 billion barrels of oil equivalent.

The main focus of this case study is on the development stage of operations because of the importance of having an insight to identify pertinent issues that makes exploration and production a success. Other issues will include government and partner relationships, the effect of NOCs fiscal terms on the contract and venture partners, commercial and economic issues, political risk and particularly environmental risks which was the supposed reason for Conoco’s withdrawal from the venture. 2. 11. 2Venture Related Risks Political/Fiscal risk: Ecuador suffered decades of military rule and political instability prior to achieving its democracy in 1979 but has witnessed peaceful transfers after that period. It has also benefited from relations with the US.

However, passing legislation in Ecuador was difficult particularly in election years due to party conflicts and fractionalization and had adversely affected potential reforms that could encourage investments in oil projects. Economic Risk: The 1980s were characterized by inflation, volatile oil prices and economic stagnations brought about by debt profile of various countries. The contribution to national GDP by the countries oil and gas resource had reduced due to political instability and inconsistent government policies while inflation figures were about 25% between 1994 and 1998. Financial risk:The venture’s main operator (Maxus) had an investment portfolio of production operations in the Gulf of Mexico, US and Indonesia and also some other relatively high risk exploration… ventures.

With outstanding dividend obligations and a highly geared capital structure, there was a need for new investment to aid cash flow generation and repayment of long term debt. Getting capital for the development project was not forthcoming and associate partner resorted to selling part of its assets in the gulf of Mexico. Environmental Risk: The country’s oil concession is dominantly situated in ecologically fragile Amazon rain forest and as such had a keen interest from the international community and Ecuadorian government. This necessitated including environmental safety and protection procedures in licenses and agreement. Geological risk:The oil from block 16 was heavy and highly viscous at 12-22O API gravity. This was as a result biodegrading activity, water washing and immature oil generation.

2. 11. 3Exploration and Production/Conoco Corporation’s Withdrawal After preparing a development plan and assessing the environmental implication of embarking on the development, Conoco withdraws from the project citing economic reasons. However, Donahue (1998) attributed the withdrawal to pressures from environmentalist. Maxus Energy Corporation, an existing partner, took over operations and a new venture was formed with the following structure; Maxus-35%, OPIC-31%, Nomeco-14% and other minority subsidiary partners at a total of 20%. This structure was arrived at after the first three partners had distributed Conoco’s share within themselves.

As an operator, Maxus reviewed the viability of the block 16 field and was faced with the following challenges which ideally should have discouraged development of the block or dissolved the venture: * The associated environmental risk (protecting the rainforest) * Ecuador’s political risk structure (unstable reform processes) * The sensitivity/volatility of oil prices relative to the project. * Maxus had no prior development experience in a rainforest neither did any of the new venture partners. * There was a high cost of production for low value heavy oil. Furthermore, the fiscal structure was such that an increase in production above the 50,000 barrels per day led to very marginal increase in Maxus profit. Also, the venture faced competition from Ecuadorian refineries concerning use of diesel fuel for its operations.

They had planned to build a topping plant to supply diesel to generators but had to stop because of the competition and compulsion to purchase from government at higher prices. This had a great effect on the project economics, thus confirming most of the reasons that were not in favour of the venture project. 2. 11. 4Economic, Financial and Political Set Backs. By June 1994, when production started in Block 16, reaching about 30,000 - 35,000 barrels of oil per day, the consortium had started experiencing the effects of the risks stated above. First, there was a 40% increase above budget in development cost traceable to the location of the field (i. e. use of helicopters), increased facilities cost and overheads.

Secondly oil price was lesser than anticipated thus reducing expected revenue and cash inflow. Furthermore, oil production was adversely affected by the limited capacity of the Ecuadorian pipeline. The implication of these unexpected setbacks was that sales revenues will be paid back to the joint venture under the cost recovery provision leaving the host government with no early revenue streams. Observing that the venture was not meeting Ecuador’s economic projections (the government had anticipated 15% of the profit), the government began questioning the future of the investments. This was a ‘no win’ situation for the government and the venture partners and only led to strained relationships.

Above all, the venture faced massive political pressure to review contractual agreements that will guarantee government increase its stake and thus, further worsen the already uneconomic project. Even the strained relationship had an effect on the staff who soon started finding ways out of the system. 2. 11. 5YPF South America Intervention YPF South America as part of its strategy to expand on its exploration and production portfolio acquired Maxus in 1995. During negotiation with the Ecuadorian government, YPF lost its president Pepe Estenssoro in a plane crash which stalled the discussion briefly prior to when Robert Monti took over in 1995. The following re-negotiations took place; 1.

Replacing the fiscal policy of cost recovery and service fee by royalty payments. This positively influenced the existing strained relationship and guaranteed government a share of revenue from production 2. The venture further reduced operating costs and adopted improved technology to bolster production reserves. 3. The employment of an indigenous country general manager compared to the past two GMs who were American expatriate engineers. This benefited the partners as the new GM used his Latin background to solidify government relations, discuss financial options with private companies and improve on corporate social responsibility. 2. 11. 6Learning Highlights

Above ground risk issues like government’s political process, ways of doing business including relationship with other existing oil companies and contractual agreements should be thoroughly analysed before an investor commits to any development project. This is to ensure that the potential contract is a mutually beneficial situation for both parties. Also the use of experienced staff and contractors is necessary while at the same time involving indigenous personnel in strategic job positions to effectively take advantage of local experience and knowledge. Finally it is advisable for the investing companies to include in their business plans, different scenarios and forecasts before implementing their development plan. This should include scenario analysis of expenditures, revenues and cash flows to reflect worst and best case outcomes.

2. 12CASE COMPARISM Both cases discussed the importance of considering risk factors in upstream development and the attitude of the venture partners at managing the risks. The first case adopted a proactive method by highlighting the risks and taking necessary steps to quell them. This included involving the respective heads of state, who were able to encourage financial support for the project. The environmental issues brought by the Arctic Tundra had affected construction in summer months, thus the investors factored the construction into the winter months after adopting a plan that will have little or no threat to the biological environment.

In the other case, ignorance of risk factors affected the venture and almost damaged the relationship between the investors and the government. Conoco was smart enough to identify that the project did not meet its economic (marketability of oil type) and environmental standards (development in the rainforest and proximity to the Yanusi National Park), thought it wise to withdraw their interest. Another obvious set back was the inexperience brought in by Maxus energy who at the time had not embarked on this type of project but yet acquired an operating interest in the venture. Furthermore, the economics of the project was very rigid and as such the unanticipated effect of cost changes, fiscal policies and oil prices negatively affected the viability of the project.

For the project to make a turn around, the partners had to improve their relationship with the host government and begin to adjust the economics of the project by reducing cost, improving reserves and developing a more dynamic development plan that will factor in worst and best case scenarios. This was exactly what YPF South America embarked upon after acquiring a controlling interest in the venture. CHAPTER 3DATA SPECIFICATION, METHODOLOGY AND MODELLING 3. 1INTRODUCTION The chapter draws on the previous two chapters to specify the hypothetical data required for modelling of the development of the 8 fields. Description and the underlying assumption for each parameter will accompany each specification. However the limitations of the assumptions will be discussed after the model to highlight potential shortcomings with the model specifications.

The fundamental structure of the model is the appraisal of 8 (4 on-shores and 4 off-shores) oil fields with general parameters and field specific parameters. Table 3. 1 Table 3. 1 3. 2GENERAL PARAMETERS Crude Oil Price:? 85. 50 was selected randomly between ? 80 and 100 as a base case price and assumed to apply throughout the life of the entire project. Inflation Rate: This is necessary to simplify our estimates in money of the day (MOD) terms and account for investment in real terms. 2% will indicate a relatively marginal increase and prevent exorbitant figures in future estimates. Tax Rate:This is a fairly common rate used as corporate tax in most countries. Depreciation Rate:Hypothetical figure which varies with company policy or host government’s cost recovery period.

Royalty Charge:Rate selected in line with the fact that most royalties are within 10% and 15%. It is applied at a fixed rate on output for the purpose of this investment. (See limitations for exception – sliding scale royalty) WACC:This will incorporate the risk profile of the investment company relative to its capital structure and the risk nature of similar upstream development projects. IOC (% share in JV):We assume that the investing JV Company in a bid to manage its investment in onshore and offshore projects has an investment policy of 50% to 60% participation in onshore project and 30% to 40% in offshore. This will help define the partners’ share of risks and rewards. This assumption is relevant to scenario 2 and 3.