Liquefied Natural Gas Projects Research Articles

Financing LNG Projects and the Role of Long-Term Sales-and-Purchase Agreements

The financing of infrastructures is a major topic in recent energy policy debates. Project finance, as a specialized form of debt finance, thereby has become a well-established financing tool. This paper contributes a qualitative and quantitative analysis of the determinants of the debt ratio in project finance, using data on 26 liquefied natural gas (LNG) export and import projects. We argue that lenders will make their decision on how much to lend dependent on the risk profile of the project. In this vein, a project’s off-take agreements serve as a security for financial contracts. We empirically show that the debt ratio of an LNG project decreases with increasing risks associated to future cash flows. Estimation results confirm that leverage increases with higher shares of a project’s capacity sold under long-term sales-and-purchase agreements, with a lower capital outlay of the project, and with a lower risk index of the country where the project is located.

A stage-gate integrated risk control system for LNG plant projects: Focusing on the design phase

Since plant facilities including liquefied natural gas (LNG) plants pose accident risks, most risk studies have been focusing on public security risks and safety requirement. However, design and construction of LNG plants are also vulnerable to considerable schedule delay and cost increase due to its distinct characteristics such as the monopolized FEEDs technology, low-temperature and high-pressure equipment, and a large number of concurrent activities and participants. Hence, it is imperative to develop an efficient risk management tool which could support contractors' risk analysis and control in the design and construction phase. This study proposes a stage-gate integrated risk control framework focusing on the design phase of international LNG plant projects. An improved process to identify and analyze risks using the source-event, risk path, and quantification using probability-impact-significance of coordination concept are incorporated. A total of 83 risk factors of the design phase are identified and their quantification, prioritization, mitigation and monitoring methods are proposed along a state-gate framework. An illustrative case application is conducted to a real LNG plant project and its distinct benefits to manage and control risks of LNG projects are validated. Applicability and usability of the framework is also tested. The proposed framework is expected to function as effective tools for minimizing the risk of LNG projects and maximizing the management capacity of practitioners.

The Northern Sea Route: Smooth Sailing Ahead?

Transit traffic on the Northern Sea Route (NSR) has increased considerably in the last few years, in relative terms. There is no clear pattern of transit cargo on the NSR and little indication that cargo owners or shipping companies have committed themselves to use of this sea route for the longer term. An important exception to this picture is the Yamal LNG (liquefied natural gas) project, which will be based on year-round use of the NSR. Administrative procedures have improved and escort fees have become competitive, but are not transparent. The future capacity of the icebreaker fleet is being questioned, and so is the need for icebreakers. Also, Russia lacks an integrated policy for the NSR.

Probabilistic Reserves Addition Within a Project

Summary The SPE-Petroleum Resources Management System (2007) (SPE-PRMS) is a project-based system in which the project definition and its treatment play key roles in the estimation and categorization of reserves and resources and their range of uncertainty. This is key to capturing the potential downside and upside of the project and the commercial opportunities that may exist. Wrongly defining the project may result in an improper ring-fencing of the elements that one must consider in reserves and resource estimation and in improper risk assessment, with potential for missed opportunities or failure as an outcome. The SPE-PRMS is clear on the type of aggregation that one can use within a field, a property, or a project, with probabilistic addition allowed within each of these entities. However, despite this clarity, and on the basis of information provided in 10-Ks, 20-Fs, and annual reports, most companies in the oil-and-gas industry have not yet adapted their methods to reflect these best practices in external disclosures. The technical literature has devoted significant effort to address technical and commercial issues in probabilistic reserves and resource estimation of a field or incremental activity (e.g., drilling wells). However, very little effort has been devoted to the proper definition of a “project,” its attributes, ring-fencing, uncertainty-assessment approaches for the fields within the project, and in the categorization and aggregation of reserves or resources within the project. Furthermore, downside project economics should capture the true project's downside (or the true P90 of the project) rather than an overly pessimistic estimate of its proved reserves calculated with arithmetic additions within the project. To describe a simple approach to a project's reserves estimates, this paper uses an actual liquefied-natural-gas (LNG) project and its reserves estimates, estimated by different companies, with the arithmetic aggregation approach and the probabilistic aggregation approach. This example highlights different interpretations of the existing standards and regulations among joint venture (project) partners within the same project. This paper also highlights the overall impact that the two types of proved-reserves-aggregation methods (arithmetic and probabilistic) may have. In the specific example presented in this paper, the difference between the two methods can account for up to 15% of the project's proved reserves. One can also use the approach described in other types of projects (e.g., a project with satellite developments by use of common facilities) or resources estimates (e.g., projects in contingent resources), to properly capture the downside risk and realistic upside, uncertainty ranges, and project business opportunities, truly reflecting the project's reasonable certainty at the P90 level. Gas projects are preferred to illustrate this approach. For gas-commitment purposes, many buyers require the LNG project's proved (P90) reserves to be independently certified before contractual commitments can be finalized. Underestimation of the project's true proved reserves may result in loss of opportunities and/or in an overly pessimistic assessment of the proved reserves not reflecting reasonable certainty. Requirements from regulatory bodies [e.g., NARA (SEC) 2009; ESMA 2011] and their linkages to reserves aggregation within a project are also addressed in this paper. In the project analyzed, this underestimation is between 12 and 15% of the project's proved reserves, depending on the year of disclosure.

An innovative method for project control in LNG project through 5D CAD: A case study

Abstract Current studies on 5D CAD have been limited to either description of concept or automatic generation of quantities. Few have attempted to explore the other capabilities of 5D CAD. Project cost control and schedule control are very important for successful project delivery, while existing studies on computer based project control tools have largely focused only on schedule control. This paper fills the gap by investigating the possibility of using 5D CAD for project cost and schedule control. Initiated by Woodside Energy Ltd, a prototype of a 5D CAD system has been developed specifically for Liquefied Natural Gas (LNG) industry. The system was tested with the project data of an example module from an LNG plant provided by Woodside Energy Ltd. The functions of the system include: visualization of schedule data and verification of cost in real time and facilitation of periodic planning and progress reporting. It is concluded that 5D CAD could be a very powerful project cost and progress control tool.

Technology Focus: Natural Gas Processing and Handling (April 2014)

Technology Focus In the next 20 years, there will be a large increase in global natural-gas demand, with an average growth rate [forecast by the International Energy Agency (IEA)] of more than 1.8% per year. The top two leading countries in rising gas demand are China (7% per year) and India (4.7% per year). There is plenty of gas worldwide. In November 2010, the IEA announced that the world’s ultimate gas recovery could be approximately 30,000 Tcf. That is twice the previous estimation from the same source made in 2009. That is primarily because of the success of shale-gas production in North America. Of the 30,000 Tcf of gas, proved gas reserves are slightly more than 6,600 Tcf, and 49% of that is located in Iran (18%), the Russian Federation (17.6%), and Qatar (13.4%). The US is the largest natural-gas producer and consumer. It produced approximately 24 Tcf and consumed 25.4 Tcf in 2012, while Russia produced much more gas than it consumed (20.9 and 14.7 Tcf, respectively). On the other hand, many countries, such as China, Japan, South Korea, Mexico, the United Kingdom, and Germany, use much more gas than they can produce, and some of them do not produce any. That leads to one of the remaining challenges in natural-gas use: natural-gas processing and handling. Currently, 68% of the world’s gas is transported by pipeline (primarily on land) and 32% as liquefied natural gas (LNG). The top three LNG exporters are Qatar, Malaysia, and Australia. Because of relatively recent new offshore gas discoveries, Cyprus, Israel, and Mozambique are expected to be new players in the LNG market, along with the United States because of its success in shale gas production. Some of them might consider building floating LNG (FLNG) terminals. To find out the market context for LNG projects that will come to market beyond 2020 and how FLNG could fit in that marketplace, attend the SPE Floating LNG workshop in Perth, Australia, 18–21 May 2014. Although the countries mentioned most likely will export their gas as LNG, compressed natural gas (CNG) could be an interim solution, especially with the new generation of CNG containers made with composite material. A composite container may have as little as 40% of the weight of a metal container with the same capacity. Composite containers are also stronger than steel containers, with high damage tolerance and fire resistance. GTL technology can provide liquid fuels for transportation and can also reduce gas volume by a factor of 600 or higher, depending on the final products. Because of the large capital investments involved and the physical size of the process, currently only a small portion of natural gas is converted to liquids through GTL methods. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 16495 The Role of Underground Storage in Large Natural-Gas-Production Operation by Merry Hoagie, Santos, et al. OTC 24205 Stranded-Gas Field Development With Cluster LNG Technology by JungHan Lee, LNG Solutions, et al. IPTC 16489 An Integrated Model for Selecting the Best Fuel To Develop in the Value Chain of Natural Gas by Ahmad Mousaei, RIPI, et al.

JX Nippon: The New Mission

Hironori Wasada, senior vice president of JX Nippon Oil & Gas Exploration, highlights the ambitions and challenges facing the domestic and international operations of his company. What is the current status of the oil and gas industry in Japan? Japan imports almost 99.6% of its oil requirements, as we produce only 14,000 BOPD, which is less than 0.4% of our consumption. For gas, Japan produces about 3% of its consumption, with 97% of our consumption imported in the form of liquefied natural gas (LNG). The country is trying to reduce its energy export reliance, and the Japanese government is assisting and encouraging local companies to search for oil and gas offshore. Onshore fields in Japan are old and have started depleting, and recently a Japanese firm made a trial production of shale oil from an onshore oil field. In addition, the government is looking for alternative energy resources to meet growing local demand, and is currently looking at the commerciality of offshore methane hydrates. Also, several companies recently have been listed on the local stock exchange, which has put the industry under the scrutiny of investors who expect it to deliver revenue. Who are the major shareholders of JX Nippon? What major projects are you currently involved in? JX Nippon Oil & Gas Exploration Corporation is a business unit of JX Group, and is engaged in oil and gas development all over the world. We are very active in Japan, where development of local energy resources is the mission of Japanese companies. We are committed to continuing exploration activities in Japan, with the aim of contributing to a stable supply of energy. Currently, we are involved in exploration activities offshore Japan, and this includes the Sanriku and offshore Erimo blocks. Also, we hold a 100% interest in offshore blocks Shikoku, Nishi-kyushu, Sado, and Toyama Bay. The onshore Nakajo oil and gas field in Niigata Prefecture, Japan, is the domestic E&P base of JX Group. Our mission in the Nakajo field is to steadily supply natural gas to customers, including industries and local communities. How about investment outside Japan? NOEX (JX Nippon) currently operates in 14 countries. We are leading projects as operators in crude oil production in Vietnam, natural gas production in Malaysia, and exploration in the UK North Sea. We have also been part of a consortium producing oil in the United Arab Emirates (UAE) for more than 30 years. We are very active in several Asian countries, including Thailand, Myanmar, Vietnam, Indonesia, and East Timor. In Thailand, we will apply our own experience and technologies acquired through our operations in Vietnam to improve the efficiency of crude oil production at the Nang Nuan oil field in Block B6/27, where we hold a 40% interest with PTTEP Siam, the operator with a 60% interest in the field. In Vietnam, we are involved in Block 15-2, Block 05-1 b/c, and Block 16-2, while in Myanmar, we hold interests in Blocks M12, 13, and 14 and Block M11. We are also involved in LNG projects, including the Tangguh LNG project in Indonesia, and Papua New Guinea’s first LNG project, which is set to deliver its first LNG cargo in 2014.

Risky Business: The Issue of Timing, Entry and Performance in the Asia-Pacific LNG Market

Canada’s federal government has championed the prospect of exporting liquefied natural gas (LNG) to overseas markets. The government of British Columbia is aggressively planning to turn itself into a global LNG-export hub, and the prospect for Canadian LNG exports is positive. However, there are market and political uncertainties that must be overcome in a relatively short period of time if Canada is to become a natural gas exporter to a country other than the United States. This report assesses the feasibility of Canadian exports and examines the policy challenges involved in making the opportunity a reality.Demand for natural gas in the Asia-Pacific region is forecast to grow over 60 per cent by 2025. LNG trade is expected to make up nearly two-thirds of global natural gas trade by 2035. Supply in the Asia-Pacific region is limited, requiring significant LNG imports with corresponding infrastructure investment. This results in substantial price differentials between North America and the Asia-Pacific countries, creating a potentially lucrative opportunity for Canada.The lower North American prices are a reflection of the fact that there is a surplus of gas on this continent. Canada’s shipments to its sole export market, the United States, are shrinking in the face of vast increases in American production of shale and tight gas. Canada has a surplus of natural gas and there is growing demand in the Asia-Pacific region. Proponents argue that all Canada needs to do is build and supply facilities to liquefy gas and ship it across the Pacific; thereality is not so simple.Timing is one of the key challenges Canada faces. Producers around the world — including in the newly gas-rich U.S. — are racing to lock up market-share in the Asia-Pacific region, in many cases much more aggressively than Canada. While this market is robust and growing, the nature of the contracts for delivery will favour actors that are earliest in the queue; margins for those arriving late will be slimmer and less certain over time. As supply grows, so too does the likelihood of falling gas prices in the Asia-Pacific region, making later projects less lucrative. LNG projects are feasible only on the basis of long-term contracts; once a piece of market share is acquired, it could be decades before it becomes available again. Currently, there are more proposed LNG-export projects around the world than will be required to meet projected demand for the foreseeable future.Delays beyond 2024 risk complete competitive loss of market entry for Canadian companies. B.C. is behind schedule on the government’s goal of having a single terminal operational by 2015. Of equal concern is the lack of policy and regulatory co-ordination, with disagreements between governments over standards, process and compensation for those stakeholders involved in the potential LNG industry. Issues as basic as taxing and royalty charges for gas shipments between provinces and locating facilities and marine-safety standards remain unsettled in Canada. The B.C. government has announced plans to levy special taxes on LNG, a policy that could render many current proposals uncompetitive. The LNG market is much more complicated than current discussions suggest; this report delves into every aspect relevant for Canada as a potential exporter. The prospect for Canada expanding into the Asia-Pacific market is entirely viable. Canada has almost everything going for it: political stability, free-market principles, immense resources, extensive infrastructure and industry experience. Everything, that is, except a coordinated regulatory and policy regime. Withoutthat, Canada could be shut out, stuck relying on a single U.S. gas-export market that, increasingly, does not need us.

Pakistan's overall energy potential assessment, comparison of LNG, TAPI and IPI gas projects

Abstract Pakistan is facing severe energy crisis in spite of the fact that nature has blessed her with huge energy potential. Short fall of electricity supply in the country is increasing and has been recorded up to 4522 MW in 2010. This deficit reached to 7000 MW in May, 2011. A comprehensive review of Pakistan's energy sector is presented in this paper. Energy potential, major issues of energy sector and energy import options are discussed. Issues like poor management, combined cycle capacity, low hydro power share, circular debt and energy security have been covered. Energy potential assessment includes hydro solar, wind, coal, nuclear, hydrogen cells, geo-thermal, ocean resources and bio mass. Future prediction calculations are based upon country's current and world's average per capita energy consumption. Current oil and gas reserves of the country contribute to only 5 percent and 48.8 percent of the energy mix and at the current rate will be exhausted by 13 and 16 years respectively. The overwhelming dependence of the energy sector on imported fossil fuels may create a situation of energy security threat. However dependence upon the energy import options cannot be avoided in order to lessen the severity of energy crisis in near future. Some of the energy import options are: Turkmanistan, Afghanistan, Pakistan and India (TAPI); Iran, Pakistan and India (IPI) gas pipelines; Liquefied Natural Gas (LNG) from Qatar etc. On the other hand exploitation of vast renewable potential like hydro, solar and wind requires serious attention. Exploitation of indigenous coal resources would also be a key for solving energy crisis in the long run. In summary, this paper presents energy potential assessment in context of major issues, future predictions and impact of energy import options. This in turn provides a big, clear and brighter picture of the country's energy sector.

Australian LNG: pathways to productivity

Liquefied natural gas (LNG) has been one of the largest capital investment drivers in Australia, adding billions of dollars in government revenue, and creating thousands of jobs through various channels. ~50 mtpa of new LNG capacity will be added in Australia by 2017 and another ~50 mtpa of LNG capacity is on the drawing board that needs buyer and investor support for development. However, Australia is at risk of losing a large share of these future LNG projects to lower-cost exporters such as East Africa, North America etc. McKinsey’s ‘Pathways towards Australian LNG productivity’ report highlights which pathways can be followed to make Australian LNG projects competitive and how government, industry and operators can work together to get there.

Sustainable Energy Growth Tops Middle East Conference Agenda

Conference review The 15th annual Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), organized in the capital of the United Arab Emirates, attracted major national and international oil and gas companies from around the world to discuss common challenges and the opportunities in the region. Involvement from Middle Eastern countries was higher than ever at the conference, with delegations from Saudi Aramco, Qatar Petroleum, Kuwait Petroleum, Sonatrach, and many other international companies discussing their strategies and technologies. The largest oil and gas show outside North America were held under the theme “Sustainable Energy Growth: People, Responsibility and Innovation.” More than 50,000 people from 91 countries attended. SPE organized the conference and technical sessions, which covered a number of topics that influence the industry including technical, economic, personal skills, and capability issues. More than 50 technical sessions presented by 300 industry experts were delivered during the event. Mohamed Bin Dha’en Al Hamli, UAE minister of energy, opened the ADIPEC conference. He said the scale of ADI-PEC and its setting in Abu Dhabi made it an ideal platform to address the complex technical and logistical challenges of exploring for and producing oil and gas at a time of increasing global energy demand. Formally introducing the conference, Ali Rashid Al Jarwan, chief executive officer of Abu Dhabi Marine Operating Company (Adma-Opco) and chairman of the ADIPEC 2012 conference, said the itinerary was the most comprehensive to date. “This year, the event offered more depth and scope than ever before. ADIPEC was founded on the principle of sharing knowledge and experience. This principle is as relevant now as it was 25 years ago when ADIPEC was established,” he said. Speaking on the challenges of growing global energy demand, Christophe de Margerie, chief executive officer of Total, said that demand for oil and gas from non-OECD countries has increased and this creates a challenge. “Meeting the increasing demand is a bit challenging due to projects’ complexity, access to finance, and geopolitical constraints,” de Margerie said. “To meet this soaring demand, new LNG (liquefied natural gas) projects are needed to satisfy European and Asian demand, even with potential additional supply from shale gas.” To address the new challenges facing the industry, companies should focus on leveraging technology, he said. “This will help unlock resources and improve recovery, optimal development through innovation, as well as operational excellence,” he said. Sami Al Rushaid, chairman and managing director of Kuwait Oil Company, said that his company is strongly focusing on optimizing recovery through primary, secondary, unconventional, enhanced oil recovery (EOR), and development of heavy oil. “Significant oil is also expected to come from exploration activities,” he said.

Large neighborhood search for LNG inventory routing

Liquefied Natural Gas (LNG) is steadily becoming a common mode for commercializing natural gas. Due to the capital intensive nature of LNG projects, the optimal design of LNG supply chains is extremely important from a profitability perspective. Motivated by the need for a model that can assist in the design analysis of LNG supply chains, we address an LNG inventory routing problem where optimized ship schedules have to be developed for an LNG project. In this paper, we present an arc-flow formulation based on the MIP model of Song and Furman (Comput. Oper. Res., 2010). We also present a set of construction and improvement heuristics to solve this model efficiently. The heuristics are evaluated based on a set of realistic test instances that are very large relative to the problem instances seen in recent literature related to this problem. Extensive computational results indicate that the proposed methods are computationally efficient in finding optimal or near optimal solutions and are substantially faster than state-of-the-art commercial optimization software.

Social-Performance Indicators and Maintaining Corporate Social Responsibility

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152353, ’Developing Social-Performance Indicators and Maintaining Corporate Social Responsibility in a Developing Country During Construction and Operation of an LNG Plant,’ by Jeanette Rascher and AbdulSalam Al-Shamsi, Yemen LNG Company, prepared for the 2012 SPE Middle East Health, Safety, Security, and Environment Conference and Exhibition, Abu Dhabi, 2-4 April. The paper has not been peer reviewed. Maintaining corporate social responsibility is vital in securing a stable operating environment. The selection of social key performance indicators is crucial to promote long-term strategic goals, set targets, track performance, proactively identify triggers for change, and drive future improvement in performance. A range of indicators was developed to support the ongoing monitoring and evaluation of the company’s social-management plan, including community investment projects, livelihood restoration, reinstatement, and the effectiveness of community engagement within the project area. Introduction Indicators are used to track process and progress, and to determine whether the social component is making a positive difference (maximizing beneficial project effects) or minimizing risk (mitigating or reducing the negative effects of project activities as far as practicable). A monitoring and evaluation system was established as a tool to ensure that the company would achieve the goals and objectives set in its social-management plan and that the project design and criteria were followed, implementation effects occurred as predicted, emerging or unanticipated issues and projects were managed efficiently and effectively, lender and social-performance review requirements were complied with, international best practice was followed, national legislation was adhered to, and human development and capacity building occurred. Project Background A project was launched in August 2005 to design, construct, and operate a liquefied-natural-gas (LNG) plant on the southern coastline of Yemen, with an associated land pipeline to market and export the LNG, as shown in Fig. 1. Primary stake-holders included project-affected people (PAP), local and central government and governmental agencies involved with and exposed to project activities, and project employees. In terms of the LNG project, PAP are defined as communities, households, and individuals who live in close proximity to the project site. There were 22 clearly defined villages within a 5-km corridor on either side of the pipeline right of way and seven in the vicinity of the Balhaf liquefaction plant. Within each of these 29 villages (with their sub-villages), there are highly complex and potentially volatile household and tribal structures based on social, cultural, and religious norms founded in the community over many generations and which determine authority, respect, and status within the community. It is common for many families, relatives, and individuals to reside within a single household in a single village or community. Secondary stakeholders included those who have links (e.g., technical expertise) with primary stakeholders. Secondary stakeholders include nongovernmental organizations, various intermediary or representative organizations, and technical and professional bodies, often representing public interests.

2012 offshore petroleum exploration acreage release

Australia has abundant natural gas reserves and is experiencing a rapid expansion of its liquefied natural gas (LNG) production capacity. In 2011 alone, four Australian LNG projects received final investment decisions (FIDs) and another FID was made in the first weeks of 2012. These projects will add more than 33 million tonnes of new LNG capacity, represent more than $100 billion in investment, and will see Australia become the world’s second largest LNG exporter by 2015. These projects are underpinned by Australia’s stable economic environment and our effective and efficient legislative regime that provides the industry the confidence to pursue a variety of investment opportunities. The essential first step covered by this regime is exploration, which is supported by Australia’s annual Offshore Petroleum Exploration Acreage Release. Prepared by the Department of Resources, Energy and Tourism and Geoscience Australia, the annual Acreage Release is the key mechanism used by the Australian Government to encourage investment in petroleum exploration. The 2012 Acreage Release areas have been carefully selected to offer the global petroleum exploration industry a variety of investment opportunities. Areas vary in size, level of existing geological knowledge, and are located in a range of water depths. Selected areas are supported by pre-competitive geological and geophysical data and analysis undertaken by Geoscience Australia. The detailed Acreage Release information package is available at online at www.petroleum-acreage.gov.au or by visiting the Commonwealth Government’s booth at the APPEA conference.

Fire and Explosion Risk Analysis and Evaluation for LNG Ships

Liquefied natural gas(LNG) has large fire and explosion hazard and China's imports of LNG by sea will present rapid growth in the next decade. Analyses were made for the fire fatalness of LNG ships. The risk evaluations of fire and explosion in the LNG ship were made at a different angle by use of the Dow method, BLEVE model and VCE model. The clear, accurate, comprehensive evaluation findings were obtained, in which the fire and explosion hazard index F&EI is 168 and the degree of risk is ‘very large’ before the security measure compensations, but after security measure compensations, fire and explosion risk index F&EI falls and the degree of risk is reduced,. The results could be applied as references to the scientific management and the adoption of safety measures for the shipping enterprises that plan and participate actively to import LNG project.

The Impact of Qatar's Investment and Fiscal Policies on its Gas and LNG Success

Abstract 1. Introduction: Qatar currently produces 77 mtpa of Liquefied Natural Gas (LNG), which dwarfs the 24 mtpa production of 2nd placed Indonesia. Production started as recently as 1997, compared to the several decades that other LNG producers have been in operation. This paper will review the key policy factors that have been responsible for Qatar's success story including leadership vision, efficient utilization of International Oil Companies’ (IOCs) expertise and technology, and a conducive hydrocarbons policy. 2. Qatar-Country Brief GDP trend, population 3. Qatar National Vision (QNV): Impact on the Energy Sector The QNV envisages that Qatar's hydrocarbon resources would be subject to cautious development in order to safeguard the interest of future generations, and there would be greater focus on non-hydrocarbon industries. 4. Hydrocarbon Legislation The Permanent Constitution of Qatar establishes the state's sovereignty over the ownership of its resources. 5. Qatar's Gas and LNG Sector Figures: * Qatar LNG Projects, 1997-2011 * Global LNG production by country * Qatar LNG production trend 6. Analysis of Development & Fiscal Agreements (DFAs) and Production Sharing Agreements (EPSAs/DPSAs) The DFA is joint venture between Qatar Petroleum and an IOC. Most LNG (and gas) agreements are structured as such, due to the strategic nature of Qatar's gas sector and the gigantic North Field, as well as the sophisticated liquefaction technology involved in LNG projects. The two main LNG joint ventures are RasGas and Qatargas. Most of the country's oil contracts have been awarded on the EPSA and DPSA basis, which do not have any state equity participation unlike the gas DFAs. These allow for exclusive grant of rights to explore and produce petroleum. 8. Conclusion:Qatar has kept a stable and prospective hydrocarbon regime that has attracted investors. The state wisely diversified its partnerships to include capable oil majors to spread the risks and to create a better bargaining position when negotiating fiscal terms, and preferred long-term Sale & Purchase Agreements with customers to safeguard future revenues. Through careful collaboration with IOCs and balanced bilateral contracts, the focus was on a win-win scenario for the investor and the government.

LNG for Petroleum Engineers

Summary While remote parts of the world are awash with hundreds of trillions of cubic feet (Tcf) of natural gas, the industrialized West and emerging economies of the East cannot get enough of the clean-burning, environmentally friendly fuel. The problem is transporting this compressible fluid long distances and across major bodies of water. For markets more than 1,500 miles distant, liquefied natural gas (LNG) has proved to be the most economic option. By refrigerating natural gas (primarily methane) to–260°F (–162°C), thereby shrinking its volume by 600:1, natural gas in the form of LNG can be transported in large insulated cryogenic tankers at a reasonable cost. Natural-gas liquefaction is a series of refrigeration systems similar to home air-conditioning (AC) systems, consisting of a compressor, condenser, and evaporator to chill and condense the gas. The difference is in the scale and magnitude of the refrigeration. A typical single-train LNG plant may cost USD 1.5 billion and consume 6 to 8% of the inlet gas as fuel. Because many of the impurities (e.g., water vapor, carbon dioxide, hydrogen sulfide) and heavier hydrocarbon compounds in natural gas would freeze at LNG temperatures, they must first be removed and disposed of or marketed as separate products. This paper will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading. However, the focus is on the liquefaction process and equipment. Differences among the commercially available liquefaction processes (e.g., cascade, single mixed refrigerant, propane precooled mixed refrigerant, double-mixed refrigerant, nitrogen) will be discussed. The aim is to provide SPE members with a clear understanding of the technologies, equipment, and process choices required for a successful LNG project.

Comments: Positive Forecasts

Editor's column Higher oil prices, continued enthusiasm over shale, and the influx of capital are combining to paint a bright picture for the oil and gas industry this year. Both operators and the service sector appear optimistic for growth opportunities—despite some uncertainty surrounding offshore drilling—as the industry quickly rebounds from recession. The Original E&P Spending Survey by Barclays Capital forecasts that global E&P spending will increase 11% this year, from USD 442 billion in 2010 to USD 490 billion in 2011. The survey is based on information from 402 international oil companies, national oil companies, and independents. The outlook for spending in Latin America, the Middle East and North Africa, and Southeast Asia appears particularly bright. International oil companies will post the largest increases in spending, says the study, a reversal from previous years when national oil companies led spending increases. BP, Chevron, ConocoPhillips, ExxonMobil, Shell, and Total are expected to boost expenditures by 18% in the aggregate. Factors driving the increased spending by operators include engineering and construction spending for several large liquefied natural gas projects, increased spending in Iraq, and an increase in deepwater activity, the report said. A recent Wood Mackenzie analysis reported that global upstream capital spending for 2010 would hit USD 380 billion and that many regions and sectors of the upstream industry are regaining confidence. Spending last year was about USD 19 billion higher than in 2009 but 10% lower than 2008. The Wood Mackenzie report said it expects spending to continue to increase in the short term and recover to 2008 levels by 2012 or 2013. The industry’s recovery is largely being led by spending on developing unconventional resources such as shale, the report said. Although most of the spending to date has been in developing US shale plays, operators are increasingly eyeing opportunities in Eastern Europe and elsewhere. Also boosting recovery is the influx of capital. More than half of chief financial officers (CFOs) in the oil and gas industry report that their companies’ ability to access capital and credit is either the same or better than it was a year ago, according to a study by BDO USA, an accounting and consulting organization. That renewed access to capital is allowing companies to aggressively pursue the acquisition of new properties, technologies, and other companies. In addition, 95% of the CFOs surveyed expect to maintain or increase the number of personnel employed by their companies this year. The oilfield services sector also appears healthy. The annual IHS Herold Review of the Oil Field Services Sector reported that key oil company financial performance for service companies by late last year had greatly improved, including for Baker Hughes, Halliburton, and Schlumberger as well as for offshore drilling contractors Transocean, Diamond Offshore, and Oceaneering International, among others.

Designing a decision support model for the LNG market

As the Liquefied Natural Gas (LNG) market is supply-driven and subject to long-term contracts, both liquefaction companies and shipowners need to make strategic decisions on fleet chartering requirements. These planning decisions become ever more difficult in light of the transformations permeating the LNG market, propelling into a more competitive market with more flexible trades and expanding spot markets. The overcapacity of LNG ships during 2008–2009 triggered by massive overcontracting is a good case in point where the use of decision support models would have been beneficial, especially considering the fortunes and risks at stake. In this paper we present an LNG shipping model that effectively supports decision-making in practice. To demonstrate the value added of the model, we study the implications of LNG project delays and increased decommissioning of ships with respect to market balance and fleet requirements.

What’s Different about Floating LNG? A Legal and Commercial Perspective

Liquefied natural gas (LNG) is of clear strategic importance to many countries. Floating LNG (FLNG) represents an opportunity, in the case of liquefaction, to develop marginal gas fields and, generally, to match supply and demand as never before. However, the advent of FLNG project developments will inevitably bring with it a unique set of technical, commercial and regulatory challenges. Lawyers will have a large part to play in ensuring that these challenges are adequately addressed, assisting project sponsors in securing the requisite permits and approvals under existing applicable national and international regulatory frameworks or helping to negotiate appropriate regulatory frameworks in jurisdictions where the existing framework does not cater for the peculiarities of FLNG. This article surveys some key legal and commercial issues in the structuring of the FLNG projects by comparison with onshore LNG projects and includes a case study on Indonesia.