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Natural gas and LNG trade­ a global perspective

In 2004, Sasol started piping natural gas from Mozambique
Temane field to the company's Sasolburg and Secunda sit

Indonesia's Declining Output
Shell Russia LNG to Japan's Chubu Electric
Regional Natural Gas Reserves 2004
Gas_Production_2004 Shell Makes New Sakhalin II LNG Supply Deal
New Liquefaction projects  2005 Outlook for US LNG Location of China's new LNG terminals
Mexico U.S. Canada Strengthen Energy Secto
Rhode Island Law Bans LNG State Waters Traffic
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LNG exports

Trinidad and Tobago Algeria
Egypt Nigeria


Iberian Peninsula
Cheniere Gets OK for Louisiana Facility Portugal Spain
France Japan

South Korea India

Outlook for US LNG

Natural gas and LNG trade­ a global perspective
New dynamics within the gas industry will accelerate its ability to eclipse oil as the premier fuel of the world economy

Oil prices have been very volatile on the upside. However, oil prices are nothing compared to the natural gas (NG) price roller coaster. Why is NG now selling for about $7/million Btu (or Mcf, 1,000 cubic ft) when just a few weeks ago it was over $16? Given the short supply caused in part by hurricanes in the Gulf of Mexico and strong demand, some analysts were convinced that the $20 NG would be common on the US East Coast no later than Christmas Eve 2005. Of course, that didn't happen. Blame or credit warmer weather, NG prices fell.

So what are the forces in play here? We believe that price is no longer the defining issue for the NG market. Supply is. And supply issues are causing major price fluctuations. Even small sup­ply-side changes-excess gas or a shortage of gas, real or perceived by as little as 0.5%-are being amplified by the market. This is a function of the cost of bringing new NG supplies online, espe­cially the real intractability of existing sources. Market psychology, perhaps irrational in either direction, has taken over.

Four years ago, we calculated the "equilibrium price" of NG for the US using data and full-cycle economic analyses. The calculation was done to find the required price for a company to get a return on its investment. We used "activation index" -how many dollars are required to deliver one Mcfd NG plus the observed production decline rates and the reported operating costs. For the US as a whole, the average equilibrium price was about $2.50, but such average pricing is of little use because local equilibrium prices ranged from $l/Mcf to $4.75/Mcf.

Calculating the national equilibrium price is an enormous headache to gather the required data. Yet, the equilibrium price would probably not result in much difference in the price. This is why, four years ago, we said that if anybody can bring liquefied natural gas (LNG) in the US for $3.50/Mcf would find a very inviting market share. Several companies acted on this advice.

What about domestic production?

Nothing shows the maturity of the US oil and gas business than the hopelessness of substantially increasing domestic production no matter how much drilling is done and no matter how much politicians exhort the vir­tues of "energy independence." Maturity in petroleum production implies several factors in a combination of one, two or all three fac­tors: reservoir pressure decline, water influx into the production zone or exploitation of less and less geologically attractive zones. Simply  stated, it takes 200 to 250 successful oil wells in the continental US to equal the production of one average Saudi Arabian well.

For NG, the situation is actually equally bleak if not worse. For the last four years, the number of rigs drilling for gas increased from a little less than 700 to almost 1 ,200-a 70% increase. And yet, NG production has remained flat to slightly declining.

The geological and physical requirements for increased produc­tion are simply no longer there. The increase in drilling activity, fueled by the recent unprecedented NG price increases, is barely slowing down the inevitable decline of domestic production.

So what does this mean for gas users and investors? Get used to volatility. Now that NG prices are declining, we believe they could fall yet further. But don't be surprised if NG prices increase to $16+ if we have a hot summer and/ or a cold winter. This volatility will continue until the US begins receiving on a regular daily doses-several billion cubic feet (Bcf)-of LNG. Importing LNG is the only answer to US' predicament but the solution is at least two years away.

US is not alone on NG issues.

The UK, the world's other major deregulated gas market, is experiencing similar problems­declining domestic production and how to secure supply in advance of completion of major import facilities.

Likewise, the UK is also experiencing highly volatile NG prices driven by winter supply (or lack of it), with more substantial seasonal swing than in the US. The forward price curves for NG in the UK and US suggest such price volatility will persist, at least until 2008 when new LNG (and pipeline in the case of the UK) import facilities become functional (Fig. 1).
In 2006, the security of LNG supplies over pipeline supplies from third-party countries was highlighted by two events in Europe:
• Ukraine and Russia disputes in January 2006 led to brief cuts in Russian supplies to continental Europe.
• Inability of the Interconnector (Bacton to Zeebrugge) pipeline connecting UK with mainland Europe to respond to market forces and supply gas shortfalls in the UK's deregulated market at premium prices with gas from substantially regulated markets of continental Europe in spite of pipeline capacity being available.

The latter issue has caused several NG price spikes in UK between October 2005 and March 2006. Price spike in March were made worse by a fire in the UK's largest gas storage reservoir (Centrica's Rough field), taking the facility offline for several months. On March 13,2006, UK NG prices at the National Balancing Point (NBP) rose from 60 pence/therm (~$10.5/MMBtu) to 200 penceltherm (~$35/MMBtu) across the day. With the new LNG receiving terminals and direct pipelines from Norway (2008), the UK's dependence on controlled continental European gas market behaviors will become less important.

State of NG
NG is the world's second largest source of primary energy. It accounts for about 23% the total world energy demand, currently estimated at 450 quads (quadrillion Btu). By coincidence, one quad is also very near one trillion cubic feet (Tcf). Thus, the world consumes approximately 100 Tcf ofNG. In addition, NG also provides about 23% of the US' energy consumption, which is about 105 quads.

NG is the cleanest burning fossil fuel and produces less emissions and pollutants than crude oil or coal. Since the early 1970s, NG world reserves have steadily increased at an annual rate of 5%. Similarly, the number of countries with known reserves has also increased from around 40 in 1960 to about 85 presently.

While NG abounds throughout the world, facilities to receive and distribute this product to market are limited. These facilities include pipelines across land masses and LNG transports across the oceans. Once new LNG facilities come online in the US, starting in late 2007 or early 2008, NG will undoubtedly emerge as the dominant fuel, first for power generation then, in the longer-term for transportation-a far more demanding energy transition.

Developing world
China and India are racing from the developing world to economic superpower status. But nations are using very different approaches. China is applying a manufacturing agenda; India is developing a services
approach. Together, China and India will usher in a broader and more powerful strain on globalization that will put more pressure on the developed world.

The rapid growth in China and India over the last few years is unprecedented, precipitating huge demand increases for all energy resources. Result: The rest of the world is scrambling for the same energy sources including NG. The US, with the largest and most pressing energy needs, is hampered by the myriad of permit approvals required for LNG siting.

Transportation is an essential aspect of the gas business, since NG reserves are often quite distant from consumer markets. NG is far more cumbersome than oil to transport, and most gas is transported by pipelines. There is a relatively well-developed network in the former USSR, Europe and North America. However, in its gaseous state, NG is quite bulky. A high-pressure pipeline can transmit only about a fifth of the amount of energy per day, which can be transmitted in an oil pipeline, even though gas travels much faster.

When gas is cooled to -160°C (-260°F), NG becomes liquid and is much more compact-occupying 1/600 of its gas volume. Where long overseas distances are involved, transporting NG in its liquid state is more economical. The LNG industty is set  for a large and sustained expansion as improved technology has reduced transportation costs of formerly stranded NG reserves as a liquid to consumer markets.

New Liquefaction projects in planning/development, 2005

Location of China's new LNG terminals
This shift of the dynamics for the NG market will further commoditize NG globally. 

LNG carriers are up to 1,000 ft long, and require a minimum water depth of 40 ft when fully loaded. The existing global fleet of LNG carriers in the first-quarter 2006 is 194 vessels with 11 million tons of LNG capacity. New building orders for LNG carriers are 120; thus, the future fleet will have 300 vessels before 2010. The fleet was just 90 vessels in 1995 and 127 vessels in 2000. The current fleet annually transports more than 120 million metric tons of LNG (converted to 6.5 Tcf), about 25% of world gas trade and 6.5% of total NG use.

LNG transport and trade
The need to transport NG across oceans has developed an international LNG trade, with major investment in infrastructure required to construct NG supply chains (Fig. 2). The first LNG shipments were made on a trial basis in the early 1960s between the US and UK. In addition, during 1964, startup of the first commercial-scale LNG project to ship LNG from Algeria to the UK occurred. Since then, LNG trade has grown steadily and has formed an increasing proportion of international trade. International LNG trade began in 1954. Its success led to the first commercial base-load international LNG project in 1964 between Algeria and the UK for a 15-year contract. This was followed by ventures between Algeria and France in 1965, and Alaska and Japan in 1969. 

Gas exports grew about 10 fold between 1966 and 1980. For exporting countries, flared gas in Abu Dhabi and Libya, or surplus NG, could be exported as LNG to generate foreign exchange. LNG projects provided an important option for developing countries with abundant, under-utilized NG reserves. Most of the global LNG supply comes from countries with large NG reserves. These countries include Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Nigeria, Oman, Qatar, and Trinidad and Tobago. Egypt is the latest nation joining the LNG exporters in 2005. In the near future, countries such as Norway and Russia, with the most impressive NG reserves, will join the league of LNG-exporting nations. In spite of holding large NG reserves, political instability continues to delay Iran and Venezuela from exporting significant gas either by pipeline or LNG. Recently, plans to construct new gas liquefaction plant have mushroomed around the world with many new countries entering this industry. 

Consuming countries are developing LNG infrastructure.
These nations are looking at LNG not just in terms of diversification and cleaner energy production (Fig. 3), but also because they are moving toward or already experiencing energy supply deficits. Therefore, LNG is attractive to many consuming nations:  o Those without significant reserves, seeking reduced oil dependence, such as Japan, South Korea and several European nations 

Those whose indigenous industries have hit or passed peak output, such as the US and UK, which have highly developed gas delivery infrastructures but are increasingly becoming net energy importers.

Developing economies that are energy hungry for fast domestic economic growth such as China and India. Both nations have underdeveloped delivery infrastructures but possess the potential for huge growth for end-users. 

China has dominated the world energy action over recent years and will become even more active in the future. China's oil majors-CNOOC, Sinopec and CNPC-have embraced LNG.
Currently, 18 LNG regasification facilities have either been announced or are under construction (Fig. 4). CNOOC   is Chinas leader in the LNG race. Chinas first LNG terminal in Guangzhou (a joint venture between CNOOC and BP) was scheduled to be online by mid-2006. This facility will receive the first LNG shipment with Australia as the originating country. China's second LNG terminal, also controlled by CNOOC, is located in the Fujian Province and is expected to be in operation by the end of 2007. A third regasification terminal is planned for the Zhenjiang Province. Given the rising LNG price in the global market, we expect several of Chinas LNG projects to be delayed. Some delays may become cancellations (Fig. 5). 

Chinas decision to sanction LNG receiving terminals in 2002 and 2003 were fortuitously timed in a buyer's market. China was able to secure excellent long-term prices for LNG (nearly $3/MMBtu). In the high oil and gas price environment that has evolved, sellers' price expectations have increased substantially. The latest round of regasification terminals being planned in China (and India) are struggling to reach price agreements with LNG suppliers. Indeed, some contracts signed in that LNG buyer's window of opportunity (2001 to 2003) are now under pressure from sellers to renegotiate the gas price upward. High prices are expected to slow down or even postpone several planned projects. 

There are 52 LNG receiving terminals located worldwide, primarily in Japan, South Korea and the US (as shown in Tables 1 and 2). Several European countries also import LNG. For countries that entered the LNG trade before 1973, imported gas prices were cheap, especially when compared to alternative resources. Between 1973 and 1979, LNG prices remained competitive, although they were increasingly linked to the prices of petroleum products. In countries with a serious pollution problem, LNG had a premium value as a cleaner fuel. For other importers, LNG provided an economic way of diversifying energy sources to improve the total security of supply. For both buyers as well as sellers, LNG became a proven means of supply, which was technically reliable and safe and also offered the most economic means of bringing large NG volumes to markets where delivery by pipeline was impractical.

In the 1970s, much larger projects were planned to exploit economies of scale in liquefaction and to meet growing energy demand. The first large-scale project was the Brunei exports project to Japan in 1972. LNG trade grew more rapidly than the gas-export market as a whole, and its share increased from 7% to 19% of total gas trade in 1982. However, in 1983, when the actual implementation of projects under construction began, international LNG trade virtually stopped growing. Some proposed projects-such as the ones from Iran to the US and Japan, and from Algeria and Nigeria to the US and Europe-were not carried out due to economic and political reasons. Some projects were cancelled, while others are waiting to be reactivated in either their original or a different form.
Currently, trade is concentrated in two main areas-the Pacific Rim and Atlantic Basin. In the medium term, LNG exporters will be more diverse than their gas reserves may suggest. LNG exporters, until 1999, were predominantly concentrated in the Pacific Basin, exporting to Japan and South Korea, for whom LNG comprised their national NG consumption. However, the exporting countries and destinations for LNG exports are expanding rapidly:  o LNG trains came onstream in Trinidad and Tobago, and     Malaysia in 2003.

Egypt joined the ranks of LNG exporters bringing the total number to 15, from 9 in 1997.
The Spanish Egyptian Gas Co.'s (SEGAS) LNG Source SP Statistical Review, June 2005 complex in Damietta came onstream in fourth- quarter 2004 and will export LNG to the Spanish market via a new receiving terminal at Sagunto, Spain.

Iran, which has the world's second largest NG reserves, has three projects underway. Combined capacity of the projects is approximately 24 million tpy, which is equivalent to 1.15 Tcf.  The entry of companies such as British Gas (BG) into the market and the re-emergence of the US market are reshaping the LNG/NG market. One change is the relationship between suppliers and buyers, the point of origin and the end-point of LNG shipments. Historically, one of the LNG buyers' principal concerns was supply security, particularly in the absence of alternative NG sources. Thus, many buyers developed a portfolio of long-term, relatively inflexible contracts with suppliers. In addition, some buyers used spot or short-term purchases to manage seasonal peaks, unexpected demand growth or shrinkage. However, changes in the global NG markets are forcing buyers to adopt flexible contracting strategies.

Buyers and sellers
Buyers do not want to get into a situation where they lose key customers to competitors and suffer a significantly reduced LNG requirement. At the same time, they do not want to be required to pay for volumes that they don't need under the take-or-pay provision of an inflexible, long-term supply contract. So, major buyers are increasingly using a balance of short-, medium- and long-term contracts as well as optional volumes to increase operational flexibility but maintain supply security.  Buyers are also using new types of indexing in contracts that link LNG purchase prices to factors other than oil price. In some cases, LNG price is linked to spot-market gas or coal prices in which these fuels are the main energy alternative. LNG buyers have expanded along the LNG value chain. They have become involved in shipping, trading, liquefaction and distribution. This strategic change is motivated by the buyers' need to develop greater operational flexibility for dealing with seasonality and price/volume risks. This relates to the need to diversify revenue streams and to take advantage of increased buying power in a market of potential excess supply.

Stranded gas
Globally, NG reserves are increasing. Commercialization of stranded gas is becoming important to both international operators and host governments. The potential supplies exceed 4,000 Tcf of gas currently discovered but, as yet, not contracted. While other gas monetization methods such as gas-to-liquids (GTLs) and compressed NG are becoming competitive, LNG is still the most prominent, feasible option for maximizing stranded gas values (Table 3). Thus, competition in LNG supply is growing.

A trend toward increased competitiveness has increased the economies of scale-from expansion of existing LNG receiving facilities to construction of larger liquefaction trains and ships. Higher materials and services costs and skilled manpower shortages in the LNG industry, due to the high demand, have put a slight damper on progress toward lower unit costs for facilities. However, few expect such challenges to seriously impact the growth of the LNG industry in the medium- and long-term.
In areas where significant, relatively low-cost gas resources are present, companies and governments will look at developing integrated complexes incorporating LNG, GTLs and other gas-monetization processes. Such complexes are now developed in Qatar and Equatorial Guinea. In addition, suppliers have identified the value of integration within the LNG value chain. Historically, suppliers focused attention on supplying customers and building relationships. Now, greater competition and market liquidity have increased the importance of proprietary LNG processes and improved margins at every point across the value chain. Companies, such as Shell, BP and BG, recognized that access to markets and the ability to control each part of the value chain would assist in monetizing reserves. It also would allow the flexibility required to exploit evolving opportunities. Other key players in LNG supply have followed their lead.
Although projects historically required a high proportion of long-term, off-take commitments before a final investment decision was made, a greater level of volume risk is now adopted by new supply projects. This risk can be traced partly to buyer need and partly to competitive effects. It is offset by the companies' ability to utilize their integrated positions to transport and place additional, uncontracted volumes.

The LNG industry continues to be supported by long-term agreements between suppliers and buyers. But there will be increasing market liquidity and increasingly integrated portfolios. A greater proportion of the market will be traded on shorter-term or more flexible arrangements because of the buyers' stronger market position.
LNG as a tradable commodity is emerging into a full-fledged financial complex, and will add to that complex by providing a physical arbitrage between different regional markets. While neither a political nor an environmental panacea, LNG offers a global commodity that can meet the greater demand for NG. The combination of secure energy supplies, higher NG prices, lower LNG production costs and rising NG imports with increasing demands for clean energy in developed and developing nations, and the desire of gas producers to monetize NG gas reserves, are setting the stage for increased LNG trade. Global LNG demand has grown from the first 260-Mcfd commercial LN G export in Arzew, Algeria, in the early 1960s to a forecasted demand of200 million tpy in 2008. This is equivalent to almost 11 Tcf of NG, more than 40,000 times the volume of that first trade. This demand is expected to exceed 500 million tpy by 2030 with the average plant sized at 5 million tpy.

To meet this demand, the LNG industry is rapidly expanding its export facilities. Until 2000, the trend was to increase the liquefaction train capacity to fully benefit from the economies of scale. Since 2000, the wider spread in train capacity ranging from 3 million tpy to 8 million tpy per train. High-capacity trains are the most economic when reserves are abundant and easy to produce. Projects with lower-capacity trains can also be economically attractive, if not all of these conditions are fulfilled
One obstacle is a possible short-term response from the strategists of the US and UK governments to respond to short-term gas price volatility and recent winter gas price spikes by sanctioning new nuclear-power plants on a massive scale. This would probably not dampen growth in the gas infrastructure developments in the medium term, but could have a long-term impact on the share gas ultimately takes in the primary energy mix. It is certainly in the interests of the gas industry to explain very clearly to government that price volatility is something that can be cured by investment within LNG infrastructure.

Outlook. The US and the UK have entered a new era of importing NG. China is about to join them. These new importers will provide a new dynamic to the NG industry that will accelerate its ability to eclipse oil as the premier fuel of the world economy.
Saeid Mokhatab is an advisor of natural gas engineering research projects in the Chemical and Petroleum Engineering Department of the University of Wyoming, as well as an international associate of David Wood & Associates in Lincoln, UK. His expertise lies in the area of design and operations of natural gas transmission pipelines and processing plants. He has participated as a senior consultant in several international gas-engineering projects, and has published more than 50 academic and industrial-oriented papers, reports and books. He served on the board of SPE London Section during 2003-6 and is currently a member of Offshore Technical Committee for Pipeline Systems Division (PSD) of ASME's International Petroleum Technology Institute, ASME/Offshore Technology Conference's General Program Committee, ASCE Pipeline Research Committee and SPE.

Michael J. Economides is a Professor at the Cullen College of Engineering, University of Houston, and the Managing Partner of a petroleum engineering and petroleum strategy consulting firm. His interests include petroleum production and petroleum management, a particular emphasis on natural gas, natural gas transportation, LNG, CNG and processing, advances in process design of very complex operations, economics and geopolitics. He is also the Editor-in-Chief of the Energy Tribune. Previously, he was the Samuel R. Noble Professor of Petroleum Engineering at Texas A&M University and served as Chief Scientist of the Global Petroleum Research Institute. Prior to joining the faculty at Texas A&M University, Professor Economides was the Director of the Institute of Drilling and Production at the Leoben Mining University in Austria. Before that, Dr. Economides worked in a variety of senior technical and managerial positions with a major petroleum services company. Publications include authoring or co-authoring of 11 professional textbooks and books, including The C%r Of ai/ and 200 journal papers and articles. Dr. Economides does a wide range of industrial consulting, including major retainers by national oil companies at the country level and by Fortune 500 companies. He has had professional activities in over 70 countries. In addition to his technical interests, he has written extensively in wide circulation media in a broad range of issues associated with energy, energy economics and geopolitical issues. He also appears regularly as a guest and expert commentator on national and international television programs.

David Wood is an international energy consultant specializing in the integration of technical, economic, risk and strategic information to aid portfolio evaluation and management decisions. He holds a PhD from Imperial College, London. Research and training concerning a wide range of energy related topics, including project contracts, economics, gas I LNG I GTL, portfolio and risk analysis are key parts of his work. He is based in Lincoln, UK but operates worldwide.
     World Gas Reserves  2004                                                            World Gas Production  2004

Natural gas is a hydrocarbon mixture primarily composed of methane with lesser amounts of other paraffin hydrocarbons, including ethane, propane and butanes. The value of natural gas lies in the combustion properties of methane, a key raw material for making solvents and other organic chemicals. Value is also derived from the hydrocarbon liquids that can be extracted from the gas.
Analysts at Nexant Chem Systems (www. have prepared a new overview of various gas sonditioning processes that identifies technologies, processes constraints and the market outlook. The following are highlights from Nexant's study ..
The two main ways of transporting natural gas are by gas pipelines and via low-temperature tankers in the form ofliquefied natural gas (LNG). In pipelines, gas is moved under pressure differentials. For onshore pipelines, 70 to 100 bars is a standard inlet pressure. For offshore pipelines, the pressure at the entry of the pipeline typically ranges from 100 to 150 bars, depending on the distance from the offshore facilities to the gas use r. During transportation, pressure drops will occur over long distances. Therefore, recompression stations are sometimes required.
In the form of LNG, natural gas is transported at a temperature close to its boiling point at atmospheric pressure, which is approximately -160°C. The gas is liquefied in a liquefaction plant. Before being liquefied, the gas must be treated:
  Table One
Typical LNG product
Product specs, cost transport stir natural gas markets
Maximum limit
3-3.5 ppmv
Total sulfur 30 mg/sm3
CO2 50 ppmv
0.01 mg/sm3
H20 Vapor
1 ppmv
1 ppmv
Pentanes and heavier`
0.1 mol%
Source: Nexant Chem Systems

Treatment specifications are more severe than in the case of pipeline transport, as it is necessary to avoid any risk of solid-phase formation during the liquefaction process. LNG is transported in a liquid state to overseas receiving terminals. At the reception terminal, LNG is re-gasified and sent to the distribution grid at the specified pressure and caloric value.
The degree to which natural gas is treated depends on its ultimate use. The various gas specifications for pipeline gas, compressed gas and LNG ensure that the product's treatment delivers satisfactory combustion performance for the application. Additional treatment is often required for long-distance gas transportation purposes, whether it is by pipeline to convey sales gas or LNG.
Gas conditioned for transmission and distribution via pipelines is regarded as sales gas specification. The characteristics of sales gas can vary dependent on requirements of the gas purchaser and/or contractual obligations imposed to protect the pipeline itself
LNG specification tends to be more stringent than sales gas specification as it is set for plant operation reasons, particularly for the liquefaction plant, according to Nexant's analysis. COb water and aromatics can freeze on exchanger surfaces ("riming"), reducing efficiency and possibly causing blockages in the heat exchanger. Mercury, a common trace contaminant of gas, attacks aluminum, the favored construction material for low-temperature exchangers. Table 1 lists the typical specifications for levels of impurities contained in the gas feeding a liquefaction plant.
Commercial applications
Natural gas can be used as an energy source (for power generation, liquid fuel generation as GTLs and/or space heating) or as a petrochemical feedstock-particularly for methanol and ammonia production.
Condensates are co products of natural gas conditioning, which consist of pentanes and heavier components. By virtue of being liquids, condensates are easier to transport as compared to natural gas. Condensates typically have very low sulfur levels in comparison with most crude oils and typically have API gravity of greater than 50.

Condensates generally have four possible dispositions:
• Sale to a Steam cracker as ethylene feedstock
Sale to a refiner
• Onsite splitting and sale of straight run cuts
• Third-parry splitting and sale of straight-run Cuts
Global markets
Global natural gas reserves have almost doubled over the past 20 years, according to this research. The increases proved gas reserves have been dynamic in several regions. In the Former Soviet Union (FSU), gas reserves increased by over 50%, those in Africa registered an increase of 125% and those in the. Middle East increased by more than 160%. E.g. 1 shows the breakdown of natural gas reserves by region for 2004.
The greatest concentration of natural gas reserves is in the Middle East and the FSU, which together account for more than 72% of the global reserves. Global gas reserves, however, are not matched to global gas production,

For example, North America, which has one of the lowest overall reserves, actually has the highest marketed production for any region (Fig. 2).

Out of a total marketed production of almost 95 Tcf (2,700 Bcm) in 2004, North America represented 28%; South and Central America, 5%; Europe and Eurasia, ] 2%; the FSU, 28%; Middle East, ] 0%; Africa, 5%; and Asia-Pacific, 12%. Production of natural gas is therefore greatest in North America, where demand is highest, followed by the FSU, then Europe and Asia-Pacific, according to this analysis.

"The mismatch between reserves and production rates is in part a reaction of the high Cost of transporting gas. This means that gas reserves relatively close to markets are most economic to develop and are preferentiality produced," notes Nexant's study. Thus, with the exception of the FSU, the regions of highest consumption-North America and Europe-have the lowest reserves to production ratio.

Bottlenecks in materials, Manpower delaying projects
Escalating construction costs throughout the LNG supply chain are threatening to crimp what has been a robust industry growth rate. "Sky-high Costs have prompted a reassessment of project timelines and feasibilities, with any slowdown likely to prolong the now well-established seller's market for output coming online toward me end of the decade or shortly thereafter," according to a recent outlook from Poten & Partners, a global consultancy.
Qatar's Energy Minister Abdullah alAttiyah has reported that capital Costs in the oil and gas sector have doubled or even tripled from initial estimates.

Qatar is not alone in feeling the pinch
Cost rises ranging from 25% to over 100% have been noted for a number of liquefaction projects in line for final investment approval, while several receiving terminals in the US and Canada are expected to cost much more than anticipated.

Storm of constraints
A confluence of factors is sending project costs skyward. While demand for LNG continues to rise, the industry is beginning to feel strain across the board from equipment and material costs to over-stretched engineering and project management resources. For example, prices for essential raw materials such as steel, nickel and aluminum have risen by as much as 130% in the past three years. Labor costs have also escalated markedly.
In addition, the current wave of new LNG projects has dovetailed with rapid growth in other energy industry sectors, further straining the whole engineering, procurement and construction (EPC) system, says this outlook.

Equipment manufacturing constraints have played a bigger role in recent cost escalation
"While shop loads for many LNG facility equipment items typically run between 60% and 80% of capacity, utilization has risen sharply over the last two years to around 100%. Demand for many critical plant items such as cryogenic pumps, compressors, turbines and fin-fan coolers exceeds manufacturing capacity and is expected to tighten further as construction schedules ramp up through the end of the decade," according to this study.

Strong concurrent demand from the upstream, GTL and petrochemical sectors for items such as plate-fin exchangers and fin-fan coolers is further exacerbating the equipment crunch. "This excess demand seems unlikely to be entirely soaked up through increased capacity: Delivery times on the most critical items have doubled in some cases and are beginning to affect project completion dates," says Poten & Partners analysis.

Another contributor to the current bottleneck is the demand for skilled resources.
Construction labor remains tight in several regions. In Western Australia, a small experienced labor pool is being called on to support three or more projects simultaneously, up from just one or two concurrent trains previously. Import projects in fast-growing markets like the US, the UK and India must compete for resources with strong domestic construction sectors and, in the case of the US Gulf Coast, hurricane reconstruction efforts.
Engineering and project management skills also appear to be stretched to near breaking point, and the number of experienced contractors is not expanding at the same pace as project opportunities.
"Resource quality concerns have been further exacerbated by fierce competition for experienced personnel between and among the oil companies and EPC contractors. This has cannibalized resources and increased staffing uncertainties and costs," says this study.

Some profit
Faced with the problem of expanding the available resource pool while still maintaining quality standards, the EPC sector is leveling demand for its services and selecting projects through steeper pricing. The result is higher EPC margins. These are now far more robust than earlier in the decade when contractors were struggling to emerge from a prolonged business slump and pricing was extremely competitive.

Without this supply side certainty, more developers will be forced to follow Anadarko's recent example and put import terminals on hold. “Of course, prices for LNG and natural gas have also increased along with costs, improving the economics of many projects. It remains to be seen if the higher costs become more palatable when sustained energy price rises are factored into project modeling,” according to this analysis.
FTC study finds no price manipulator: Post-hurricanes

The US Federal Trade Commission (FTC) conducted an intensive Congressionally mandated investigation into whether gasoline prices nationwide were manipulated or if price gouging was practiced in the aftermath of last August’s Hurricane Katrina.
In its investigation, the FTC found no instances of illegal market manipulation

Shell Russia LNG to Japan's Chubu Electric
July 12 Bloomberg

Royal Dutch Shell Plc's Russian venture may sign an initial accord this week to sell liquefied natural gas to Chubu Electric Power Co. over about 15 years, officials said.  Sakhalin Energy Investment Co. may sell Chubu Electric as much as 450,000 tons of LNG a year, said the officials, who asked not to be identified because the contract hasn't been signed. The agreement may be worth about 276 billion yen ($2.4 billion), based on Finance Ministry import data for May.

Japan, the world's biggest market for LNG, is competing with the U.S. and China for supplies as global demand for the cleaner- burning fuel surges. Chubu Electric, which has about 10 million customers in central Japan, is looking to gas projects in Russia to help make up for declining shipments from Indonesia, the world's largest LNG exporter, and Australia.

"Russian gas will add to Chubu Electric's variety of LNG supply sources and help the company raise its bargaining power in future negotiations with other producers," said Tatsuya Tsunoda, an analyst at Mizuho Securities Co. in Tokyo.

Hideo Matsumoto, an official in Sakhalin Energy's external affairs division in Sakhalin, Andy Corrigan, a spokesman for Shell in London, and Hirotaka Iwase, a spokesman for Nagoya-based Chubu Electric, Japan's third-biggest power producer, declined to comment.

Shell, the world's third-largest oil company, has sold 90 percent of the output from the 9.6 million metric ton-a-year LNG plant that's under construction in Sakhalin, Jon Chadwick, Shell's top gas executive in Asia, said in a June 22 interview. The company plans to sell the other 10 percent to buyers in Asia, he said, without giving details on potential buyers.

Spiraling Costs

The final gas sales, negotiated as rising oil prices and gas project delays have boosted Asia LNG prices, may help compensate for the project's spiraling costs. Developing Sakhalin, which is mostly ice-bound for half the year, will cost $20 billion, more than double the original estimates because of rising material prices and higher contractor fees.

Shell owns 55 percent of Sakhalin Energy, operator of the Sakhalin-2 project. Mitsui & Co., Japan's trading company, holds 25 percent and Mitsubishi Corp., Japan's largest trading company, 20 percent.

Japanese power and gas utilities such as Tokyo Electric Power Co. and Tokyo Gas Co. have agreed to buy a combined total of about 4 million tons of LNG a year from Sakhalin-2.

Indonesia has failed in the past three years to meet commitments to supply customers in Japan, South Korea and Taiwan as falling reserves cut natural gas supplies to its LNG plants. Australia's North West Shelf venture will reduce exports to Japan as it increases sales to China.

LNG is natural gas that has been chilled into liquid form for transportation by ship. Import terminals return the LNG to gas form so it can be sent through pipelines to customers such as factories, power stations and households. Demand for LNG is rising as oilfield discoveries slow and generators seek cleaner-burning fuel.

Shipments from Sakhalin Energy's Sakhalin-2 project to Chubu Electric may start as early as 2011, the officials said.

"We're seeking any available sources of LNG to make up for an expected decline in our imports from Indonesia and Australia,'' Iwase said by phone on July 7.

In the past eight months, Chubu Electric signed two LNG supply contracts with Malaysian and Australian producers for a combined 2 million tons a year, starting as early as 2010.

The utility in April said it will buy as much as 540,000 tons a year from Malaysia LNG Sdn., 90 percent owned by Petroliam Nasional Bhd., for 20 years. Last November, it signed an initial accord with Chevron Corp.'s Australian unit to buy 1.5 million tons a year from the Gorgon project under a 25-year supply contract, starting in 2010.

`Sustain Imports'
"We need to sustain our imports of about 9 million tons a year in the years ahead to keep pace with growing requirements," Iwase said.

Chubu Electric has four long-term LNG supply contracts with Australia's North West Shelf venture, Indonesia and Qatar for a combined 8.85 million tons a year. That accounts for 15 percent of Japan's overall LNG imports.

Indonesia supplies as much as 3.8 million tons, or 43 percent of the company's needs, under two agreements that end in 2010 and 2011. Chubu Electric's contract for 1.05 million tons a year from the North West Shelf venture will also expire around that time, Iwase said.

Indonesia may not extend contracts to supply 12 million tons of LNG a year to a group of Japanese buyers, including Chubu Electric, after expiry in 2010 because Indonesia wants to send the gas to Java, where demand is rising, Energy and Mineral Resources Minister Purnomo Yusgiantoro said on Feb. 8.

Indonesia's Declining Output
Indonesia's LNG shipments are in decline because of lower output from fields operated by Chevron Corp. and Vico Indonesia, a venture of BP Plc and Eni SpA.

"Japanese power and gas utilities will be exposed to the risk of LNG supply shortages in coming years" regardless of contracts with new producers, said Tsunoda at Mizuho Securities. "Start-up dates for several LNG projects have been delayed in recent years."
Shell Makes New Sakhalin II LNG Supply Deal
Shell 7/12/2006

Shell said that Sakhalin Energy, operator of the Sakhalin II Project, on Wednesday signed a new Heads of Agreement (HoA) for the sale and purchase of liquefied natural gas (LNG) with Japan’s Chubu Electric Power Co., Inc.

The Chubu Electric HoA calls for the supply of approximately 0.5 million tonnes per annum (mtpa) of LNG for a period of 15 years, with deliveries to commence in April 2011. Sakhalin Energy and Chubu Electric will now continue discussions to finalize a full sales and purchase agreement.

Shell added that the signing of the agreement further enhances Sakhalin’s role as a new strategic supplier of natural gas for Japan and confirms the wider Asia Pacific Region as a major new market for Russian gas supplies.

”We are pleased to have reached a deal with Chubu Electric for the supply of Sakhalin II LNG and we are looking forward to building a long-term relationship with the company,” said Ate Visser, Sakhalin Energy’s commercial director, who signed the agreement on the company’s behalf. “The signing of this HOA with Chubu Electric further demonstrates Sakhalin II LNG’s competitive advantage in the Japanese market due to our close proximity. It also indicates that, given we are still approximately 2 years away from the start of LNG exports, there is a strong customer desire to receive supplies from this pioneering project that is helping to establish a new energy province on Sakhalin.”

The LNG will be supplied from Sakhalin Energy’s 9.6-mtpa LNG plant, being built as part of the enormous Sakhalin II Phase 2 project at Prigorodnoye at Aniva Bay on the southern tip of Sakhalin. The plant will have two gas liquefaction process trains, each with a capacity of 4.8 mtpa. Overall design, procurement, and construction work of the Phase 2 project is about 75% complete.

Sakhalin Energy Investment Company Ltd. is an incorporated company, established in April 1994 and based in Yuzhno-Sakhalinsk, Russia. Its purpose is to implement of development the Sakhalin II integrated oil and gas project. The shareholders in Sakhalin Energy are: Shell Sakhalin Holdings B.V. with 55 % interest (parent company--Royal Dutch Shell plc), Mitsui Sakhalin Holdings B.V. with 25% (parent company--Mitsui & Co., Ltd.), and Diamond Gas Sakhalin B.V. with 20 % (parent company--Mitsubishi Corp.).

The Sakhalin II development represents one of the largest integrated oil and gas projects in the world. Phase 1 has been producing oil from the Vityaz Complex offshore Sakhalin since July 1999. The Vityaz Complex consists of the Molikpaq production platform, a single anchor leg mooring buoy and the Okha floating storage and offloading unit, and is located on the Astokh feature of the PA reservoir offshore Sakhalin. The Molikpaq is the first offshore oil production platform in the Russian Federation.

Production is currently limited to the ice-free period during the summer months. Cumulative production since first oil is more than 70 million barrels. Sakhalin Energy has sold its crude oil to customers in seven markets, new for Russia--Japan, Korea, China, Taiwan, the Philippines, Thailand, and the U.S.

Phase 2 of the Project is thought to be the biggest single integrated oil and gas project ever undertaken. It entails the further development of the PA field--an oil reservoir with associated gas – and the development of the Lunskoye field--a gas reservoir with associated condensate. The project calls for the construction of two new production platforms-- on the PA field and one on the Lunskoye field. Concrete gravity base structures (CGBS) of the new platforms were successfully built in Vostochny, in the Russian Far East, and installed at the fields in the summer 2005. In June 2006 the Topsides for the Lunskoye platform were installed on top of its CGBS. The Topsides for the PA-B platform will be installed in 2007.

An onshore processing facility is being built in the north of the island to separate gas and condensate from the Lunskoye field. Onshore pipelines will transport the oil and gas more than 800 kilometers to an oil export terminal and Russia's first LNG plant at Prigorodnoye on the southern end of Sakhalin Island, which remains largely ice-free year-round. The two-train LNG plant will have a capacity of 9.6 million tonnes per annum. Although the plant is still under construction, most of the future LNG capacity is already sold under long-term contracts. The company anticipates signing binding heads of agreements for the remaining gas in the near future.

The Phase 2 Project will also enable year-round production from the Molikpaq platform. It is currently about 75% complete, including design, procurement of materials, equipment, and actual construction.
Sasol aims for R20bn spending 12 Jul 2006
In 2004, Sasol started piping natural gas from Mozambique's onshore Temane field to the company's Sasolburg and Secunda sites.

Petrochemicals group Sasol said on Tuesday that its spending could approach as much as R20-billion a year towards the end of the current decade. "Looking ahead, it is difficult to provide precise capex figures for our 2007, 2008 and 2009 financial years," the company said. "Our current expectation is that annual capex spend will be in the region of R13-billion to R15-billion over the next two to three years. It is possible that capex could approach R20-billion a year towards the end of the current decade," Sasol said.

Sasol added that it envisaged a number of large potential capital projects.
These include incremental growth at Sasol Synfuels in South Africa, the planned expansion of the Mozambique natural gas project, completion of the Escravos project in Nigeria, expansion in Qatar and potential joint ventures in China.

In the safety front, Sasol achieved a recordable case rate of 0.7 per 200 000 employee hours during the 2006 financial year down from 1.2 in 2005. The company had aimed for a recordable case rate of 0.5 for 200 000 employee hours in 2006. "Regrettably, the group has so far this financial year reported four workplace fatalities (three contractors and one employee) in South Africa, which is unacceptable in the light of the ongoing group wide drive to achieve zero-fatality workplace worldwide," Sasol said. The group reported 17 workplace fatalities in 2005.

Gas-to-liquids plants
Sasol also said its pre-feasibility study with US company Chevron for a potential gas-to-liquids plant in Australia was nearing completion. Sasol Chevron continued to work with Qatar state company Qatar Petroleum to evaluate GTL expansion opportunities in that country, Sasol added.

The Oryx GTL plant in Ras Laffan in Quatar was inaugurated on June 6.
"The plant's air-separation train was started up in April 2006, paving the way for a series of sequential module start-ups leading to the full start-up of the entire GTL operation later in 2006," Sasol said.

Eyeing India, China
The company is also pursuing coal-to-liquid opportunities in China, India and the US and has entered into agreements to conduct second stage feasibility studies for two CTL plants in China. In Nigeria at Escravos, where Sasol's Fischer-Tropsch type process is being used, the bulk of the site preparation have been completed. "Nigeria personnel are already undergoing training at Sasol facilities in South Africa to operate the Escavos GTL plant once it becomes operational in 2009," Sasol said.

In South Africa, the iThemba Lethu shaft complex and the Bosjesspruit Irenedale projects at Secunda, were on track to be completed on schedule and below budget before December 2006, the company said. The development of the new Mooikraal mine, near Sasolburg, was completed before June 2006. The remainder of the Sasolburg mining operations, Sigma-Mohlolo and Sigma- Wonderwater, are undergoing final closure and rehabilitation.

On the empowerment front, Sasol said that the Igoda Coal venture with Eyesizwe should become effective in Sasol's 2007 financial year subject to final approval from South Africa's Department of Minerals and Energy. At Sasol Oil, exports, mostly to sub-Saharan African states, had been lowered in recent months to meet the growing South African demand for liquid fuels, Sasol said.

Sasol said its retail petrol station market share had climbed to more than eight percent. By the end of April 2006, 164 Sasol service stations and 212 Excel stations had been established. Following the blocking of the Uhambo joint venture by the Competition Tribunal, Sasol Oil was developing several potential growth plans for the next few years and expected to start implementing some of them in the year ahead, the company said.

Looking ahead
Sasol said that gas was core to fuelling the company's new growth. "Looking ahead, gas is set to play a more vital role in fuelling Sasol's future growth and diversification in southern Africa and beyond," the company said.

For Sasol's 2006 financial year, the company expected to report capital expenditure of R13-billion up from R12.4-billion in 2005.
Mexico U.S. Canada Strengthen Energy Sector 
Efe 7/18/2006

Mexico, the United States, and Canada have agreed to strengthen the North American energy sector to improve efficiency and foster research and development in clean technologies, Mexico's Energy Secretariat, or SE, announced Monday.  Mexican Energy Minister Fernando Canales Clariond, U.S. Energy Secretary Samuel W. Bodman, and Canadian Natural Resources Minister Gary Lunn announced the joint accord in a letter signed by the trio, said the SE in a communique.  The letter was directed at the heads of government of the three countries--which have been partners since 1994 in the North American Free Trade Agreement, or NAFTA--and emphasized that it had been agreed to improve energy efficiency programs and strengthen cooperation in the research and development of clean technology.
In addition, the partners agreed to facilitate the commercialization of technologies to supply clean energy and to negotiate a trilateral pact to lay the framework for collaboration in science and technology in the sector.

"The Mexican government endorses its commitment, at the highest level, to execute this initiative and ensure the secure and sustainable provision of energy, an essential element in the prosperity of the region," said the Mexican energy chief.

The joint accord formed part of the agenda during the March 31 meeting of the Security and Prosperity Partnership of North America in the southeastern resort town of Cancun.  In May, the top energy officials of the three countries met in Washington to hold the partnership's first working meeting dealing specifically with the energy sector. At that meeting, Canales, along with his Canadian and U.S. counterparts, evaluated the advances made in the energy sector and agreed on a strategy to implement the Cancun mandate, according to the SE statement. As a result of the meeting, the three officials agreed to send a letter to their countries' leaders establishing the strategy and the general actions to be undertaken to strengthen the region's energy sector.

The officials also acknowledged the importance of cooperation in regulatory matters and the exchange of energy information so that markets function more efficiently, are more open and are completely transparent. EFE
Rhode Island Law Bans LNG State Waters Traffic
Intelligence Press 7/18/2006

Rhode Island Gov. Donald L. Carcieri has signed into law a bill that would prevent tankers carrying liquefied natural gas (LNG) from using the state's waters to deliver the chilled fuel to the proposed Weaver's Cove LNG import terminal in Fall River, MA. The bill, sponsored by state Rep. Raymond Gallison Jr., was passed by the General Assembly in late June before it adjourned. Specifically, the measure would block LNG tankers from coming up the Narragansett Bay, which serves as the waterfront for two of Rhode Island's largest cities -- Providence and Newport.

It was not immediately known what impact the new law would have on the proposed Weaver's Cove LNG terminal, a $250 million project that would provide 800 MMcf/d of peak sendout capacity, 400 MMcf/d of baseload supply and 200,000 metric tons of LNG storage. The terminal would be located at a former petroleum import terminal on the Taunton River, which feeds into Mount Hope Bay and the Narragansett Bay.

There also was the question of whether federal law would preempt the new state law. A spokeswoman for Gallison said "not as far as we know" would federal law supersede the state's action. She noted that Gallison's measure was based on the federal Waterfront Safety Act.

However, in letters in May to Rhode Island's Senate president and House speaker, Rear Adm. David P. Pekoske, commander of the First Coast Guard District, said that any state law in this instance would be preempted by federal law, according to a published report in the Providence Journal. The letters further pointed to Massachusetts, where a bill similar to Gallison's was passed by the state legislature in 2004 but is now being challenged in court by federal authorities on constitutional grounds, it said.

The new Rhode Island law is the latest in a string of obstacles that has been thrown in front of the proposed Weaver's Cove LNG terminal, a project that has elicited considerable opposition from local, state and federal congressional leaders that has spilled over into the courts (see Daily GPI, Jan. 30). The Federal Energy Regulatory Commission approved the project a year ago despite the protests.

Opponent Rep. Jim McGovern (D-MA) responded by adding language to a transportation authorization bill, later signed into law by President Bush, that blocked the demolition of the Brightman Street Bridge connecting Fall River and Somerset, MA (see Daily GPI, Aug. 10, 2005).

This action would make it impossible for large LNG tankers to navigate the Taunton River and reach the Weaver's Cove facility in Fall River. Weaver's Cove, which is sponsored by Poten & Partners and Amerada Hess Corp., countered with a proposal to build smaller LNG tankers to get around the constraints of the Brightman Street Bridge (see Daily GPI, Feb. 14).