France is one of the world's largest nuclear power producers
France is a founding member of the European Union (EU) and one of Europe's most important economies. In 2004, France's gross domestic product (GDP) stood at $2.01 trillion, the second-largest in the EU. Economic growth, though, has been unremarkable in recent years, with real GDP growth of only 2.1% in 2004. The lack of significant economic growth has strained France's public finances, and for the fourth consecutive year, France's budget deficit will exceed the limits of the EU Growth and Stability Pact.

Jacques Chirac has been President of France since 1995, leading a coalition of center-right parties. Since 2002, he has ruled in coordination with Prime Minister Jean-Pierre Raffarin. The two have set upon many reforms of France's economy, including a relaxation of labor market regulations, the privatization of state-owned enterprises, and an overhaul of the public pension scheme. Following the poor showing of the center-right coalition in the March 2004 regional elections, Chirac replaced the heads of several key government ministries and slowed the pace of these reforms. Public employee unions have been the most vocal critics of energy sector liberalization, staging many large demonstrations.

French economy has the third-lowest carbon intensity in the OECD.
France emitted 407 million metric tons (Mmt) of Carbon dioxide in 2002, the fourth-most in Europe. It also consumed 11.0 quadrillion British thermal units (Btu) of total energy, the second-largest amount in Europe. On the other hand, the energy intensity of France's economy in 2002 was Well below the average for members of the Organization for Economic Cooperation and Development (OECD).
Further, the carbon dioxide intensity of the French economy in 2002 was the third-lowest in the OECD, behind only Switzerland and Sweden, an indication of France's reliance upon nuclear energy.

France has been the victim of several major Oil spills that resulted in severe environmental damage to France's coastline and caused serious economic harm to France's tourism and fishing industries. In response, the French government has taken a proactive approach to preventing marine pollution by establishing an extended ecological zone into the Mediterranean Sea and imposing more stringent conditions on oil tankers.
 
Air pollution, especially in Paris, is still a problem, despite the adoption of measures to mitigate the effects of increased transportation and growing energy consumption from France's transportation sector. By European standards, France's development and use of renewable energy resources has been fairly limited. Market barriers thus far have stifled the use of renewables for electricity and heat production in France.
 
Furthermore, the low cost of nuclear energy has meant that there is little economic justification to develop alternative fuel sources. Finally, there has been some opposition to nuclear power in France by environmentalists, including public protests and demonstrations.

In 2004, France's crude Oil refining capacity was 1.95 million bbl/d, the third-largest in Europe. The largest refinery in the country is Total's Gonfreville l'Orcher facility, with a capacity of 343,000 bbl/d. Total controls some 56% of France's refining capacity.
 
France imported 599,400 bbl/d of Petroleum products in 2004, with the largest sources of these imports being the former Soviet Union (27%), Germany (9%), and the United Kingdom (8%). The majority of France's petroleum products consumption is for road transportation, followed by household consumption and air transportation.

France imported 97% of its natural gas needs in 2003
At the beginning of 2005, France had about 450 billion cubic feet (Bcf) of proven Natural Gas reserves. France has very little domestic natural gas production; in 2003, the country consumed 1.6 trillion cubic feet (Tcf), with only 3% of that demand met from domestic sources. The most important sources of France's natural gas imports are Norway, Russia, and Algeria. Natural gas is a small component of France's energy mix, representing only 15% of total energy consumption in 2002.

The EU has enacted numerous directives seeking to liberalize European natural gas markets. To date, France has been one of the slowest EU members to implement these directives into national law, though there has been considerable progress of late on this issue. Beginning in July 2004, non-residential customers could freely choose their gas distributor, with this freedom scheduled to extend to all customers by 2007.
 
The French government has made some progress on liberalizing GdF itself; in 2004, it legally changed GdF into a joint stock company. The most significant change caused by this new legal definition was that the French government would no longer guarantee GdF's debt. GdF planned to offer its stock to the public for the first time in 2005, though French law requires that at least 50% of GdF's stock remain held by the French government. France has also begun the process of privatizing its natural gas transport system, also a requirement of EU directives. By the end of 2005, distribution companies should be able to purchase stakes in the parts of the system that they utilize.
Since deregulation began, Total has been the private company with the most success in gaining access to the French market. While most natural gas enters France from the north, Total appears to have concentrated on natural gas customers in the south, where prices are higher and there are greater opportunities for undercuting the tariffs charged by GdF. In 2000, Total purchased Gaz du Sud-Ouest, a small regional gas transportation company in southern France. Total also planned to construct a new natural gas import Pipeline from Spain, and it had a stake in the Medgaz pipeline from Algeria (see below). Foreign operators, such as BP and Ruhrgas, have also made some progress in gaining market share.

France has natural gas pipeline connections to Norway, Spain, Russia, Netherlands. GdF operates the vast majority of France's domestic Pipeline system. The company operates over 19,000 miles of Natural Gas pipelines in France, with an overall system capacity of 5.9 Bcf/d. The GdF systems covers the entire country, with main trunk lines connecting population centers to the import entry points of Dunkerque, Montoir-de-Bretagne, Fos-Cavaou, Cerville-Velaine, and Taisnieres. GdF also maintains 0.28 Bcf of natural gas storage facilities at strategic locations in the transmission network.
Because of its dependence on natural gas imports, France has extensive pipeline connections with its neighbors. The Franpipe, completed in 1998, links Norway's Draupner platform in the North Sea to the French port of Dunkerque. The 521-mile-long, 1.4-Bcf/d Franpipe was the first pipeline to directly link France with a natural gas field in a foreign country. Analysts predict that Franpipe will eventually supply one-third of France's total natural gas consumption. The Trans-Pyrenean natural gas pipeline, linking Calahorra, Spain to Lacq, France began operations in 1993. The 330-million-cubic-feet-per-day (Mmcf/d) connection allows Spain to import natural gas via France from Norway. France also imports natural gas from Russia through the Cerville-Velaine distribution center in northeast France and from the Netherlands through the Taisnieres entry point.

In October 2004, Total began construction of the 48-Mmcf/d Euskadour natural gas pipeline. The pipeline will connect a liquefied natural gas (LNG) receiving terminal in Bilbao, Spain to southern France. Total expected to finish construction on the Euskadour pipeline by 2006.
The proposed Medgaz natural gas pipeline would link Algeria to France via Spain. Algeria�s Sonatrach (20%) and Spain's Cepsa (20%) are leading the project. Financial issues have delayed initial construction of Medgaz, as the consortium has not yet secured sufficient investments to start the project. However, if completed, Medgaz would have an initial capacity of 775 Mmcf/d.

Introduction
Owned by the French government, Gaz de France (GdF) dominates all Natural Gas activities in the country. Prior to recent reforms (see below), GdF had a legal monopoly on the production, distribution, transportation, and importation of natural gas in the country. In recent years, EU directives have forced member countries to open their natural gas sectors to foreign investors, and GdF has taken advantage of this openness to enter the domestic natural gas markets of other EU countries. As a result, almost one-third of GdF's 15 million customers are outside France. However, because France has been one of the slowest EU countries to open its own markets, there has been some backlash to GdF's foreign ventures, especially from the governments of Italy and Spain.
Gaz de France Profile
An integrated energy utility, present throughout the gas supply chain from exploration and production to customer services, pursuing its growth in Europe.
As Europe's regulatory framework is going through a profound change and energy markets are opening up to competition, Gaz de France has decided to operate as an integrated energy utility, present throughout the gas supply chain from exploration and production to customer services, and to pursue its growth in Europe.
This choice, which is compatible with the new market development conditions, will allow the Group to implement its strategy while complying with European directives.
Gaz de France offers multi-energy packages, and a large gamut of associated services (activities described in �Energy Supply and Services�), while managing and developing its natural gas transmission, storage and distribution infrastructures (activities described in �Infrastructures�).
Committed to sustainable development, Gaz de France is seeking to achieve corporate growth while maintaining its commitment to public service
Gaz de France Key Data
The Group's consolidated net sales totalled 18.13 billion euros, up 8.9% from 2003.
International business accounted for 29% of the Group's total net sales.
Net income Group share reached 1046 millions euros.
Total investements amounted to 1,76 billion euros.

Gaz sales amounted to
66.4 billion cubic meters.
The Group employed a workforce of
38 251 people.

France has tried to position itself as a European hub for liquefied Natural Gas (LNG) imports. France is one of Europe's largest consumers of LNG, and the country receives some 25% of its natural gas imports in the form of LNG.
 
Most French LNG imports come from Algeria, with smaller quantities from Nigeria. France currently has two LNG receiving terminals: the 440-Mmcf/d Fos-sur-Mer, located at the Fos Cavaou gas terminal on France's Mediterranean coast, and a 970-Mmcf/d terminal at Montoir-de-Bretagne, on the Atlantic coast.
 
GdF is constructing a new, offshore LNG receiving terminal at Fos Cavaou, and ExxonMobil has also proposed building an LNG import terminal near Fos Cavaou by 2009.

France has relatively small Coal reserves of 40 million short tons (Mmst). France's coal sector has declined steadily over the past several decades, as cheaper imports have replaced domestic sources. In 2002, France only produced 2.3 Mmst of coal. The state-owned coal monopoly, Charbonnages de France, closed its last production facility in April 2004. There have been some plans by foreign companies to resume coal production in France; in late 2004, ATH, a large British coal producer, announced that it would resume production at the Bertholene coal concession in south-central France by 2006.
Coal has become a less important part of France's energy supply, constituting only 5% of French total energy consumption in 2002. Nuclear power has replaced most of France's coal-fired power plants. Nevertheless, France still consumed 22.9 Mmst of coal in 2002, the seventh-most of the EU's 25 member countries, with the largest sources of France's coal imports coming from South Africa, Australia, and the United States. The few remaining coal-fired power plants represented about half of France's coal consumption in 2002, with most of the remainder consumed by the steel industry.

TransCanada Pipelines is the largest Operator of Natural Gas pipelines in Canada. Its 25,600-mile network transports the bulk of Canada�s natural gas production. Important parts of the TransCanada network include the 13,900-mile, 10.6-Bcf/d Alberta System, the 120-mile, 0.9-Bcf/d British Columbia System, the 8,900-mile, 7.2-Bcf/d Canadian Mainline, and the 600-mile, 3.0-Bcf/d Foothills System.
A consortium of natural gas companies, led by Imperial Oil, plan to build the Mackenzie Valley natural gas Pipeline. The 760-mile, 1.2-Bcf/d pipeline would carry natural gas from inside the Arctic Circle to northern Alberta, where it would flow into the existing natural gas transportation system; there would also be a parallel pipeline to carry NGLs. Canada�s National Energy Board (NEB) scheduled a series of public hearings on the project for 2006, where it would consider the economic and environmental impacts of the project. If the project attains regulatory approval, construction of the system would likely last four years and cost some C$6 billion.

Canada is the United States� most important trading partner, with over $450 billion worth of goods, services, investments, and financial transfers exchanged between the two countries in 2004. Canada and the U.S. also enjoy an interdependent energy relationship, trading Oil, Natural Gas, Coal, and electricity.
Canada has experienced sustained economic growth during the past several years; its real gross domestic product (GDP) grew at a rate of 2.9 percent in 2005, the same as in 2004. Continuing economic recovery in the United States and higher prices for Canada�s natural resource exports have driven Canada�s economic growth in recent years.

Canada has considerable natural resources and is therefore one of the world�s largest producers of energy. In 2003, Canada produced 18.4 quadrillion British Thermal Units (Btu) of total energy, the fifth-largest amount in the world. Of this total, Canada consumed 13.5 quadrillion Btu in 2003. Since 1980, Canada�s total energy production has increased by 80 percent, while its total energy consumption has increased only by 40 percent.
 

Canada�s total Oil production (including all liquids) was 3.1 million barrels per day (bbl/d) in 2005, while the country consumed 2.3 million bbl/d that year. The country's oil production has been increasing since 1999, as new oil sands and offshore projects have come on-stream to replace aging fields in the western provinces.
Overall, analysts predict that oil sands production will increase significantly in coming years and offset the decline in Canada�s conventional Crude Oil production.

According to Oil and Gas Journal (OGJ), Canada had a reported 178.8 billion barrels of proven oil reserves as of January 2006, second only to Saudi Arabia. However, the bulk of these reserves (over 95%) are oil sands deposits in Alberta. The inclusion of oil sands in official reserve estimates is not without controversy, because oil sands are much more difficult to extract and process than conventional crude oil.
Canada sends over 99 percent of its crude oil exports to the U.S., and it is one of the most important sources of U.S. oil imports. During the first eleven months of 2005, Canada exported 1.6 million bbl/d of crude oil to the U.S., the single-largest source of U.S. crude oil imports. Canada also sent some 520,000 bbl/d of Petroleum products to the U.S. during this period, the most from a single country.

Canada has a privatized Oil sector that has witnessed considerable consolidation in recent years. The largest integrated Operator in the country is Imperial Oil, majority owned by ExxonMobil. In 2002, Alberta Energy Company and PanCanadian Energy merged to create EnCana, Canada�s largest independent Upstream operator.

Other significant oil producers in Canada include Talisman Energy, Suncor, EOG Resources, Husky Energy, and Apache Canada. U.S. companies maintain a sizable presence in the Canadian oil industry.

The Canadian government formed Petro-Canada in 1975 in an effort to reduce the dominance of U.S. companies in Canada�s oil industry. The company received considerable initial resources from the Canadian government in its early years, though critics accused Petro-Canada of inefficiently deploying those resources and interfering with the operations of private companies. In 1991, the Canadian government began to privatize Petro-Canada, and in late 2004, the government sold its remaining 20 percent stake in the company.

If you have never considered trading energy markets then think again - Because they can yield fantastic profits as the recent bull move in crude oil has shown.

Here we will go through the basics and show you how to trade energy markets for maximum profit potential.

The worlds most actively traded commodity group

The energy markets are the world’s largest traded commodity group as they are literally the fuel of the global economy and are always volatile and offering opportunities for profit.

Standardized Contracts

Contacts are standard size and the main market is NYMEX in New York.

You can go both long and short as well giving you constant opportunities for profit and price information is freely available on the net.

Looking for opportunities

As they are always trending - The best way to trade them is via technical analysis and look for the long term trends not the short term noise of the market.

Focus on these trends and you can pile up huge profits if you catch them!

Each energy market has its own unique trading personality and a seasonal tendency. These seasonal tendencies make a great filter for trades as in many contracts their highly reliable.

For example, unleaded gasoline is used for cars and peak demand is the summer driving season on the other hand heating oil is needed to heat homes and demand is strongest in the winter.

Trading these spreads adds an extra dimension to trading to pinpointing low risk high reward trades.

There are many more and the really give you an edge when trading.

Intra commodity spreads

To cut risk even further you can trade these spreads.

These are simply the difference in prices of two different contracts, of the same commodity i.e August and October natural gas

The trick is to pick the contract that is expected to move the most and lay off some of the risk.

For instance, in energies it’s normally the nearby contract that moves the most, so you buy the near contract and sell the deferred – This is known as a bull spread and is used by the real pro traders.

When using spreads its always important to take into consideration the general trend and price pattern of the spread before trading – There great way to limit risk and maximize profits and that’s what we all want.

Vehicles

With futures you can also trade options to and these are great way to trade a volatile market as they offer unlimited profit potential linked to limited risk.

When buying options though make sure (and this applies to any market) you buy options that are at or near the money with plenty of time to expiry.

You get staying power and that’s a major bonus, in a volatile market like energies.

Instead of getting stopped out by the market “noise” you can remain in on the trade. Getting stopped out by volatility is a major reason traders lose – They get the direction right but get hit on the stop.

Why energies are such a good market

They trend well (and are suitable for any long term trading methodology) they fuel the world economy so we know there is always going to movement and trends but you get something extra when trading:

1. Highly reliable seasonal spreads

2. The opportunity to trade intra spreads for better risk reward

Combine this with options and you will get the best risk reward with staying power to take advantage of these moves.

A word of caution

Don’t trade energies short term – They are highly volatile and short term price spikes that will kill you – You need top focus on the long term trends only.

Another important point is these markets have an ability to wrong foot the experts so don’t focus on the news – Focus on what the charts are telling you.

You are looking for long term trends and the big trends only come a few times a year so you won’t be trading frequently. If you want to always be in on the action forget you will lose.

 rude Oil Weekly Trading Signal – Explained

The weekly oil trading chart shows a long 7 month sell off without any bounces on the way down and volume has increased as the price continues is slide lower indicating that there is more and more interest from traders and investors. Prices have now put in a small bounce and will be testing our downward trend line if the price of oil continues to rally this week. Also the MACD (momentum) is about to cross to the upside which is very bullish. If oil prices breakout above our down trend line and the MACD crosses over to the upside then we will have a buy signal in oil on the weekly chart.

Crude Oil Weekly Trading Strategy Chart
Crude Oil Trading Strategy

Crude Oil Daily Trading Chart – Explained
Crude Oil’s daily chart is very bullish looking as Well. The price has broken is downward trend line and has pulled back to a support level over the past 2 weeks. Fridays big bounce gave us a buy signal for USO because everything for my oil trading strategy was in favor (MACD cross, Stochastic, Trend line Break, volume). The only issue was that risk was over 3%, currently at 9% I will wait for a better entry point on a correction which will also confirm the new trend.

Crude Oil Daily Trading Signals Chart
Crude Oil Trading Signals

Crude Oil Trading Conclusion:
Crude oil as you can see looks to be a picture perfect setup as momentum in the price is slowly shifting direction. While many traders went long on Fridays buy signal I am waiting for risk to decrease before I put my money to work. I don’t mind buying things at a higher price if the overall risk is lower and the reversal looks strong.

Commodities so far this week have not changed much. But I can point out a few things for us to watch Thursday and Friday.
Precious Metals – Gold GLD fund – Silver SLV Fund – PM Stocks GDX Fund
We could start to see a shift between the price relationship between gold and the broad market. I pointed this out last week mentioning that gold and silver are starting to hold up in value while stocks sell off on big days. For example, Wednesday’s sell-off in equities did not have much effect on precious metals. This is what we want to see. It means money is moving out of stocks and into gold and silver bullion as a safe haven.
These three charts of GLD, SLV and GDX show Wednesday’s price action as gold and silver moved higher while precious metal stocks sold down with the rest of the market. This is generally a bearish indicator for gold and silver but because I am starting to see this happen more often and traders are ready for the market to top any day, I am seeing this as a bullish indicator. If the market starts to slide I have a feeling investors will be dumping a lot more money into gold and silver.

Gold, Silver, Precious Metals Stocks
Gold, Silver, Precious Metals Stocks
Energy – Oil USO Fund – Energy Stocks XLE Fund
We are seeing a similar pattern in the energy sector. Oil had a nice move higher today while energy stocks sold off. Stocks are starting to fall out of favor.

Energy Oil Stocks
Energy Oil Stocks
Natural Gas – UNG Fund
Natural gas is still in a bear market and trading under a major resistance trend line. This commodity could go either way so I am going to wait for the odds to be more on my side before jumping on board with a long or a short trade.

Natural Gas UNG Fund
Natural Gas UNG Fund
Mid-Week Gold, Silver, Oil and Nat Gas Conclusion:
The market is starting to look and feel top heavy with many indicators and price action patterns giving cross signals. While the market could continue to rocket higher with new money getting dumped in from average investors because of solid 3rd quarter earnings, we must be cautious by tightening our stops and take some profits off the table. Until we get a short term oversold market condition I am trading very conservatively.

The past week in gold, silver, oil, natural gas and the broad market wasn’t anything to write home about. We are seeing controlled profit taking which is making the market choppy. Many traders are getting very bearish on the market which is a good thing in my opinion. According to my market internals, sentiment and volume analysis we should get a shake out (sharp dip) which would make traders exit their positions before the market continues higher.
Some trader’s say we are in a bull market, others say we are in a major bear market. Either way the trend is up on the daily and weekly charts and companies are making money. Buying on over sold dips has been very profitable this year. Until I see things drastically change, this is my strategy for the broad market.
Lets take a look at the commodity sector.
HUI – Gold Stocks Index
Recently we have seen money move out of gold stocks but with the majority of them trading at support trend line we could see some fireworks this week.

Gold Mining Stocks Trading
Gold Mining Stocks Trading
Gold – GLD Exchange Traded Fund
Gold has been trading sideways as investors and traders digest the previous rally higher. The recent price action looks similar to the September rally and consolidation. Lets hope for a another move higher without getting shaken out of our positon.

Gold ETF Trading Newsletter
Gold ETF Trading Newsletter
Silver – SLV Exchange Traded Fund
Silver is in much of the same situation as gold. We are waiting to see what happens here at these support levels.

silver ETF Trading Newsletter
silver ETF Trading Newsletter
Crude Oil – USO Exchange Traded Fund
Oil has been making a strong rally after breaking out of is multi month consolidation pattern. We are now looking for some type of pullback or test of breakout for another low risk entry point.

Crude Oil ETF Trading Newsletter
Crude Oil ETF Trading Newsletter
Natural Gas – UNG Exchange Traded Fund
Natural gas is having some trouble breaking out above the multi month resistance trend line. Buying here is a 50/50 bet and I will wait for another entry point before putting our money to work.

Natural Gas ETF Trading Newsletter
Natural Gas ETF Trading Newsletter
Natural Gas, Oil, Silver and Gold Exchange Traded Fund Conclusion:
Overall, the market feels ready for quick snapback to shake traders out of profitable positions. I expect a resumption of the up trend as the market slowly creeps higher at a steady pace digesting each rally with sideways movement.

Commodities and stocks almost look ready for a rally or at least a relief bounce. The market is down over 5% and the normal pullback this year has been 4%. Using technical analysis and inter-market analysis we can see that the market is reaching extreme lows and this usually means we are only a couple days away from a rally.
I work with several market technicians as we all analyze the market a different way and share our work with each other to gain maximum insight on the broad market moves. We analyze momentum cycles, magnetic cycles, volatility levels, support & resistance levels, volume analysis and inter-market analysis.
Each of us has found a formula which works for our individual style of trading. And by combining our work we have found that we can collectively produce some very exciting trading signals for the broad market. We focus on leveraged index funds in order to take advantage of our insights. While nothing in trading is ever perfect, the analysis for timing the broad market is very exciting.
Here are some quick charts on where the market is trading.
US Dollar – Daily Dollar Price Chart
This chart is a no brainer. The trend is down and trading at resistance. If the US dollar reverses back down we will see stocks and commodities move higher.

US Dollar Index Trade
US Dollar Index Trade
VIX – Daily Volatility Index
Again, overall the trend is down and trading at resistance. As the saying goes “When the VIX is high its time to buy”. Just to be clear, the VIX is low compared to the previous highs set back in 2008 which was around the 80 level. But, if we want to keep things simple for the current trend then the VIX is high for our current market condition. The VIX moves in the opposite direction of the equities market.

VIX - Volatility Index Trade
VIX - Volatility Index Trade
DIA – Dow Jones Industrial Average ETF Fund
Here is the Dow Jones index fund and it clearly shows that when investors are selling out of their positions and getting scared of a market collapse, volume rockets higher. When we see the price pullback to possible support levels and volume increases that is a time when we should be looking to scale into a long position for a bounce, such as now.

Dow Jones Index Trade
Dow Jones Index Trade
XLE – Energy Sector ETF
You can see that the energy sector is very close to a support level and volume is high. With the US dollar about to reverse back down it will help boost this sector as it is tied in with commodity prices which rise with a falling dollar. I expect we will see a price gap lower and fill this area before moving higher.

Energy Sector XLE Trade
Energy Sector XLE Trade
GLD – Gold ETF Fund & Silver
This chart has not changed much from last weeks report. We are getting the drop as expected this week. We could see the gap fill from early October before gold stabilizes.
Silver is in the same situation. Gold and silver move in tandem so we are waiting for a bottom before looking for a low risk entry point.

Gold and Silver Trading Tends
Gold and Silver Trading Tends
Commodity & Stocks Trading Conclusion:
To keep things short and to the point, I am seeing momentum cycle lows as of today, magnetic wave lows today, and most commodities and indexes trading at support. These observations, coupled with the US dollar at a possible resistance level and market volatility spiking to an extreme high, lead me think a bounce is in the cards.

Gold GLD ETF – Gold Pivot Trading Low – Daily Chart
As you can see from the chart below we appear to be in the middle of a pivot low correction which can make for some great entry points. The trend is up, gold is oversold and it looks like we had a reversal low last week.

Gold Pivot Trading Low
Gold Pivot Trading Low
Silver SLV ETF – Silver Pivot Trading Low – Weekly Chart
This is a chart I posted a couple months ago and so far silver has traded within the trend lines and support & resistance levels I pointed out in early August. Silver still looks bullish as it is trading at a pivot low.
Pivot Trading Low for Silver
Pivot Trading Low for Silver
Gold Miners GDX ETF – Gold Miners Pivot Trading Low – Weekly Chart
Gold mining stocks appear to be trading near the bottom of the trend channel. The odds are still pointing to higher prices.
Gold Miners Trading Pivot Low
Gold Miners Trading Pivot Low
Crude Oil USO Fund – Oil Pivot Trading Low – Daily Chart
This chart of USO is also from a recent post in early October. USO broke out and is now trading at our support trend lines. There was a nice reversal candle last week but the heavy selling across the entire market pulled oil back down.
Crude Oil Pivot Low
Crude Oil Pivot Low
Natural Gas UNG Fund – Natural Gas Pivot Trading Low – Daily Chart
Pivot trading low could be close for UNG. The daily chart is telling me we saw the bottom in natural gas back in September as prices collapsed washing out most long (bullish) traders. I figure we will see prices trade between $9-12 for several months as the commodity forms a base.
Natural Gas Pivot Trading Low
Natural Gas Pivot Trading Low
S&P 500 Index – S&P 500 Pivot Trading Low – Daily Chart
The broad market looks and feels oversold. This chart uses Andrews Pitchfork analysis to show where short term pullbacks to the middle trend line (middle of trading range) have been a buying opportunity. Deeper corrections drop to the bottom support trend channel. These corrections sometimes form a lower low and lower high that scares traders and inestors out of the market before heading higher.
SPX Pivot Low
SPX Pivot Low
S&P 500 Seasonality Chart – S&P 500 Pivot Trading Low
This chart shows the performance for each month over the past 37 years. Simple analysis shows selling pressure in Sept and Oct as mutual funds sell positions to lock in gains for their books each year. This move is generally compounded because seasoned traders know about this seasonal movement and also sell positions and even short the market to take advantage of this at times.
I think we are inline for a perfect storm going into year end. The market is trading at a pivot low from many different analysis theories. This forms a high probability trading opportunity in the next 2 months if we see prices reverse and start heading higher this month.
SPX Seasonal Trend Pivot Points
SPX Seasonal Trend Pivot Points
Pivot Trading Low Conclusion:
A lot of stocks have taken a real beating this past month as sell orders flooded the trading desks last week. Technology, financials and small cap stocks took is the worst. The sharp drop is not really what we wanted to see but it makes good sense. With those groups posting the largest gains since March it is only normal that money will be coming out of those stocks to lock in gains.
Many traders are starting to panic about another possible market melt down. This negative sentiment is a bullish indicator for higher prices. If everyone is scared and exiting their positions then we must be close to trading a pivot low.

According to Oil and Gas Journal (OGJ), Germany had 390 million barrels of proven oil reserves in 2005. Most of these reserves are located in northern and northeastern Germany.
 
The country produced 162,000 barrels per day (bbl/d) of oil in 2004, of which 68,000 bbl/d (42 percent) was Crude Oil. Over one-half of Germany�s crude oil production comes from a single field, Mittelplate, located in tidal flatlands in the North Sea. Mittelplate is a joint project of German oil and gas companies RWE and Wintershall AG.
Due to the size of the German economy and the lack of significant domestic oil production, Germany is one of the world�s largest oil importers. In 2004, Germany consumed 2.6 million bbl/d of oil, with imports supplying over 90 percent of these needs.
 
According to BAFA, the German economics statistics agency, the largest source of Germany�s crude oil imports in 2004 was Russia, followed by Norway and the United Kingdom.

Germany has several large Pipeline systems that deliver crude Oil from import terminals along its northern coastline to inland refineries. The 440-mile Minveraloelverbungleitung (MVL) connects the cities of Rostock, Schwedt, and Spergau in eastern Germany.
Majority-owned by France�s Total, MVL supplies oil refineries in Schwedt and Spergau with Crude Oil from an oil terminal at Rostock, with a capacity of 380,000 bbl/d. MVL also connects with the Druzhba crude oil pipeline from Russia at the Poland-Germany border, near Schwedt.
The Norddeutsche Oelleitung (NDO) crude oil pipeline in northern Germany connects an oil terminal and refinery in Hamburg with an oil terminal in Wilhelmshaven. The 90-mile NDO has a capacity of 150,000 bbl/d. Another crude oil pipeline, the 240-mile, 300,000-bbl/d Nord-West Oelleitung (NWO), connects Wilhelmshaven with Wesseling, near Cologne, supplying oil refineries in the area.

According to Oil and Gas Journal (OGJ), Germany has 9.9 trillion cubic feet (Tcf) of proven Natural Gas reserves, the third largest in the EU, after the Netherlands and the United Kingdom. Almost all of Germany�s natural gas reserves and production occur in the northwestern state of Niedersachsen, between the Wesser and Elbe rivers.
Germany�s sector of the North Sea also contains sizable natural gas reserves, currently supporting the A6-B4 production project (see below). However, environmental regulations have curtailed the complete exploration of the area.
Germany began to liberalize its natural gas sector in the late 1990s in order to comply with EU directives. Unlike other EU countries, though, Germany did not establish a national regulator for the liberalized natural gas sector. Rather, it relied upon negotiated access between suppliers, distributors, and transmission companies.
Without transparent open access to the system, several large companies came to dominate the sector. In July 2005, Germany approved a new energy bill that vested regulatory oversight of the natural gas sector with the Bundesnetzagentur (BNA), an existing agency that also regulated the telecommunications and the postal system.
Private operators control Germany�s natural gas production. BEB, jointly owned by Royal Dutch Shell and Esso (a subsidiary of ExxonMobil), controls about half of domestic natural gas production. Other important players include Mobil Erdgas-Erdoel (also a subsidiary of ExxonMobil), RWE, and Wintershall.
The largest wholesale distribution company in Germany is E.ON Ruhrgas, controlling about one-half of that market. Germany�s wholesale distributors also control most of the national natural gas transport network. Finally, there are thousands of small, independent companies active in the retail distribution sector, many wholly- or partly-owned by municipal governments.

Germany has one of the largest economies in the world, with a 2004 nominal gross domestic product (GDP) of $2.7 trillion. However, in recent years, a combination of high unemployment and sluggish domestic demand has dampened German economic growth. The country posted real GDP growth of 1.6 percent in 2004, after GDP contracted by 0.7 percent in 2003.

Owning to its large economy, Germany is one of the world�s largest energy consumers. In 2003, the country consumed 14.2 quadrillion British Thermal Units (Btu) of total energy, the fifth-largest amount in the world. Besides Coal, Germany does not possess any sizable hydrocarbon reserves, so the country must rely upon imports to meet much of its energy needs.
 
In 2003, Germany imported 63 percent of its total energy needs, up from 44 percent in 1991. The lack of domestic energy resources has led Germany to become a world leader in the development of renewable energy technologies, with the country becoming the world�s largest generator of electricity from wind.

In 2003, Germany produced 780 billion cubic feet (Bcf) of Natural Gas. The country is the third largest producer in the EU, behind the United Kingdom and the Netherlands. Production has risen slightly since 1991, but the lack of new discoveries in the country could hinder future production growth.
Over 90 percent of Germany�s natural gas production occurs in Niedersachsen. Germany also operates a single offshore natural gas field, A6-B4, located in the North Sea. Operated by Wintershall, A6-B4 came onstream in September 2000, and the project currently produces about 46.8 Bcf of natural gas per year.
In 2003, Germany produced 780 billion cubic feet (Bcf) of natural gas. The country is the third largest producer in the EU, behind the United Kingdom and the Netherlands. Production has risen slightly since 1991, but the lack of new discoveries in the country could hinder future production growth.
Over 90 percent of Germany�s natural gas production occurs in Niedersachsen. Germany also operates a single offshore natural gas field, A6-B4, located in the North Sea. Operated by Wintershall, A6-B4 came onstream in September 2000, and the project currently produces about 46.8 Bcf of natural gas per year.

Due to its central location in Europe, Germany is an important transit center for Natural Gas imports from Russia and the North Sea. The 200-mile, 1.2-Bcf/d Sachsen-Thueringen-Erdgasleitung (STEGAL) extends from St. Katharinen, Czech Republic to Reckrod, where it connects to the MIDAL system. STEGAL allows Germany to import natural gas from Russia via the Czech and Slovak natural gas transmission systems. It is also possible for STEGAL to operate in reverse flow mode, facilitating the transmission of North Sea natural gas to the Czech Republic and Slovakia instead.
E.ON Ruhrgas and Gaz de France (GdF) jointly own the 2.1-Bcf/d Mittel-Europaeische-Gasleitung (MEGAL) system, which has two parts. MEGAL-Nord is a 290-mile Pipeline linking the Czech Republic and France via Waidhaus, on the Czech-German border, and Medelsheim, on the French-German border. MEGAL-Sud extends 100 miles from Oberkappel, on the German-Austrian border, to Schwandorf, where it connects to MEGAL-Nord. Besides facilitating the transportation of natural gas from Russia to France, the MEGAL system also has several interconnections with Germany�s domestic gas transport network.
The Trans-European Natural Gas Pipeline (TENP), a joint venture of E.ON Ruhrgas and Italy�s Sname Rete, runs 600 miles from the German-Dutch border to Italy. This system also supports a reverse flow operation, so it would be possible to also use the TENP to transport Algerian or Libyan natural gas from Italy to Germany.
 

Germany�s domestic Natural Gas transmission network facilitates the movement of natural gas from import terminals to its interior consumption centers. Wingas operates the 440-mile Mitte-Deutschland-Anbindungs-Leitung (MIDAL) system, which runs the length of the entire country and connects the North Sea coast with Kahrlsruhe.
With a capacity of 1.2 Bcf per day (Bcf/d), MIDAL allows Germany to import natural gas from Norway through receiving terminals in Emden and Dornum. Also linking the North Sea coast with the interior is the Norddeutsche Erdgas Transversale (NETRA), a 210-mile, 2.1 Bcf/d system operated by a consortium led by E.ON Ruhrgas. NETRA links the Emden and Dornum receiving terminals with eastern Germany.

There are two important spur lines off MIDAL. Wingas and E.ON jointly operate the 80-mile Rehden-Hamburg Gas Pipeline (RHG), which connects Hamburg to the MIDAL system. Second, Wingas operates the 200-mile WEDAL system that links the MIDAL pipeline with the Belgian border near Aachen.
Wingas operates the Jamal-Gas-Anbindungs-Leitung (JAGAL) pipeline system, which brings Russian natural gas into eastern Germany via Poland. The 70-mile JAGAL I connects Mallnow, on the Polish border, to Baruth, south of Berlin. JAGAL II extends 140 miles from Baruth to Rueckersdorf, in the state of Thueringen. Overall system capacity of JAGAL is 2.3 Bcf/d.

As of 2003, Germany had 7.4 billion short tons (Bst) of recoverable Coal reserves. Over 97 percent of these coal reserves are lignite (brown coal), with the remainder composed of bituminous and anthracite (hard coal). Brown coal is Germany�s most important domestic energy source. According to Statistik der Kohlenwirtschaft, a German coal industry association, brown coal production represents over 40 percent of Germany�s total domestic energy production.
Coal is an important part of Germany�s energy consumption mix, meeting 24 percent of Germany�s total energy needs in 2003.

Germany is the seventh largest coal producer in the world. In 2003, it produced 197.4 million short tons (Mmst), of which 86 percent was lignite, 13 percent was bituminous, and 1 percent was anthracite. The country operates ten mines, employing some 45,000 people. However, German coal production has declined rapidly since reunification in 1989-1990; in 1990, West and East Germany produced a combined 513.7 Mmst of coal. The closure of older, inefficient mines in the former East Germany has been the principle cause of this decline. Currently, over one-half of Germany�s lignite production occurs in the Rhineland region in the western part of the country.
Most of Germany�s hard coal deposits are deep below ground and difficult to access, making their extraction problematic and expensive. As a result, the government must provide large subsidies to the industry to maintain production. The German government plans to give the hard coal industry $3.6 billion in subsidies in 2005, down from $3.7 billion in 2004. According to an agreement reached with the coal industry in 1997, coal subsidies will fall to $2.3 billion by 2012. Brown coal production, on the other hand, is mostly feasible without subsidies.
 

Germany has a strong commitment to protecting its environment. It has actively promoted the use of renewable energy, both under the Kohl government with the Electricity Feed Law, and now under Schroeder's government with eco-taxes. However, Germany�s reliance on Coal, particularly brown coal, for electricity generation and the heavy industrialization of the economy has lead to serious problems with air pollution, acid rain, and habitat degradation. These problems are particularly acute in the former East Germany.
Germany consumed 14.2 quadrillion British Thermal Units (Btu) of total energy in 2003, of which Oil was 39 percent, coal was 24 percent, and Natural Gas was 23 percent. With an energy intensity of 6,800 Btu per dollar (2000, PPP) of economic output in 2003, Germany is below the average energy intensity for the 25 countries in the OECD.
Germany ratified the Kyoto Protocol on climate change on May 31, 2002. In 2003, the country emitted 842.0 million metric tons (Mmt) of Carbon dioxide, making it the sixth-largest emitter of carbon dioxide in the world and the third largest within the OECD. The EU has decided to meet its Kyoto obligations as a whole, rather than as individual signatories. Under the EU�s burden-sharing program, Germany must cut its carbon dioxide emissions by 21 percent relative to the 1990 baseline during the 2008-2012 commitment period. The EU expected Germany to make such deep cuts, because the country has already experienced a sharp decline in carbon dioxide emissions following reunification.

Aside from acting as a transit center for other countries' Oil and Natural Gas exports from the Caspian Sea, Iran has potentially significant Caspian reserves of its own, although only a small amount (0.1 billion barrels) has been proven as "recoverable." Currently, Iran has no oil or natural gas production in the Caspian region. In early 2004, a 3-D seismic survey of the southern Caspian was being conducted by Iran's Oil Survey Co. In September 2004, it issued an initial tender to begin drilling in deepwater portions of the Caspian Sea sometime in 2005. However, Iran now looks likely to postpone any Caspian Sea drilling until 2006 at the earliest, in part due to problems at its Alborz platform.

At the present time, Iran continues to maintain that regional treaties signed in 1921 and 1940 between Iran and the former Soviet Union, which call for joint sharing of the Caspian's resources between the two countries, remain valid. Iran has rejected as invalid all unilateral and bilateral agreements on the utilization of the Sea. As such, Iran is insisting that either the Sea should be used in common, or its floor and water basin should be divided into equal (20 percent) shares. Under the so-called "condominium" approach, the development of the Caspian Sea would be undertaken jointly by all of the littoral states. However, using the equidistant method of dividing the seabed on which Kazakhstan, Azerbaijan, and Russia have agreed, Iran would only receive about 12-13 percent of the Sea. 

As of early December 2005, no agreement has been reached among Caspian Sea region states on this matter. In March 2003, Iran and Turkmenistan had noted "the need to achieve a consensus between the five [littoral] countries," while the two countries reportedly moved ahead in charting their common border in the Sea.

The Doroud 1&2, Salman, Abuzar, Foroozan, and Sirri fields comprise the bulk of Iran's offshore Oil output. Iran plans extensive development of existing offshore fields and hopes to raise its offshore production capacity significantly. In early October 2003, Iran re-launched a tender for eight exploration blocks in the Persian Gulf after receiving little interest from a January 2003 announcement (Iran may launch a second licensing round in the next few months).

One area considered to have potential is located near the Strait of Hormuz. Another interesting area is offshore near Bushehr, where Iran claimed in July 2003 to have discovered three fields with potentially huge - 38 billion barrels oil reserves. In May 2004, Brazil's Petrobras signed a 3-year, $32-$34 million deal to develop the Tousan fields of the Persian Gulf.

In late 2001 and early 2002, Shell brought part of the $800 million Soroush-Nowruz development online, with production reaching 190,000 bbl/d in June 2005. The two fields are located offshore, about 50 miles west of Kharg Island, and contain estimated recoverable reserves of around 1 billion barrels of heavy oil (20° API). The heaviness and high sulfur content (3 percent) of the oil has made marketing Soroush-Nowruz oil difficult; in September 2005, Iran reportedly diverted Soroush-Nowruz production into storage rather than try to sell it at a steep discount. In addition, there were reports in early October 2005 of technical difficulties at the oil fields, reducing production to 100,000 bbl/d for a time.

In March 2004, the Iranian Offshore Oil Company (IOOC) awarded a $1.26 billion contract for recovery of NGLs and Natural Gas from Soroush, Nowruz, Foroozan, and Abuzar to Japan's JGC Corporation. Ethane from the gas will feed an ethylene complex at the Kharg petrochemical complex. Iran reportedly hopes to become a major Petrochemicals producer within 10 years.

The Iranian constitution prohibits the granting of Petroleum rights on a concessionary basis or direct equity stake. However, the 1987 Petroleum Law permits the establishment of contracts between the Ministry of Petroleum, state companies and "local and foreign national persons and legal entities." Buyback contracts, for instance, are arrangements in which the contractor funds all investments, receives remuneration from NIOC in the form of an allocated production share, then transfers operation of the field to NIOC after the contract is completed.

The buyback system has drawbacks for both sides: by offering a fixed rate of return (usually around 15-18 percent), NIOC bears all the risk of low Oil prices. If prices drop, NIOC has to sell more oil or Natural Gas to meet the compensation figure. At the same time, companies have no guarantee that they will be permitted to develop their discoveries, let alone operate them. Finally, companies do not like the short terms of buyback contracts. In response, Iran has considered revisions to buyback terms (e.g., extending the length of contracts, allowing for continued involvement of oil companies after the field is handed over to NIOC), but these have been controversial and generally have not moved forward. In early December 2005, acting Iranian oil minister, Kazem Vaziri, questioned the future of buyback contracts but emphasized that Iran would continue to seek foreign investors in the energy sector.
The first major project under the buyback investment approach became operational in October 1998, when the offshore Sirri A oil field (operated by Total and Malaysia's Petronas) began production at 7,000 bbl/d. The neighboring Sirri E field began production in February 1999, with production at the two fields expected to reach 120,000 bbl/d.

In March 1999, France's Elf Aquitaine and Italy's Eni/Agip were awarded a $1 billion contract for a secondary recovery program at the offshore, 1.5-billion-Barrel Doroud oil and natural gas field located near Kharg Island. The program is intended to boost production from around 136,000 bbl/d to as high as 205,000 bbl/d. Total is Operator of the project, with a 55 percent share, while Eni holds the other 45 percent.

In April 1999, Iran awarded Elf (46.75 percent share), along with Canada's Bow Valley Energy (15 percent share), a buyback contract to develop the offshore Balal field. Eni is also involved, with a 38.25 percent stake. The field, which contains some 80 million barrels of reserves, started producing at a 20,000-bbl/d rate in early 2003, and reportedly reached 40,000 bbl/d in February 2004.

With sufficient investment, it is widely believed that Iran could increase its crude Oil production capacity significantly. Iran produced 6 million bbl/d of Crude Oil in 1974, has not come close to recovering to that level since he 1978/79 Iranian revolution. Still, Iran has ambitious plans to increase national oil production - to more than 5 million bbl/d by 2010, and 8 million bbl/d by 2015. The country is counting on billions of dollars in foreign investment to accomplish this, but the goal is unlikely to be achieved without a significant change in policy to attract such investment (and possibly a change in relations with the West).

Iran exports around 2.7 million bbl/d, with major customers including Japan, China, South Korea, Taiwan, and Europe. Iran's main export blends include Iranian Light (34.6° API, 1.4 percent sulphur); Iranian Heavy (31° API, 1.7 percent sulphur); Lavan Blend (34°-35° API, 1.8-2 percent sulphur); and Foroozan Blend/Sirri (29-31° API). Iran's domestic oil consumption, 1.5 million bbl/d in 2005, is increasing rapidly as the economy and population grow. As mentioned above, Iran subsidizes the price of oil products heavily, resulting in a large amount of waste and inefficiency in oil consumption. 

State-owned National Iranian Oil Company (NIOC)'s onshore field development work is concentrated mainly on sustaining output levels from large, aging fields. Consequently, enhanced oil recovery (EOR) programs, including Natural Gas injection, are underway at a number of fields, including Marun and Karanj. Overall, Iran's oil sector is considered old and inefficient, needing thorough revamping, advanced technology, and foreign investment.

In February 2004, a Japanese consortium led by Inpex signed a final agreement on the $2 billion Azadegan oilfield development project. Azadegan was discovered in 1999, representing Iran's largest oil discovery in 30 years, and is located onshore in the southwestern province of Khuzestan, a few miles east of the border with Iraq. Reportedly, Azadegan contains proven crude oil reserves of 26 billion barrels, but the field is also considered to be geologically complex, making the oil more challenging and more expensive to extract. In January 2001, the Majlis approved development of Azadegan by foreign investors using the so-called "buyback" model (see below).

Inpex, which has no Upstream experience of its own, hopes to bring in an international partner - possibly Total, Statoil, Sinopec, or Lukoil (Shell has indicated that it is not interested) - as the field's Operator. Initial production of medium-Sour Crude oil from Azadegan could come in 2007, ramping up to 260,000 bbl/d by 2012. At its peak, Azadegan production could account for as much as 6 percent of Japan's oil imports. However, as of early December 2005, little forward progress had been made on Azadegan, including the lack of an operating agreement with NIOC, possibly due to financial and/or political issues (e.g., US sanctions against Iran, the absence of an Iranian oil minister). In September 2005, Iran sharply criticized Japan for the slow progress.

Since August 1996, the Iran-Libya Sanctions Act (ILSA) has imposed mandatory and discretionary sanctions on non-U.S. companies that invest more than $20 million annually (lowered in August 1997 from $40 million) in the Iranian Oil and Natural Gas sectors. On August 3, 2001, President Bush signed into law the ILSA Extension Act of 2001.

This provided for a 5-year extension of ILSA with amendments that affect certain of the investment provisions. In addition, the United States has maintained various sanctions against Iran since 1979, following the seizure of the U.S. embassy in Tehran on November 4 of that year. In 1995, President Clinton signed two Executive Orders prohibiting U.S. companies and their foreign subsidiaries from conducting business with Iran.

Executive Order 12957 specifically banned any "contract for the financing of the development of Petroleum resources located in Iran." On March 10, 2005, President Bush extended sanctions for another year, citing Iran's "continued support for terrorism, its efforts to undermine the Middle East peace process and its efforts to acquire weapons of mass destruction."

In April 2004, the United States removed Libya from the ILSA sanctions, following fulfillment of that country's commitments to rid itself of weapons of mass destruction and to renounce terrorism. On September 20, 2004, the President signed an executive order terminating the national emergency (declared in Executive Order 12543 of January 7, 1986), with respect to the policies and actions of the Government of Libya, revoking Executive Order 12544 of January 8, 1986 and Executive Order 12801 of April 15, 1992, all of which imposed sanctions against Libya in response to the national emergency.

The new September 2004 executive order also revokes Executive Order 12538 of November 15, 1985, which prohibited the importation into the United States of petroleum products refined in Libya. This lifting of sanctions has opened the door to a potential return of U.S. oil companies to Libya for the first time in nearly 20 years.

Besides Iran, the United States maintains sanctions on two other oil producing nations - Sudan and Syria. For more information on these sanctions, please see EIA's Global Energy Sanctions report.

In spite of the fact that little damage was done to Iraq's Oil fields during the war itself, looting and sabotage after the war ended was highly destructive, accounting for perhaps 80 percent of total damage. Starting in mid-May 2003, the U.S. Army Corps of Engineers -- which had the lead in restoring Iraq's oil output to pre-war levels -- began a major effort to ramp up production in the country.
 
On April 22, 2003, the first oil production since the start of the war began at the Rumaila field, with the restart of an important gas/oil separation plant (GOSP). As of November 2005 Iraq's Qarmat Ali water injection facility reportedly was operating at only 70 percent of capacity, holding back production from Rumaila and other southern oil fields.
Prior to the recent war, oil industry experts generally assessed Iraq's sustainable production capacity at no higher than about 2.8-3.0 million bbl/d, with net export potential of around 2.3-2.5 million bbl/d (including smuggled oil).
 
One major challenge in maintaining, let alone increasing, oil production capacity, was Iraq's battle with water cut, especially in the south. In 2000, Saybolt International had reported that Iraq�s Northern Oil Company (NOC) and Southern Oil Company (SOC) were able to increase their oil production through use of short-term techniques not generally considered acceptable in the oil industry (i.e., injection of refined oil products into crude reservoirs). The Saybolt report now appears to have been largely accurate. In addition, a U.N. report in June 2001 said that Iraqi oil production capacity would fall sharply unless technical and infrastructure problems were addressed. Others have pointed to the need for water injection in order to maintain pressure and to avoid Reservoir damage in the southern fields. U.N. oil experts have estimated that some reservoirs in southern Iraq have been so badly managed that their ultimate recovery rates might be only 15 percent-25 percent, Well below the 35 percent-60 percent usually seen in the oil industry.
Iraq's southern oil industry was decimated in the 1990/1991 Gulf War, with production capacity falling to 75,000 bbl/d in mid-1991. That war resulted in destruction of gathering centers and compression/degassing stations at Rumaila, storage facilities, the 1.6-million bbl/d (nameplate capacity) Mina al-Bakr/Basra export terminal, and pumping stations along the 1.4-million bbl/d (pre-war capacity) Iraqi Strategic (North-South) Pipeline.
 
Seven other sizable fields remain damaged or partially mothballed. These include Zubair, Luhais, Suba, Buzurgan, Abu Ghirab, and Fauqi. Generally speaking, oilfield development plans were put on hold following Iraq's invasion of Kuwait, with Iraqi efforts focused on maintaining production at existing fields.
In October 2005, the SOC re-issued a tender for drilling in southern oil fields. Reportedly, SOC offered improved payment and other terms. Included in the tender was the chance to drill 20 wells in the Mishrif formation of the West Qurna fields (see below). In other news, in September 2005, the US Project and Contracting Office cancelled cancelled part of a contract with Halliburton to refurbish 60 wells in southern Iraq. The contract was then awarded to SOC.

According to the Oil and Gas Journal, Iraq contains 110 trillion cubic feet (Tcf) of proven Natural Gas reserves, along with roughly 150 Tcf in probable reserves. About 70 percent of Iraq's natural gas reserves are associated (i.e., natural gas produced in conjunction with oil), with the rest made up of non-associated gas (20 percent) and dome gas (10 percent).
 
Until 1990, all of Iraq's natural gas production was from associated fields. In 2002, Iraq produced 53 billion cubic feet (Bcf) of natural gas, down sharply from 215 Bcf in 1989. Since most of Iraq's natural gas is associated with oil, progress on increasing the country's oil output will directly affect the gas sector as Well. Most associated gas is simply flared off. Significant volumes of gas also are used for power generation and reinjection for enhanced oil recovery efforts.
Main sources of Iraqi associated natural gas are the Kirkuk, Ain Zalah, Butma, and Bay Hassan oil fields in northern Iraq, as well as the North and South Rumaila and Zubair fields in the south. The Southern Area Gas Project was completed in 1985, but was not brought online until February 1990. It has nine gathering stations and a larger processing capacity of 1.5 billion cubic feet per day.
 
Prior to the war, natural gas gathered from the North and South Rumaila and Zubair fields was carried via Pipeline to a 575-million-cubic-foot-per-day (Mmcf/d) natural gas liquids (NGL) fractionation plant in Zubair and a 100-Mmcf/d processing plant in Basra. At Khor al-Jubair, a 17.5-million-cubic-foot LPG storage tank farm and loading terminals were added to the southern gas system in 1990.
 
After the 2003 war, gas gathering and treatment facilities in southern Iraq reportedly deteriorated to the point that most gas produced in the area was simply flared off. Iraq is looking at plans for increasing associated natural gas processing capability in Zubair and West Qurna and to reduce gas flaring.
Iraq's only non-associated natural gas production is from the al-Anfal field (200 Mmcf/d of output) in northern Iraq. Al-Anfal production, which began in May 1990, is piped to the Jambur gas processing station near the Kirkuk field, located 20 miles away. Al-Anfal's gas resources are estimated at 4.5 Tcf, of which 1.8 Tcf is proven.
 
In December 2001, Russia's Gazprom reportedly was negotiating possible development of al-Anfal. In November 2001, a large non-associated natural gas field reportedly was discovered in the Akas region of western Iraq, near the border with Syria, and containing an estimated 2.1 Tcf of natural gas reserves. It is not clear whether the field is associated or non-associated.

According to the Oil and Gas Journal, Iraq's refining capacity was 597,500 bbl/d as of January 1, 2005, compared to a nameplate capacity of 700,000 bbl/d. Overall, Iraq has eight refineries, none of which were damaged during the March-April 2003 war itself. The three largest refineries are the 310,000-bbl/d Baiji, 150,000-bbl/d Basra, and 110,000-bbl/d Daura plants.
In May 2005, two small companies - Hydrocarbon Supply Ltd. of Texas and Prokop of the Czech Republic -- signed contracts to upgrade Daura at a cost of $110 million. Capacity at the plant is to be increased to 170,000 bbl/d. Also, on April 1, 2005, Iraq also announced plans to build a new oil refinery in Basra, with a capacity of 250,000-300,000 bbl/d. Reportedly, eight companies have bid to build the refinery.
According to former Oil Minister Issam Chalabi, Iraqi refineries currently are operating at only 50 percent-75 percent of capacity, forcing the country to import around 200,000 bbl/d of refined products, at a cost of $200-$250 million per month. This does not include the additional cost of steep government subsidies on the consumer price of Gasoline, which had been priced under 10 cents per Gallon prior to December 2005 (violent demonstrations broke out in that month after steep price increases were announced).
 
It is estimated that, overall, direct and indirect oil subsidies cost Iraq $8 billion per year. Subsidies also encourage illegal smuggling of oil out of Iraq, and exacerbate shortages within the country. In order to reduce Iraq's need for oil product imports, significant investment will be needed to perform refinery upgrades (Iraq had identified dozens of such projects prior to the war) and possibly to build new refineries.
In early December 2005, construction began on two new refineries � a 140,000-bbl/d facility in Karbala province and a 30,000-bbl/d plant at Diwaniya (south of Baghdad). The two plants are expected to cost around $1.5 billion and $300 million, respectively, and to be completed within three years. Iraq has also issued tenders for a 70,000-bbl/d refinery at Koya in the Kurdish region, and a 140,00-bbl/d facility at Nahrain, south of Baghdad.

n the Persian Gulf, Iraq has three tanker terminals: Basra port (formerly known as Mina al-Bakr), Khor al-Amaya, and Khor az-Zubair (which mainly handles dry goods and minimal Oil volumes, plus Natural Gas liquids and liquefied Petroleum gas). Basra is Iraq's largest oil terminal, with two pipelines (48-inch and 41-inch), plus four 400,000-bbl/d capacity berths capable of handling very large crude carriers (VLCCs).
Gulf War damage to Basra appears to have been repaired in large part and the terminal reportedly was handling around 1.6 million bbl/d in mid-October 2004. Basra's nameplate loading capacity is 85,000 barrels per hour (around 2 million bbl/d), which is significantly above current capacity of about 50,000 barrels per hour (around 1.2 million bbl/d), suggesting that potentially higher volumes of oil than the nameplate capacity could be shipped out of the port.
On April 24, 2004, a suicide attack against Basra port damaged one tanker berth in the first such attack on Iraq's Persian Gulf export terminals since the onset of war in March 2003. On September 22, 2004, the Iraqi Oil Ministry signed a $15 million contract with Sinopec to build eight oil storage tanks, with a total capacity of 350,000 barrels, on the Faw Peninsula in southern Iraq.
Iraq's Khor al-Amaya terminal was heavily damaged by Iranian commandos during the Iran-Iraq War and also during Operation Desert Storm in 1991. In early March 2004, Khor al-Amaya reopened for oil exports, with initial capacity of 12,000 barrels per hour (300,000-400,000 bbl/d). Upon full completion of repairs, Iraq projects Khor al-Amaya's capacity is expected to reach 1.2 million bbl/d.

The subsea segment of the oil and gas industry is the by far the fastest growing industry in the world today. The global turnover is expected to grow by 30% from today towards 2011. This creates opportunites for companies that are not part of this booming oil anmd gas industry today..

Gold futures quotations showed a small upturn on Monday with the support from other raw goods and stock indexes prices, however, the market trading volume was low.
 
December Gold futures in followup of COMEX trading up by 2,50 dollars to 994,10 dollars per ounce.
 
The deals were rather calm and low-key due to Iom-Kipur holiday. The Gold was supported by purchases amid the stock indexes uprise, as well as purchases of other raw goods after the copper price surge from the minimums. The yellow metal was also backed up by the oil price tick up.
 


 

Oil

Crude oil futures rose on Monday following the stock indexes. Thus, considerable strengthening of the American stock indexes eased concerns for a while regarding growing oil and fuel reserves.
According to the trading results of the New York Commodity Exchange, the November sweet crude oil futures ticked up by 82 cents or by 1,2% to 66,84 dollars per barrel. Brent oil futures price jumped by 43 cents or by 0,7% to 65,54 dollars per barrel.
 
The oil prices climbed when the US stock indexes started the trade in a positive territory, recovering the interrelation, which has been unstable for about a couple of weeks.
 
The oil futures has been fluctuating around 70 dollars/brl for several months already, while the traders are waiting for the global economy to use surplus oil and fuel inventories accumulated during the downturn. The reserves contraction is slower than it was expected. This promtes corrections from time to time, similar to that was seen in the last week when the oil price fell by 8% amid unexpected growth of crude oil inventories in the USA.
 
The oil market participants also keep watch over the actions of Iran waiting for «G6» negotiations which are due on Thursday in Geneva. On Monday, Iran tested the long-range rocket able to reach Israel. The USA and its confederates stand for new sanctions introduction after the information emerged last week concerning the establishment of the second uranium enrichment plant in Iran, raising concerns about that Teheran is to develop the nuclear weapon.
 


FRAMINGHAM, Mass. -- Energy Insights, an IDC company, announced today that it now offers research coverage dedicated to helping utilities and technology providers understand the complex dynamics of the rapidly evolving intelligent grid market. The Intelligent Grid Strategies research and advisory service will explore the business and regulatory impacts of emerging intelligent grid technologies and provide innovative strategies such as distributed energy resources. Technologies covered will include sensors, smart metering, network automation and control, analytics, and communications

Kuwait's finance minister said on Thursday the US dollar will remain the currency of oil trading because there was no problem in using the US currency.

The remarks follow a host of denials this week of a British newspaper report that Gulf Arab states were in secret talks with Russia, China, Japan and France to replace the dollar with a basket of currencies in trading oil.

"This is not on the cards," said Mustapha Al Shamali on a visit to London, when he was asked if there was a chance of replacing the dollar.

If we carefully look at the present business scenario then we could easily see that in recent time futures trading are gaining its world-wide popularity. In fact it is the most common trading found on many markets these days. As per the latest definitions- it is more like a trading of contracts called futures contracts, which facilitates the owner with power to trade the basic commodity at somewhere in the future for a fixed rate. Moreover, like stocks and options trading, futures trades are done in precise centralized futures commodity trading markets. However, depending upon the type of futures contracts, it can be broadly classified as commodity futures contracts and financial futures contracts.

In commodity futures contracts, trading of contracts end with a physical delivery. They may include agricultural commodity futures like sugar, oats, wheat, rice etc OR energy commodity futures such as crude oil, natural gas, etc; metals & stones like gold, silver, diamond etc. This means that if a trader is holding a futures contract and the time come when it expires, the appropriate payment will be made by the buyer, and the basic commodity (agricultural or energy) will be delivered by the seller. Whereas in financial futures contracts, trading of contracts end with a cash settlement and it include futures for treasury notes, bonds, mutual funds etc.

The futures contract trading can be executed electronically on electronic trading platforms linked to the major commodity exchanges or by the traditional open outcry method on the floor of the exchange. However, the basic form of futures contract is that it must state a location and date for physical delivery of the particular commodity. There are times when delivery arrangements are also specified by the exchange. This is particularly important for commodities that require high transportation costs, which in turn may affect the delivery place.

All those who are involved in commodity future trading must understand that for most commodity futures contracts, daily price movement limits are specified by the exchange. A limit movement is nothing but a move of price that can shift in either direction equal to the daily price limit. If the price moves down by an amount equal to the daily price limit, the contract is said to be limit down. And if the price moves up by the limit then it is said to be limit up. Price limits and positions limits generally aim to avoid large price movements deriving from excessive speculation. However, at times they act as an artificial barrier to trading when the price of the underlying commodity increases or decreases swiftly.

Overall, trading with commodity futures is definitely a good way to make handsome money but there are some essential factors that one has to take care. It is highly volatile in nature and more likely to remain unpredictable mainly because of several factors like geopolitical concerns, contracted demand-supply fundamentals, growth and inflation pressures that put pressure on the global commodity market. It is a most interesting market environment but also a dangerous one as many wars have been fought and many nations & leading companies compete for scarce natural resources and food supplies.

American Gold Eagle Coin investment allows individuals to diversify their portfolios into gold bullion coins that are backed by the United States government for their weight content and purity. The American Eagle Gold Coin is the official gold coin of the United States, as authorized by the Gold Bullion Act of 1985. In 1986, this American Gold Eagle was released by the United States Mint, instantly becoming a highly sought-after addition to the collections of numismatists worldwide.
It is available in 1/10, 1/4, 1/2 and 1 ounces of gold, carrying denominations of $5, $10, $25 and $50, respectively. It is specified by law that the American Eagle Gold Coin must be produced by gold from sources exclusively found here in the United States.
In addition to being produced with an alloy of silver and copper in order to create a more wear-resistant composition, each coin contains 91.67% of gold (22 karat), 3% silver and 5.33% copper, no matter what the denomination may be.
The American Eagle Gold Coin features breathtaking artistry depicted on both sides. On the obverse side, there is Lady Liberty, full length, with flowing hair and holding a touch in her right hand and olive branch in her left. This is a depiction of the past designs of Lady Liberty created by Augustus Saint Gaudens, famous sculptor and friend of former President Theodore Roosevelt. Additionally, the Capitol building is featured in the background, off to the left. The opposing side has a male eagle with an olive branch in his beak, soaring above a female eagle and her hatchlings in a nest.
Gold Eagles provide an added value for your investment dollar in that they may also be utilized as government approved IRA (Individual Retirement Accounts) investments. As the U.S. government also provides the guarantee of each coins weight and precious metal content, American Gold Eagles provide a relatively safe and stable long-term investment strategy to a diversified portfolio of IRA assets.
The assets that are included in a tax-sheltered IRA plan do need to be held in trust by an authorized Trustee or Custodian, a third-party who would be authorized to accept these contributions in a secure, authorized depository such as an FDIC insured bank vault. Not all Custodians or Trustees are approved or authorized to store gold bullions coins,as outlined under government regulations, so you it is important to take care in choosing a responsible organization to hold your assets if you do wish to include physical gold coins in your IRA investment strategy.
The majority of American Eagle Gold Coins are produced from the West Point Mint in New York and therefore bear the mint's "W" marking. With the current state of the American economy, the price of gold has become more valuable than ever before. Due to this fact, while the coins have nominal face values of $5, $10, $25 and $50, these coins are currently selling for a great deal more. At this time, the American Gold Eagle Coin are sold for approximately $130, $275, $500 and $1,000 respectively, as gold prices continue to drive the prices even higher.
As the growth of traditional stocks and bonds has slowed considerably the past few years, investors have turned to gold bullion as a reliable source of portfolio diversification and hedge against a weakened dollar. Typically speaking, the price of gold flows in a direction that is opposite that of dollar values. Simply put, gold prices trend upwards as the dollar falls.
If you are looking to add value to a portfolio that is diversified into precious metals, investing in American Gold Eagles and NGC Graded Gold Eagles makes for an excellent way to expand into physical gold assets in addition to, or in place of traditional stocks and bonds.

;;

gamma