Global Natural Gas Production Doubled Between 1980 and 2010

Global dry natural gas production increased 110% between 1980 and 2010, from 53 trillion cubic feet (Tcf) in 1980 to 112 Tcf in 2010. The combined share of North America and the Former Soviet Union, the top two producing regions during the time period, fell from 72% in 1980 to 49% in 2010. While all regions increased natural gas production between 1980 and 2010, the Middle East grew most rapidly, increasing more than eleven fold.

Natural gas production in the United States has grown rapidly in the past several years. Rapid increases in U.S. natural gas production from shale gas formations resulted from widespread application of two key technologies: horizontal drilling and hydraulic fracturing.

Shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other regions of the world. An initial assessment of 48 shale gas basins in over 30 foreign countries includes 5,760 Tcf of technically recoverable shale gas resources.

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EIA: Domestic Supply of Liquid Fuels Projected to Increase, Resulting in Fewer Imports

U.S. dependence on imported liquids declines through 2035 in the 2012 Annual Energy Outlook (AEO2012) Reference case projection, primarily as a result of growth in domestic oil production, an increase in bio fuels use, and slower growth in consumption of transportation fuels. In this projection, net petroleum imports as a share of total U.S. liquid fuels supplied drop from 49% in 2010 to 36% in 2035.

Net petroleum imports are projected to make up a smaller share of total energy consumption in response to modest economic growth, increased efficiency, growing domestic oil production, and continued adoption of nonpetroleum liquids. Although not included in the Reference case, proposed fuel economy standards for future vehicles (model years 2017 through 2025) would further reduce projected liquids use and the need for imports.

Projections in the Annual Energy Outlook 2012 Reference case assume current laws and regulations remain generally unchanged throughout the projection period, thus serving as a starting point for analysis of energy policies. More highlights from the Reference case, as well as projections for several energy factors through 2035, are available in the AEO2012 Early Release Reference Case Overview and supporting materials.



Gold Appears to Break Out of it's Down Trend

EIA: Arctic Crude Oil and Natural Gas Resources

Resource basins in the Arctic Circle region (click to enlarge)

Source: U.S. Geological Survey.

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The Arctic holds an estimated 13% (90 billion barrels) of the world's undiscovered conventional oil resources and 30% of its undiscovered conventional natural gas resources, according to an assessment conducted by the U.S. Geological Survey (USGS). Consideration of these resources as commercially viable is relatively recent despite the size of the Arctic's resources due to the difficulty and cost in developing Arctic oil and natural gas deposits.

Studies on the economics of onshore oil and natural gas projects in Arctic Alaska estimate costs to develop reserves in the region can be 50-100% more than similar projects undertaken in Texas.

Profitable development of Arctic oil and natural gas deposits could be challenging due to the following factors:

• Equipment needs to be specially designed to withstand the frigid temperatures.
• On Arctic lands, poor soil conditions can require additional site preparation to prevent equipment and structures from sinking.
• Long supply lines and limited transportation access from the world's manufacturing centers require equipment redundancy and a larger inventory of spare parts to ensure reliability, while increasing transportation costs.
• Employees expect higher wages and salaries to work in the isolated and inhospitable Arctic.
• Natural gas hydrates can pose operational problems for drilling wells in both onshore and offshore Arctic areas.

Natural gas development could be especially challenging. Although the Arctic is rich in natural gas, the development of Arctic natural gas resources could be impeded by the low market value of natural gas relative to that of oil. Furthermore, natural gas consumers live far from the region, and transportation costs of natural gas are higher than those for oil and natural gas liquids.

Overlapping and disputed claims of economic sovereignty between neighboring jurisdictions also could be an obstacle to developing Arctic resources. The area north of the Arctic Circle is apportioned among eight countries—Canada, Denmark (Greenland), Finland, Iceland, Norway, Russia, Sweden, and the United States. Under current international practice, countries have exclusive rights to seabed resources up to 200 miles beyond their coast, an area called an Exclusive Economic Zone (EEZ). Beyond the EEZ, assessments of "natural prolongation" of the continental shelf may influence countries' seabed boundaries.

Along with economic and political challenges, environmental stewardship and regulatory permitting may also affect timelines for exploration and production of Arctic resources. Environmental issues include the preservation of animal and plant species unique to the Arctic, particularly tundra vegetation, caribou, polar bears, seals, whales, and other sea life. The adequacy of existing technology to manage offshore oil spills in an arctic environment is another unique challenge. Spills among ice floes can be much more difficult to contain and clean up than spills in open waters.

See further information on the Arctic's energy resources and the challenges associated with their development in the December 21, 2011 edition of  This Week In Petroleum.

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EIA: Brent Crude Oil Averages Over $100 Per Barrel in 2011

Source: U.S. Energy Information Administration, based on Thomson Reuters.
Note: Brent is the underlying crude oil for the light sweet crude oil futures contracts on the Intercontinental Exchange (ICE). West Texas Intermediate (WTI) represents the spot price for crude oil at Cushing, Oklahoma, the physical delivery hub for NYMEX light sweet crude oil futures contracts.

The crude oil markets sustained high price levels in 2011, as the spot price of Brent averaged $111.26 per barrel, marking the first time the global benchmark averaged more than $100 per barrel for a year (see chart above). The West Texas Intermediate (WTI) crude oil price averaged $94.87 per barrel, up $15 per barrel from 2010, reflecting a discount to the Brent crude oil price due to transportation bottlenecks near Cushing, Oklahoma, the physical delivery hub for NYMEX light sweet crude oil futures contracts.

The price increases in 2011 reflected tightness in the global crude oil market that began in 2010 and marked the highest crude oil prices since 2008. Key factors affecting crude prices in 2011 included:

• Arab Spring. The Arab Spring and the civil war in Libya roiled oil markets during the first half of the year. Prices quickly escalated when protests in Libya intensified in late February. The spot price of Brent increased $15 per barrel from February 18 to March 2 as the market coped with the loss of 1.5 million barrels per day (bbl/d) of exports from Libya. With low spare production capacity, this sudden supply loss challenged the ability of the Organization of the Petroleum Exporting Countries (OPEC) producers to provide incremental supplies to an already tight market.
• Demand. Demand growth in emerging markets, notably China and the Middle East, drove crude oil prices higher in 2011 as well. During the first six months of 2011, the demand for petroleum products in countries not part of the Organization for Economic Cooperation and Development (non-OECD) grew by almost 4%, just as the market was coping with the loss of Libyan exports. Even with declining OECD country demand in 2011, overall global demand rose by 1.2% (1.1 million bbl/d).
• Transportation Bottlenecks. Brent's price strength in the first half of 2011 was not matched by WTI, which became dislocated from the global crude oil market due to transportation bottleneck issues in the U.S. Midwest (see chart below). Amid fast-rising crude oil production from the Bakken Shale formation and Canadian oil sands, prices for U.S. inland crude benchmark WTI weakened relative to those of broadly traded coastal or imported crude oil grades, such as Brent or Louisiana Light Sweet (LLS). Brent's premium to WTI reached a record level of almost $30 per barrel in September 2011. Between October and November the premium fell almost $20 per barrel, most likely as a result of signs that transportation constraints out of the U.S. Midwest, the main market for WTI, were easing. However, the spread ended the year close to $10 per barrel, still wide by historical standards.

Source: U.S. Energy Information Administration, based on Thomson Reuters.

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While WTI experienced a wide trading range in 2011, as its isolated market depressed the crude's value, Brent and other waterborne crudes maintained a fairly stable trading range anchored around $110 per barrel from May through the end of the year. Factors mitigating upward crude oil price pressure in 2011 included:

• Debt Crisis. The European debt crisis loomed large over the global economy, and expectations for economic growth globally, especially in the OECD economies, were not realized over the course of the year, resulting in lower-than-expected growth in demand for petroleum products.
• Strategic Petroleum Release. In response to the loss of Libyan supplies, the International Energy Agency's member countries collectively released stocks from their strategic petroleum reserves during the summer months.
• Supply Gains. Output increases from Saudi Arabia (OPEC's largest producer) and the return of Libyan oil production helped dampen price increases during the second half of the year.

Could Crude Oil Prices Intensify a Pending SP 500 Sell Off?

EIA: Current Natural Gas Forward Prices Signal Rising....But Still Low Prices in 2012

Source: U.S. Energy Information Administration, based on Bloomberg.

Note: Forward prices are derived each month (January-December) by adding the locational basis swap to the NYMEX Henry Hub futures price for the given month at each location. The ranges reflect the minimum and maximum monthly price for months in 2012. For example, a January 2012 NYMEX Henry Hub futures contract valued at $3.50/MMBtu and a January 2012 Transco Zone 6-NY basis swap valued at $2.50/MMBtu would yield a $6.00/MMBtu price at Transco Zone-6 NY.

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Natural gas forward market prices (as of December 28, 2011) signal a continuation of low natural gas prices into 2012. Winter 2011-2012 forward prices were recently the lowest in over ten years, and, of the eight trading points identified, only Transco Zone 6-NY (New York City) and PG&E Citygate (Northern California) show 2012 forward monthly price ranges that include prices above $4/MMBtu. Natural gas spot prices remained low throughout 2011 relative to prior years, reaching a two-year low in November. The spot natural gas price at Transco Zone 6 New York, shown in the graph, is above next year's average monthly trading ranges due to recent cold weather-driven demand. Current spot natural gas prices are lower than the 2012 forward contract range at several natural gas trading points identified in the chart.

The natural gas price at the Henry Hub in Louisiana informs much of the rest of the country, with prices largely following price movements at Henry. Similarly, forward prices, except for the Northeast (represented here by the Transco Zone 6-NY trading point), closely mirror 2012 forward prices at the Henry Hub. Northeast gas prices behave differently, with spot and forward prices higher during colder months due to expectations regarding pipeline constraints in transporting natural gas to the Northeast during times of high natural gas demand.

Source: U.S. Energy Information Administration, based on Ventyx's Energy Velocity Suite.

EIA: Market Changes Contribute to Growing Marcellus Area Spot Natural Gas Trading

Marcellus-area spot natural gas trading (InterContinentalExchange (ICE) day-ahead transactions) has more than doubled from under 1 billion cubic feet per day (Bcfd) to almost 2 Bcfd on average since 2005 (see chart). The largest gains in Marcellus area trading volumes were at the Tetco M3 trading point, up 178% to 0.5 Bcfd and at the Dominion South trading point, up 168% to 0.7 Bcfd since 2005. Key factors likely contributing to increased natural gas spot trading in the Marcellus area include: rapid increases in Marcellus shale gas production; direct deliveries of Wyoming gas to the Ohio/Pennsylvania border through the Rockies Express Pipeline; and increased use of natural gas for power generation.

Source: U.S. Energy Information Administration, based on Ventyx's Energy Velocity Suite.

Note: New Marcellus in the graph includes the Leidy, TGP 219, TGP 313, and TGP Zone 4 Marcellus trading points. 2011 includes data through November.

 Several factors are likely contributing to increased natural gas spot trading in the Marcellus area:

• Marcellus production gains. Bentek Energy, LLC estimates that Marcellus natural gas production now exceeds 4 Bcfd, up significantly in recent years.
• New trading points. In addition to several new Marcellus production area trading points, the extension of the Rockies Express Pipeline (REX) to Clarington, Ohio led to new natural gas trading points formed to facilitate commercial transactions. REX deliveries to Clarington, Ohio averaged over 1 Bcfd from January through December of 2011.
• Greater reliance on natural gas for electricity generation. Falling natural gas prices coupled with historically high spot coal prices created incentives for generators to use more natural gas to fuel their plants. Pennsylvania is one state that has seen significant growth in natural gas-fired electric generation.

Source: U.S. Energy Information Administration, based on Ventyx's Energy Velocity Suite. 

Residual Fuel Consumption in the U.S. Continues to Decline

After reaching a high point of over three million barrels per day (bbl/d) in the late 1970s, demand for residual fuel oil in the United States has steadily declined (product supplied as seen in the chart above is a proxy for demand). Residual fuel is used as fuel for large ships and for electricity generation, industrial process and space heating, and other industrial purposes. Between 2000 and 2010, average annual residual fuel use fell from approximately 900,000 bbl/d to 500,000 bbl/d. It averaged nearly three times that in the 1940s and 1950s. As its name implies, residual fuel oil is the remaining fraction resulting from the crude oil refining process. Because residual fuel is a heavy product, it has limited uses and relatively high emissions.

Source: U.S. Energy Information Administration, Petroleum Supply Monthly.
Note: Product supplied is a proxy for demand.
Download CSV Data

Changes on both the residual fuel supply and demand side of the equation are contributing to the downward trend.

Demand The demand-side landscape for residual fuel has changed over the course of the past few decades, particularly in the electric power sector. From 2000 to 2005, natural gas and oil prices tracked closely. Since 2006, the prices of these two fuels decoupled, as rapidly increasing supply drove natural gas prices down. As a result, the power sector began relying more on natural gas and less on residual fuel, except in circumstances where spot natural gas prices soared due to weather-related constraints. Other exceptions include Hawaii, which relies on residual fuel for much of its power generation (58% in 2010). To a lesser degree, Alaska and Florida use residual fuel, and in-city generators in New York City must use a minimum of residual fuel to meet reliability requirements. Other factors accounting for declining generation at residual-fired plants include: the availability of more efficient natural gas combined-cycle units, increased stringency of air emissions, and at times rising sulfur dioxide emissions costs.

Aside from the electricity sector, other major demand sectors, such as transportation, have not seen much change in residual demand over the same period. Residual fuel, often called bunker fuel in this context, continues to power large ships.

Source: U.S. Energy Information Administration, Fuel Oil and Kerosene Sales.
Download CSV Data

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Supply The supply of residual fuel oil from domestic refining has also declined. U.S. refinery yield for residual fuel oil dropped from 5.8% in 1993 to 3.8% in 2010. Refinery yield represents what finished petroleum products are made from crude oil run through refineries' crude distillate units and other downstream processes. Lighter petroleum products, such as motor gasoline and ultra low sulfur distillate, command higher market prices. Therefore, refineries focus their operations to maximize production of those products. By investing in more sophisticated downstream unit capacity, refineries can increase the amount of lighter products from each barrel of crude, and, as a result, lessen the production of heavier products such as residual fuel oil.

Due to rising gross exports and falling gross imports, the United States became a net exporter of residual fuel oil in 2008 (see chart below). U.S. gross exports of residual fuel oil increased steadily since the early 1990s. Additionally, after a sharp decline in gross imports from a high of more than 1,800 thousand barrels per day in 1973 to a low of less than 200 thousand barrels per day in 1995, gross imports have averaged about 350 thousand barrels per day over the last 10 years.

Source: U.S. Energy Information Administration, Petroleum Supply Monthly.
Download CSV Data

Phil Flynn: It’s Beginning to Look a Lot Like!

It's beginning to look a lot like rates cuts, everywhere you go. Take a look at the ECB cutting rates again, with oil gains and silver bulls a-glow! It’s beginning to look a lot like rate cuts, maybe even Quantitative easing in store but the prettiest sight to see is the moment that you see oil put in a floor.

It’s all about Europe and the market expects the European Central Bank will cut rates by another quarter-point to 1%. Of course the market already wants more and hopes the ECB will add a little quantitative easing to help stimulate the economy. The market would like to see the Euro zone flush with cash ahead of its "do or die" Brussels summit as the fate of the Euro currency and the credibility of Europe hangs in the balance.

For oil the increasing prospect of a deal is very bullish. Not only will it improve demand it will devalue paper currencies that are abundant and will start too chase some goods including oil. Remember always that bailouts are bullish.

Yet yesterday’s Energy Information Report wasn’t really. The trade was shocked by a surprise build in commercial crude oil inventories which increased by 1.3 million barrels from the previous week. The expectations were that supply would fall as refiners and oil companies began to draw down inventory for year end tax considerations.

The other big story from the report was distillate inventories. The EIA said that distillate fuel inventories increased by 2.5 million barrels last week and are in the lower limit of the average range for this time of year. David Bird, the man that mashes the statistics for Dow Jones, says that, "US output of distillate fuel (diesel/heating oil) rose 4.2% to a record 5.03M barrels/day last week, EIA data show, as weekly demand was 7% above a year ago at 3.92M. Exports have been very strong of late and the EIA estimates distillates averaged a daily record near 950K barrels. The production surge helped push inventories up 2.5M barrels last week and within 2.5% of the 5-year average, the narrowest gap since October.”

Gasoline supply also surged increasing by 5.1 million barrels last week and are in the upper limit of the average range. Gasoline supply builds are the beneficiary of strong diesel demand and record distillate production. Total commercial petroleum inventories increased by 9.5 million barrels last week.

Still the overall outlook for oil is still bullish. The distillate production number indicates that refiners expect continuing strong global demand.

President Obama is still fighting the Keystone pipeline despite angering our neighbors to the North, Canada and despite the fact that the pipeline is favored by the majority of the American People. The President warned Republicans he'll veto an extension of the payroll tax if it includes a measure that forces the approval of the Keystone oil sands pipeline. Once again the President is putting his special interests ahead of US job creation and improving our nation’s energy security.

Hello shale and goodbye to coal! In a must read in Today’s Wall Street Journal it is reported that “naural gas will replace coal as the leading fuel for generating electricity in the U.S. by 2025, when it will also become the world's No. 2 overall fuel source thanks to its abundance and a drive for cleaner burning energy, according to the latest long term outlook from Exxon Mobil Corporation.

The closely watched study, set to be released Thursday, forecasts that global energy demand will grow about 30% by 2040 as the world population climbs to nine billion from seven billion.

Natural gas will overtake coal as the second largest fuel source overall, ranking behind oil and powering everything from electrical plants to home heating systems. But Exxon said coal use will continue to grow through 2025 around the world, primarily in developing nations such as China and India and the African continent, because economic growth will be fastest in emerging nations.

But thereafter coal use will start to drop, for the first time in history, according to the study, which Exxon uses to help its long range planning. Key drivers in that expected drop in coal use will be growing demand for fuels that produce fewer greenhouse gases and a decline in China's population expected after 2030.

Exxon in recent years has moved to expand its natural gas business, including the $25 billion purchase of U.S. shale gas producer XTO Energy in 2010.” Don’t miss it!

The CME is looking into a new crude contract. The CME is thinking about a possible futures contract that could be physically settled with delivery to the Gulf Coast. Stay tuned!

I hate to say I told you so, but I did tell you that Libya’s oil production would come back much faster than expected. The EIA confirmed that saying that pace of Libya's re entry into world oil markets has exceeded our prior expectations and those of many other outside observers.” {not mine!} While opinions vary significantly on the eventual trajectory for Libyan oil production, nearly all forecasts have steadily shifted upwards as the country's oil sector and related institutions continue to progress.

The EIA says that “Libya’s National Oil Corporation (NOC) claims to be on track to meet its goal of returning to pre-war crude oil production levels of 1.65 million barrels per day (bbl/d) by the end of 2012. Most analysts now expect production to reach anywhere between 1.0 and 1.6 million bbl/d during that timeframe. Based in part on developments in recent weeks (Table 1), the U.S. Energy Information Administration (EIA) expects that Libyan output may ramp up to 1 million bbl/d by the beginning of the second quarter of 2012. Thereafter, EIA expects crude oil production to plateau somewhat, increasing only gradually to about 1.2 million bbl/d by the end of 2012, along an uneven and non linear path.”

EIA gas report today! The street is looking for a 13 withdrawal! I say 3. Get a trial to Phil's daily trade levels by emailing him at pflynn@pfgbest.com


Gold’s 4th Wave Consolidation Nears Completion and Breakout

WTI and Brent Price Spread Narrows

Between October and November, the spot price of West Texas Intermediate (WTI) crude oil increased $23 per barrel partly on signs that transportation constraints out of the U.S. Midwest, the main market for WTI, are beginning to ease. At the same time, the price of European benchmark Brent crude oil was up much less, only about $7 per barrel. As a result, the WTI-Brent crude oil price difference has narrowed. The WTI-Brent crude oil price difference was smaller earlier in the year. While the WTI-Brent oil price narrowed, gasoline prices continue to track the price of Brent as they have for much of the year. The average price for gasoline moved about 6 cents a gallon from early October through mid November and then fell 13 cents during the last two weeks of November.

Source: U.S. Energy Information Administration, based on Bloomberg.  

Gold’s 4th Wave Consolidation Nears Completion and Breakout

Proposed KMI and El Paso Merger Would Create Largest U.S. Natural Gas Pipeline Company

The proposed merger of Kinder Morgan Inc. (KMI) and El Paso Corp. (El Paso) announced on October 16, 2011 would create the nation's largest natural gas pipeline company. If approved by state and federal regulatory officials, the combined company would operate about 67,000 miles of natural gas pipelines (see the blue and red lines in the map), or about 22% the U.S. natural gas pipeline network. Upon closing, the proposed $38 billion transaction would be one of the biggest natural gas pipeline mergers in United States history.

El Paso's natural gas pipeline network complements Kinder Morgan's natural gas system. By adding El Paso's network to its own, KMI increases its access to natural gas markets in the Southwest, Southeast, Northwest, and Northeast. El Paso has been extending its reach into these markets. In 2011, El Paso completed three major pipeline projects: Ruby Pipeline, Florida Gas Transmission Phase VIII, and Tennessee Gas Pipeline 300 Line, in total adding around 1,200 miles and 2.6 billion cubic feet per day of capacity to its network.

Source: U.S. Energy Information Administration, based on SNL Financial.

Note: The labeled brown bars represent the four largest deals since 1996. Total transaction value only includes completed and pending deals based on the announcement year.
*Pending transaction

As measured by total dollars, 2011 has been a significant year so far for mergers and acquisitions in the natural gas transmission sector compared with previous years. The proposed merger between Kinder Morgan and El Paso could be the largest U.S. pipeline related merger and acquisition since 1996, representing about 54% of the total transaction value of proposed or concluded mergers so far in 2011, according to SNL Financial.

On June 15, 2011, Energy Transfer Equity agreed to acquire Southern Union for $9.2 billion, making it the second largest pending natural gas pipeline-related deal in 2011. Since 1996, three natural gas transmission mergers and acquisitions deals over $20 billion were concluded according to data from SNL Financial: a $22 billion deal between El Paso and Coastal Corp in 2000; a $21 billion leveraged buyout deal of Kinder Morgan by a group of private investors in 2006; and a $20 billion deal between Enterprise Products Partners and Enterprise GP Holdings in 2010.


Is This December Similar to 2007 & 2008 for Gold & Stocks?

Over One-Third of Natural Gas Produced in North Dakota is Flared or Otherwise Not Marketed

Source: U.S. Energy Information Administration, based on the North Dakota Department of Mineral Resources.

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Natural gas production in North Dakota has more than doubled since 2005, largely due to associated natural gas from the growing oil production in the Bakken shale formation. Gas production averaged over 485 million cubic feet per day (MMcfd) in September 2011, compared to the 2005 average of about 160 MMcfd.
However, due to insufficient natural gas pipeline capacity and processing facilities in the Bakken shale region, over 35% of North Dakota's natural gas production so far in 2011 has been flared or otherwise not marketed. (It is generally better to flare natural gas than to vent it into the atmosphere because natural gas—methane—is a much more powerful greenhouse gas than carbon dioxide.) The percentage of flared gas in North Dakota is considerably higher than the national average; in 2009, less than 1% of natural gas produced in the United States was vented or flared.

Natural gas production in the Bakken shale. North Dakota natural gas production from the Bakken shale, which is situated in the northwest portion of the State, increased more than 20-fold from 2007 to 2010, and the number of wells producing natural gas increased 7-fold.

Source: U.S. Energy Information Administration, based on the North Dakota Department of Mineral Resources.

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Natural gas infrastructure. The necessary natural gas infrastructure—gathering pipelines, processing plants, transportation pipelines—surrounding the Bakken shale play has not expanded at the same pace, effectively stranding the natural gas that is produced during oil production. A 2010 report by the North Dakota Pipeline Authority highlights an example of this, stating that one county was able to reduce its flaring from December 2008 to December 2009 by 62% with the addition of two new natural gas plants and the expansion of associated gas gathering systems. The report also details several other projects that have either come online recently or are planned to for the immediate future, which may reduce the amount of natural gas flared.

Natural gas flared or otherwise not marketed. The North Dakota Department of Mineral Resources estimated that in May 2011, nearly 36% of the natural gas produced did not make it to market. Most of this gas—29% of the total gas produced—was flared. The remaining natural gas that did not make it to market—7% of total gas produced—is unaccounted for or lost, which means the gas may have been used as lease and plant fuel, or encountered losses during processing or transportation.

Natural gas flaring regulations. According to current North Dakota state regulations, producers can flare natural gas for one year without paying taxes or royalties on it, and can ask for an extension on that period due to economic hardship of connecting the well to a natural gas pipeline. After one year, or when the extension runs out, producers can continue flaring but are responsible for the same taxes and royalties they would have paid if the natural gas went to market.

EIA: Rail Delivery of Crude Oil and Petroleum Products Rising

More U.S. crude oil is being shipped by rail, especially from North Dakota where a lack of pipelines has companies relying on tank cars to bring the state's soaring oil production to market. Pipelines remain the most popular transport option, carrying about two thirds of U.S. oil and petroleum products, but rail is on the rise.

The Association of American Railroads (AAR) tracks combined rail movements of oil and refined petroleum products. In the first ten months of 2011, nearly 300,000 tank cars transported U.S. oil and petroleum products, up 9.1% from the same period in 2010, according to AAR. The growth in petroleum by rail shipments is much stronger than the 1.8% increase for all railroad cargo combined during the same period.

While AAR does not issue separate data on crude oil and product shipments via rail, it notes that anecdotal evidence indicates most of the growth in the crude oil and petroleum products category is likely due to crude shipments. Based on different sources of rail traffic data, the trade group said shipments of crude oil and liquefied natural gas accounted for about 2% of all carloads in 2008, 3% in 2009, 7% in 2010, and about 11% so far in 2011. One carload holds 30,000 gallons of oil.

Tank cars are in strong demand in North Dakota, where oil production has soared from about 343,000 barrels per day (bbl/d) in January to a record high of about 464,000 bbl/d in September, according to North Dakota's Department of Minerals Resources (DMR), due to the increasing amount of crude oil extracted from rock in the Bakken Shale. DMR expects North Dakota will pass California during the second quarter of next year to become the third biggest oil-producing state. Burlington Northern Santa Fe (BNSF) and other railway companies are building or expanding terminals and adding tank cars to transport North Dakota's growing oil supplies to Gulf Coast refineries.

On November 7, the first crude oil unit train on the Bakken Oil Express, a newly constructed rail hub near Dickinson, North Dakota, departed via the BNSF Railway carrying its first shipment, 70,000 barrels of crude oil destined for St. James, Louisiana. The Bakken Oil Express receives Bakken-area crude oil by both truck and pipeline and has a current takeaway capacity of 100,000 bbl/d. The Bakken Oil Express is already planning a second phase of construction that would significantly expand its takeaway capacity to more than 250,000 bbl/d.

Deliveries of tank cars should total about 8,000 this year, up from only 4,839 last year, and then increase to 11,000 tank cars in 2012, according to Economic Planning Associates Inc., a consulting firm that tracks rail car assemblies. The firm does not have a breakdown of how many of the new tank cars will be devoted to carrying crude oil. Tank cars are also used for shipping ethanol, chemicals, fertilizer, and corn syrup.

Tank cars would also be useful in the major oil hub of Cushing, Oklahoma, where a glut of supply is depressing the key U.S. benchmark crude oil price. Pipelines bringing oil into Cushing from the north are nearly full and there is not enough pipeline infrastructure to move oil south out of the area to Gulf Coast refineries. The Surface Transportation Board (STB), the federal agency that resolves railroad rate and service disputes and reviews railroad mergers, told EIA that it saw little movement in recent months of crude oil out of Cushing by rail. Railway companies send the STB confidential information on their cargo shipments and where they are sending them.

Source: U.S. Energy Information Administration, based on the Association of American Railroads.
Note: Data are weekly average originations for each month, are not seasonally adjusted, and exclude U.S. operations of Canadian National Railways and Canadian Pacific Railway; one carload holds 30,000 gallons.

Phil Flynn: The Great Energy Divide

There is a growing gap is this country between the haves and have nots. This is what I call the great energy divide. If you heat with natural gas you are the fortunate and if you heat with heating oil, well boy, you are in trouble. Once again heating oil soars as US supply is dangerously low and strong demand elsewhere around the globe is keeping our supply tight.

The good news is that as refiners ramp up production to meet heating oil demand, the beneficiary will be gasoline as supply should surge because demand is still weak. This of course opens up a host of spread opportunities whether you are talking about the " Widow Maker", heating oil versus gasoline spread or even the Brent versus WTI spread and the gasoline vs crack could fall while the heat vs crack could rise. The best part is that volatility, the mother's milk of the oil speculators, will continue to run high.

This of shortage has been building for weeks. We wrote about how the heat oil gasoline spread had widened. At the same time we have seen the gas crack tank and the Brent versus WTI spread come back in. At the same time US refiners expected strong demand for WTI crude is one of the reasons that this market may just kiss $100 a barrel. Heat oil is probably headed to above $3.20 so other than worrying about Italy's bond yields or whether the next Greek Prime Minister is going to be Papademos or Popinfresh, oil traders have to watch the supplies of distillates closely as they are the tightest they have been in about four years.

Of course natural gas users are in heaven. While natural gas storage is down 0.2 percent from last year, record supply natural gas stocks should set a new record because of above average temperatures that are being forecast. The EIA said that the week ending Nov. 4, the country's natural gas stockpiles fell 6 billion cubic feet from last year at this time, coming in at 3,831 bcf and increased by a more than expected 37 bcf increase from last week. Stocks are now a whopping 215 bcf above the 5 year average.

Traders are going long heat short natural gas and nat gas prices for the strip are near historic lows for this time of year......Read the entire article.


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How Cheap is Natural Gas?

How cheap is natural gas? The EIA tells us winter (November-March) natural gas futures prices are near their lowest levels since 2001-2002.

The average natural gas futures price for the upcoming winter is less than $4 per million British thermal units, the lowest level entering the winter since 2001-2002. The so called "winter strip," the average natural gas futures price for the contract months November through March as settled on the New York Mercantile Exchange is a closely followed measure of market participants' price expectations.

In markets such as New England and California, where natural gas prices often set on peak, wholesale power prices, the NYMEX winter strip for natural gas also can influence expectations for forward wholesale power prices.

Source: U.S. Energy Information Administration, based on Bloomberg, L.P.
Note: October 20 was selected because it represents a date near the start of the natural gas winter heating season yet still has information for five months of the upcoming winter's natural gas NYMEX future's strip.


These prices do not reflect expectations for the cost of transporting natural gas from Henry Hub to downstream market locations. The Henry Hub, in Erath, Louisiana, is the physical delivery location for the NYMEX natural gas futures contract. Sabine Pipeline is the operator of the Henry Hub. 

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EIA: Recent Gasoline and Diesel Prices Track Brent and LLS, not WTI

Since the beginning of 2011, the spot price of West Texas Intermediate (WTI) crude oil, a traditional benchmark for the U.S. market, has trailed the spot price of other crude oils, including Brent, a global benchmark, and Louisiana Light Sweet (LLS), a Gulf Coast crude oil similar to crudes run by many U.S. refiners. Because few U.S. refiners have easy access to WTI crude oil, this price divergence has not directly translated to lower prices for U.S. refined petroleum products, such as gasoline and heating oil.

Instead, these product prices have more closely tracked the prices of Brent and LLS. Through October 25, the prices of Brent and LLS are up 20% and 18% in 2011, respectively; the prices of wholesale diesel fuel and gasoline on the U.S. Gulf coast are up 21% and 13%, respectively; meanwhile, the price of WTI is up just 2%.

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Phil Flynn: Gulf Coast Surprise

What fun is an oil inventory report without a little surprise now and then. The Gulf Coast, famous for its beautiful beaches, its spicy cuisine, and let's not forget to mention its oil refineries and oil import terminals, gave the weekly EIA data a Louisiana kick. A surge in Gulf Coast oil imports caused a large, whopping jump in U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) of 4.7 million barrels from the previous week. That puts supply at 337.6 million barrels and keeps it in the upper limit of the average range for this time of year. Thanks to that Gulf Coast surge!

But let's go even further south, down to Brazil! Blame it on Rio! Well not yet anyway but in the future Brazil is going to be a major oil player. The EIA said that, "Brazil will be responsible for some of the world's largest increases in oil production in the coming decades. Advances in seismic imaging have enabled the discovery of offshore "pre salt" deposits of oil in Brazil's Campos and Santos Basins.

These pre salt fields, so-called because they lie under massive layers of salt, are located 18,000 feet below the ocean floor under more than 6,000 feet of salt. Brazil already produces 2.1 million barrels per day (bbl/d) of crude oil and lease condensate, yet just became a net exporter in 2008. Pre salt development, coupled with the ability to meet a large share of domestic demand with Biofuels, is projected to transform the country into a major oil exporter."

You might also blame Rio for the drop in distillates. The EIA say's distillate fuel inventories decreased by 4.3 million barrels last week and are in the middle limit of the average range for this time of year. The drop comes as demand surges for diesel as harvest is underway.

Yet demand for gasoline continues to be poor. The EIA says motor gasoline inventories decreased by 1.4 million barrels last week and are near the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week.

What will be the surprise for today? My guess is a bigger than expected injection on gas storage! Report today!

Sign up for a trial of Phil's daily trade levels! Just email him at pflynn@pfgbest.com

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EIA Launches New Electricity Focused Web Page

Yesterday, EIA launched a new web based report called the Electricity Monthly Update, replacing the Monthly Flash Estimates for Electric Power Data. This new product introduces a feature story, interactive graphics, a new presentation flow, and new electricity industry data sources.

Source: U.S. Energy Information Administration, Electricity Monthly Update.

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EIA: Libya Resumes Natural Gas Exports to Italy

On October 13, 2011, Libya resumed natural gas exports to Italy via the 340-mile, Greenstream Pipeline (Greenstream), which is jointly owned by the Eni S.p.A. and the National Oil Company of Libya. Natural gas  delivery imports to Sicily, Italy, at the Gela receipt point, are now about 150 million cubic feet per day (MMcf/d).

Source: U.S. Energy Information Administration, based on Bentek Energy, LLC.

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Since February, unrest in Libya resulted in curtailed natural gas exports to Italy. Prior to the February curtailment, Libya supplied Italy with about 900 MMcf/d of natural gas, or 11% of Italy's average daily gas demand in 2010. Italy offset much of the reduced natural gas imports from Libya with increased imports of natural gas from Russia.



After natural gas flows resumed following the disruption, natural gas flowed from the onshore Wafa field about 300 miles southwest of Tripoli to Italy. Natural gas production at Wafa remained open during the crisis  and supplied natural gas to Libyan power plants. Most of Greenstream's natural gas usually comes from the offshore Bahr Essalam field (see map); only those volumes from Wafa in excess of domestic consumption are  available for export via Greenstream.

Oil N' Gold: Drop in Crude Inventory Fails to Alter the Downtrend

Total crude oil and petroleum products stocks declined -4.63 mmb to 1074.56 mmb in the week ended September 30. Crude stockpile fell -4.68 mmb to 336.28 mmb as 3 out of 5 PADDs recorded stock draws and Gulf Coast inventory plunged -5.24 mmb. Cushing stock also fell -0.83 mmb to 30.09 mmb. Utilization rate fell -0.1% to 87.7%.

Gasoline inventory dropped -1.14 mmb to 213.72 mmb although demand slipped -0.06% to 8.989M bpd. Imports dropped -6.65% to 0.51M bpd while production edged up +0.08% to 9.29M bpd during the week. Distillate inventory slipped -0.74 mmb to 156.93 mmb as demand jumped +7.39% to 4.10M bpd. Production gained +2.37% to 4.67M bpd while imports soared +36.67% to 0.21M bpd during the week.

WTI crude oil price rebounded to 78.84 after the report as crude inventory surprisingly fell. Distillate and gasoline stockpiles were also down during the week. However, the near-term outlook remained dismal amid global economic concerns and worries about European sovereign crisis.


A Comparison between API and EIA reports at Oil N' Gold


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EIA Report: World Wide Energy Use Expected to Increase 53% by 2035

In a statement released on Monday the EIA, the U.S. Energy Information Administration, predicts that the worlds energy consumption will increase by as much as 53% by 2035. in China and India.

Todays report, the 2011 International Energy Outlook, predicts that consumption of energy from renewable and alternative sources will be the fastest growing in the energy sector. Reaching 15% of the world energy use by 2035 compared to 10% in 2008. But fossil fuels will still be the world's dominant source, accounting for about 78% of the world's energy use in 2035.

The EIA said it expects oil prices to remain high, reaching $125 per barrel in 2035, but added that consumption of oil will still grow during that period.

The EIA also predicts that petroleum prices are "very sensitive to both supply and demand conditions" and that prices could fall to $50 per barrel or approach $200 per barrel, depending in part of the rate of economic growth in developing countries.

The EIA report projects changes in world energy markets between 2008 and 2035. It doesn't take into account the potential impacts of policy changes that have not yet been implemented.

One area that will be particularly sensitive to policy actions: competition between coal, natural gas, and renewable sources to meet electricity demand, said Howard Gruenspecht, the acting EIA administrator, during a speech at the Center for Strategic and International Studies.

The report projects, absent policy changes, tremendous growth in coal consumption by China and to a lesser extent India and other developing countries. That growth is a key driver of a projected increase in worldwide carbon dioxide emissions, which EIA predicted would jump about 43% between 2008 and 2035. China's carbon emissions were somewhat higher than those of the U.S. in 2008, but are projected to be "more than twice as high" as U.S. emissions by 2035, Gruenspecht said.

Natural gas consumption was projected to grow at a faster rate than any other type of fossil fuel, thanks in part to increased supply from the U.S. and elsewhere. Consumption will grow from 111 trillion cubic feet in 2008 to 169 trillion cubic feet in 2035, the report predicted.

Use of nuclear power increases slightly in the EIA projections, but "the full extent of the withdrawal of government support for nuclear power is uncertain" in the wake of the Fukushima Daiichi crisis in Japan, Gruenspecht said.

Gruenspecht said that due to budget cuts impacting the EIA, the outlook report might not be released next year. "That's a little bit of question mark in the present resource environment."


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