Crude Oil Seasonality, Inventory Rebalancing and Production Cuts

The historical stock build from December 2014 through July 2016, and subsequent decline from August through December has led some to conclude that global stocks had started to rebalance. Instead, the normal seasonality in stocks had been masked by the high overproduction of OPEC, but then normal seasonality kicked in.

Global OECD inventories from past years demonstrate the normal seasonal patterns, with some variability. As shown in this graph, stocks normal build early in the year and peak around August. Stocks normally drop from September through December. But in 2015, the oversupply was so excessive that stock just kept building through the year. They finally peaked in July 2016, then dropped off due to normal seasonal demand. This normal pattern led to a false conclusion that the rebalancing of stocks had begun.

But according to Energy Department data, OECD stocks in March 2017 are 13 million barrels higher than December. And it projects that stocks are likely to peak in May this year, earlier than normal, but to end 2017 with stocks just 14 million lower than a year ago. This is based on the Energy Information Administration ((EIA)) assumption that OPEC does not hold production to its March level. Furthermore, the EIA projects global stocks to set new record highs in 2018, after the OPEC non OPEC cuts presumably end.

Effect of Production Cuts

Some argue that the 285 million barrel excess above the 5 year average as of the end of December should disappear in five to six months by dividing 285 million by 1.8 million barrels per day, the agreed upon size of the daily cut. But that math first assumes that supply was in balance with demand, makes no allowance for rising supplies, such as in the U.S., and it does not take into account the seasonality.

According to OPEC’s figures, global OECD stocks are likely to build both in the first and second quarters, and then decline in the second half of the year, assuming OPEC production remains at the March level.

There was one development last week, if true, did shift the inventory trend lower. The EIA revised its December estimate of OECD stocks down 105 million barrels, a major revision. That reduced the size of the glut to 201 million above its five year average.

Conclusions

The market dropped sharply in early March as a result of the continued rise in stocks. The market has falsely expected to see inventories to soon decline as a result of the production cuts. But seasonal factors need to be taken into account. We should see global stocks decline in the second half of 2017, assuming OPEC extends its cuts. And the decline may start earlier than normal because U.S. refinery utilization is ramping up faster and earlier than usual, thereby requiring more crude oil.

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Best,
Robert Boslego
INO.com Contributor - Energies

Bears Run For Cover!

From our trading partner Phil Flynn....

Ultra bears are starting to change their tune on oil as weak Chinese manufacturing data and strong manufacturing data in Germany both point to better demand. China's demand may rise as the Chinese government will be forced to act swiftly to reach their growth target and should soon add stimulus increasing oil demand. Factory activity in China fell to 49.2, according to HSBC, a number that should force the Chinese government's hand.

In Germany, we are already seeing the QE impact on oil demand. The Purchasing Managers Index for the manufacturing and services industries across the region rose to a much stronger than expected 54.1 ked by a 0.4 percent expansion in Germany. Germany is the beneficiary of being the strongest economy in the Eurozone at a time when the ECB central bank has launched unprecedented stimulus. On top of that you see the U.K. inflation rate come in at the lowest rate in history. The inflation rate fell below zero for the first time in history and all of a sudden this QE madness is likely to continue.

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Now one might think that might be bearish as the dollar might continue its historic upward move as the rate differential outlook could cause continued safe haven buying. But now it seems that the Fed may be influenced into not rating rates quickly as the dollar strength is causing more problems. We saw in the FOMC that Fed Chair Janet Yellen warned that the Fed will not be impatient in raising rates. The Fed's Stanley Fischer suggested that the Fed will be data, and perhaps dollar dependent on raising rates and warned that there would not be a "smooth upward path" for interest rates hikes.

Oil bears are also counting on another big inventory increase. Yet data from Genscape, the private forecaster, is suggesting that the build might be much less than the 4 million barrel builds that is being bandied about. Genscape reports that the increase of less than 2 million barrels are around 1.6 million. That should reduce fears of storage over flowing. In fact the Energy Information Administration reported that although inventory levels at Cushing are at their record high, storage utilization (inventories as a percent of working storage capacity) are not at record levels. Capacity utilization at Cushing is now 77%, a large increase from a recent low of 27% in October 2014. However, utilization reached 91% in March 2011, soon after EIA began surveying storage capacity twice a year, starting in September 2010."

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EIA: Mexico's Energy Ministry Projects Rapid Near Term Growth of Natural Gas Imports from U.S.

 A combination of higher natural gas demand from Mexico's industrial and electric power sectors and increased U.S. natural gas production has resulted in a doubling of U.S. pipeline exports of natural gas to Mexico between 2009 and 2013. Mexico's national energy ministry, SENER, projects that U.S. pipeline exports to Mexico will reach 3.8 billion cubic feet per day (Bcf/d) in 2018. This would be more than double U.S. pipeline exports to Mexico in 2013, which averaged 1.8 Bcf/d. This projected growth is driven mainly by higher demand from Mexico's electric power sector in both the north and interior of the country.



Nearly three quarters of the projected growth in Mexico's natural gas consumption between 2012 and 2027 is projected to occur in the electric power sector (see graph). This growth is largely driven by private and independently operated power plants, whose natural gas consumption is expected to rise at a 7.9% average annual rate, from 1.6 Bcf/d in 2012 to 4.9 Bcf/d in 2027. By contrast, natural gas consumption from plants operated by national energy company CFE grows at just 0.4% per year, from 1.1 Bcf/d in 2012 to 1.2 Bcf/d in 2027. The growth comes largely from new combined cycle plants, which benefit from greater operational efficiencies and lower emission levels compared to other generation sources. Growth sharply accelerates over the near term but continues through 2027, when power sector consumption reaches 58% of total gas consumption, compared to 47% in 2012.

Mexico's projected growth in natural gas consumption occurs in each of its five market regions: Northeast, Northwest, Interior-West, Interior, and South-Southeast. According to SENER, demand growth is particularly strong in the northern and interior regions of the country.



All natural gas pipeline imports from the United States into Mexico enter the country's Northeast and Northwest regions. Some of these imports enter the country as logistical imports on pipelines owned by private entities, as well as by Pemex's natural gas subsidiary PGPB. The term logistical imports refers to imports that arrive in areas with no other form of access to natural gas. The largest growth in projected pipeline imports takes place from nonlogistical imports on PGPB owned pipelines in the Northeast. An increasing portion of this gas flows through the Northeast south to the interior regions, but much of it also serves increased consumption from the Northeast's industrial and electric generation facilities. Higher natural gas pipeline imports from the United States into the Northeast region meet both higher demand from consumers there and the increased pipeline flows from the Northeast to regions further south.

About three quarters of Mexico's natural gas production comes from associated gas that is produced at Pemex's offshore oil platforms in the South-Southeast region. Natural gas production in the South-Southeast is expected to grow by only 0.4% per year through 2019. Pemex consumes increasing amounts of this production in the near term for its exploration, production, and refining activities. With stagnant growth in the production of associated gas in the South-Southeast and limited capacity for future growth in LNG imports, pipeline imports from the United States become the primary means for Mexico to satisfy national demand growth.

SENER has previously made projections that assumed more robust investment in the development of new gas fields, and a more aggressive and diverse range of well productivity rates. SENER's high natural gas production growth projections included the undertaking of an initiative to enhance recovery rates in the South-Southeast of both gas and oil extracted from offshore fields in the Yucatan Peninsula, as well as development in the Northeast of the Sabinas Basin's La Casita shale gas play and Mexico's portion of the Eagle Ford shale play.

However, there are significant factors that could inhibit the development of shale gas and other basins in Mexico, including the geologic complexity and discontinuity of its shale gas areas, the availability of required technology and water resources, security concerns, and a focus on development of crude oil resources. Even if additional development did occur, Mexico's northern regions would likely still see high growth in pipeline imports from the United States, particularly in areas that lack pipeline connectivity to other parts of the country.

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Is this a "Bearish Outside Reversal" in Natural Gas?

June Natural Gas (NG.M14.E) opened sharply higher in Sunday evenings session, but since the open prices plummeted to a 5 day low. The sell off confirmed a bearish outside reversal ahead of today's U.S. session. June Natural Gas futures remain under pressure from last week's EIA storage report that showed a larger than expected supply build of 82 bcf. Recent weather forecasts have been calling for warmer temperatures across the country which could limit the size of upcoming supply injections.

In recent weeks, we have been in a sideways trend in the June Natural Gas Market as the market decides on which direction it is headed next. The technical analysis in Natural Gas points to bearish in the near term, making way for a potential swing trading opportunity.

In today's trading session, I will be looking to sell June Natural Gas futures at 4.660, or a breach of the 20 Day Moving Average. This breach would confirm the outside reversal in today’s trading session. My first downside target would be 4.500, a recent area of support in the market, at which point I would roll stops to break even. If the 4.500 are is hit, then I would look at 4.380 as my next target, which would be support from the long term trendline. To mitigate risk on the trade, stop loss orders should be placed just above today’s trading range and rolled behind the trade accordingly.

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 Posted courtesy of James Leeney and our trading partners at INO.com



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Growing Oil and Natural Gas Production Continues to Reshape the U.S. Energy Economy

The Annual Energy Outlook 2014 reference case was released today by the U.S. Energy Information Administration (EIA) presents updated projections for U.S. energy markets through 2040.

"EIA's updated Reference case shows that advanced technologies for crude oil and natural gas production are continuing to increase domestic supply and reshape the U.S. energy economy as well as expand the potential for U.S. natural gas exports," said EIA Administrator Adam Sieminski. "Growing domestic hydrocarbon production is also reducing our net dependence on imported oil and benefiting the U.S. economy as natural-gas-intensive industries boost their output," said Mr. Sieminski.

Some key findings:

Domestic production of oil and natural gas continues to grow. Domestic crude oil production increases sharply in the AEO2014 Reference case, with annual growth averaging 0.8 million barrels per day (MMbbl/d) through 2016, when domestic production comes close to the historical high of 9.6 MMbbl/d achieved in 1970 (Figure 1). While domestic crude oil production is projected to level off and then slowly decline after 2020 in the Reference case, natural gas production grows steadily, with a 56% increase between 2012 and 2040, when production reaches 37.6 trillion cubic feet (Tcf). The full AEO2014 report, to be released this spring, will also consider alternative resource and technology scenarios, some with significantly higher long-term oil production than the Reference case.

Low natural gas prices boost natural gas-intensive industries. Industrial shipments grow at a 3.0% annual rate over the first 10 years of the projection and then slow to a 1.6% annual growth over the balance of the projection. Bulk chemicals and metals-based durables account for much of the increased growth in industrial shipments. Industrial shipments of bulk chemicals, which benefit from an increased supply of natural gas liquids, grow by 3.4% per year from 2012 to 2025, although the competitive advantage in bulk chemicals diminishes in the long term. Industrial natural gas consumption is projected to grow by 22% between 2012 and 2025.

Higher natural gas production also supports increased exports of both pipeline and liquefied natural gas (LNG). In addition to increases in domestic consumption in the industrial and electric power sectors, U.S. exports of natural gas also increase in the AEO2014 Reference case (Figure 2). U.S. exports of LNG increase to 3.5 Tcf before 2030 and remain at that level through 2040. Pipeline exports of U.S. natural gas to Mexico grow by 6% per year, from 0.6 Tcf in 2012 to 3.1 Tcf in 2040, and pipeline exports to Canada grow by 1.2% per year, from 1.0 Tcf in 2012 to 1.4 Tcf in 2040. Over the same period, U.S. pipeline imports from Canada fall by 30%, from 3.0 Tcf in 2012 to 2.1 Tcf in 2040, as more U.S. demand is met by domestic production.

Car and light trucks energy use declines sharply, reflecting slow growth in travel and accelerated vehicle efficiency improvements. AEO2014 includes a new, detailed demographic profile of driving behavior by age and gender as well as new lower population growth rates based on updated Census projections. As a result, annual increases in vehicles miles traveled (VMT) in light-duty vehicles (LDV) average 0.9% from 2012 to 2040, compared to 1.2% per year over the same period in AEO2013. The rising fuel economy of LDVs more than offsets the modest growth in VMT, resulting in a 25% decline in LDV energy consumption decline between 2012 and 2040 in the AEO2014 Reference case.

Natural gas overtakes coal to provide the largest share of U.S. electric power generation. Projected low prices for natural gas make it a very attractive fuel for new generating capacity. In some areas, natural-gas-fired generation replaces power formerly supplied by coal and nuclear plants. In 2040, natural gas accounts for 35% of total electricity generation, while coal accounts for 32% (Figure 3). Generation from renewable fuels, unlike coal and nuclear power, is higher in the AEO2014 Reference case than in AEO2013. Electric power generation from renewables is bolstered by legislation enacted at the beginning of 2013 extending tax credits for generation from wind and other renewable technologies.

Other AEO2014 Reference case highlights:

• The Brent crude oil spot price declines from $112 per barrel (bbl) (in 2012 dollars) in 2012 to $92/bbl in 2017. After 2017, the Brent spot oil price increases, reaching $141/bbl in 2040 due to growing demand that requires the development of more costly resources. World liquids consumption grows from 89 MMbbl/d in 2012 to 117 MMbbl/d in 2040, driven by growing demand in China, India, Brazil, and other developing economies.

• Total U.S. primary energy consumption grows by just 12% between 2012 and 2040. The fossil fuel share of total primary energy demand falls from 82% of total U.S. energy consumption in 2012 to 80% in 2040 as consumption of petroleum-based liquid fuels falls, largely as a result of slower growth in LDV VMT and increased vehicle efficiency.

• Energy use per 2005 dollar of gross domestic product (GDP) declines by 43% from 2012 to 2040 in AEO2014 as a result of continued growth in services as a share of the overall economy, rising energy prices, and existing policies that promote energy efficiency. Energy use per capita declines by 8% from 2012 through 2040 as a result of improving energy efficiency and changes in the way energy is used in the U.S. economy.

• With domestic crude oil production rising to 9.5 MMbbl/d in 2016, the net import share of U.S. petroleum and other liquids supply will fall to about 25%. With a decline in domestic crude oil production after 2019 in the AEO2014 Reference case, the import share of total petroleum and other liquids supply will grow to 32% in 2040, still lower than the 2040 level of 37% in the AEO2013 Reference case.

• Total U.S. energy-related CO2 emissions remain below their 2005 level (6 billion metric tons) through 2040, when they reach 5.6 billion metric tons. CO2 emissions per 2005 dollar of GDP decline more rapidly than energy use per dollar, to 56% below their 2005 level in 2040, as lower-carbon fuels account for a growing share of total energy use.

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EIA: Natural Gas Reserves Rose by Almost 10 Percent

U.S. proved crude oil reserve additions in 2011 set a record volumetric increase for the second year in a row, according to U.S. Crude Oil and Natural Gas Proved Reserves, 2011, released today by the U.S. Energy Information Administration (EIA). Natural gas proved reserves rose also, but by less than 2010's record increase. Nevertheless, natural gas reserve additions in 2011 rank as the second largest annual increase since 1977.

"Horizontal drilling and hydraulic fracturing in shale and other tight rock formations continued to increase oil and natural gas reserves," said EIA Administrator Adam Sieminski. "Higher oil prices helped drive record increases in crude oil reserves, while natural gas reserves grew strongly despite slightly lower natural gas prices in 2011."

Proved oil reserves, including both crude oil and lease condensate, increased by 15 percent in 2011 to 29.0 billion barrels, marking the third consecutive annual increase and the highest volume of proved reserves since 1985. Proved reserves in tight oil plays accounted for 3.6 billion barrels (13 percent) of total proved reserves of crude oil and lease condensate in 2011.

Texas recorded the largest volumetric increase in proved oil reserves among individual states, largely because of continuing development in the Permian and Western Gulf basins, while North Dakota had the second largest increase, driven by development activity in the Bakken formation in the Williston Basin.

Natural gas proved reserves, estimated as wet gas that includes natural gas liquids, increased by almost 10 percent in 2010 to 348.8 trillion cubic feet (Tcf), the 13th consecutive annual increase.

Pennsylvania's proved natural gas reserves, which more than doubled in 2010, rose an additional 90 percent in 2011, contributing 41 percent of the overall U.S. increase. Combined, Texas and Pennsylvania added 73 percent of the net increase in U.S. proved wet natural gas reserves in 2011. Proved reserves in shale gas plays accounted for 131.6 trillion cubic feet (38 percent) of total proved reserves of wet natural gas in 2011.

Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. EIA's estimates of proved reserves are based on an annual survey of about 1,100 domestic oil and gas well operators.

U.S. Crude Oil and Natural Gas Proved Reserves, 2011 is available at: http://www.eia.gov/naturalgas/crudeoilreserves.

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EIA: By 2040 world energy consumption will rise by 56%

From Robin Dupre at Rigzone.com......

World energy consumption will rise 56 percent in the next three decades, driven by growth in the developing world, noted The Energy Information Administration (EIA) in its International Energy Outlook 2013 report Thursday. China and India’s rising prosperity is a major factor in the outlook for global energy demand, noted EIA Administrator Adam Sieminski in a press conference call.

“These two countries combined account for half the world’s total increase in energy use through 2040. This will have a profound effect on the development of world energy markets.” Energy demand will increase to 820 quadrillion British thermal units (Btu) in 2040, up from 524 quadrillion Btus. By 2040, China’s energy use will double the United States’, according to EIA estimates.

One quadrillion Btu is equal to 172 million barrels of crude oil.

Additionally, renewable energy and nuclear power are the fastest growing source of energy consumption with each increasing by 2.5 percent per year. But fossil fuels, including oil, natural gas and coal will continue to supply almost 80 percent of the world’s energy through 2040, noted Sieminski.

Natural gas is the fastest growing fossil fuel in EIA’s outlook, and will continue to dominate the landscape, increasing by 1.7 percent per year. Swelling supplies of tight gas, shale gas and coalbed methane support growth in projected worldwide gas use with non OECD Europe/Eurasia, Middle East and the United States accounting for the largest increases in natural gas production.

The explosion in supply from unconventional sources will underpin growth of natural gas demand, while high oil prices will encourage countries to focus on liquid fuels “when feasible”, the report stated.

The EIA’s July short term energy outlook projected benchmark Brent crude to average $105 a barrel in 2013 and $100 in 2014.The report projects that prices will increase long term with the world oil price reaching $106 a barrel in 2020 and $163 in 2040 in the Reference case.

With more than 10 years of journalism experience, Robin Dupre specializes in the offshore sector of the oil and gas industry. Email Robin at rdupre@rigzone.com.

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EIA: Underground Natural Gas Working Storage Capacity

Natural gas working storage capacity increased by about 2 percent in the Lower 48 states between November 2011 and November 2012. The U.S. Energy Information Administration (EIA) has two measures of working gas storage capacity, and both increased by similar amounts:

*   Demonstrated maximum volume increased 1.8 percent to 4,265 billion cubic feet (Bcf)

*   Design capacity increased 2.0 percent to 4,575 Bcf

Maximum demonstrated working gas volume is an operational measure of the highest level of working gas reported at each storage facility at any time over the previous five years, according to EIA's monthly survey of storage operators. Working gas is the volume of natural gas in an underground natural gas facility available to be withdrawn, not including base gas.

The maximum demonstrated working gas volume is a practical measure of full storage. Filling storage, which requires compressors to inject the gas into the storage facility, becomes more difficult and expensive as storage volume nears its maximum and pressures inside the facility increase.

That's why the demonstrated maximum is generally less than the design capacity, averaging 93% over the past two measurement periods (see Table 1), and why any given week's storage inventory is generally less than the demonstrated maximum. The maximum demonstrated volume provides guidance to operators and market analysts on the economics of filling the system.

Last October, for example, when working gas in storage reached a record-high of 3,930 Bcf, a simple calculation using the then current maximum demonstrated volume (4,188 Bcf) showed storage to be 94% full.

Read the entire EIA Report


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Marin Katusa: The Global Race for Shale Development Is On

By Marin Katusa, Chief Energy Investment Strategist

Guess who the U.S. Energy Information Agency (EIA) says has 430% more proven gas reserves than the US?


Guess who has twice as much as the U.S. in shale gas technically recoverable?

Guess who has over twice as much proven oil reserves as the U.S.?

The EIA recently published a 730 page report which assesses the shale formations of 41 countries. The global race for shale development has started. Countries that are not now known for their oil and gas production are showing much shale oil and gas promise.

Would you be surprised to know that China has more proven oil reserves than the U.S.?

If you want to know the answers to the three questions we have at the beginning of this missive, then I believe you will be interested in the Casey Energy Report's plans on profiting from the global shale race. If you thought the U.S. was the king of shale, we are sorry to burst your bubble..… it no longer wears the crown.

A picture is worth a thousand words:

Now, do you know how to make money from the global shale race? Countries like China, Argentina, and Russia are starting to exploit their unconventional energy sources. The global race for shale development and exploitation is on, and fortunes will made. Make sure you are well informed before you place your bets on this global race, as fortune will favor the bold – but the informed will fare much better.

Casey Research was the first in the business to publish a report on the potential of the European shales, years before the EIA came out with this report. Our subscribers made over 600% gains on Cuadrilla Resources, which just recently completed a deal with Centrica that valued the company in the hundreds of millions. Been there, done that.

What's next? We are so sure that you will be absolutely satisfied with our Casey Energy Report that we have no hesitations in giving you a 100% money back guarantee.

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January 2013 Crude Oil Export to China was a Rare Event

The United States exported 9,000 barrels per day (bbl/d) of foreign- rigin crude oil to China in January 2013, according to data EIA released on March 28. Many media outlets picked up this information, noting that the United States had not exported crude oil to China since 2005. However, the United States does export small amounts of crude oil on a regular basis, mostly to Canada, which is not shown on the graph. From 2003 to 2012, the United States exported an average of 35,000 bbl/d of crude oil — 98% of those exports were delivered to Canada. By comparison, in January 2013, the United States imported nearly 8 million barrels per day, while producing about 7 million barrels per day.





To export crude oil, a company must obtain a license from the Bureau of Industry and Security (BIS), which is part of the U.S. Department of Commerce, and which relies on the Code of Federal Regulations Title 15 Part 754.2. According to the regulations, "BIS will approve applications to export crude oil for the following kinds of transactions if BIS determines that the export is consistent with the specific requirements pertinent to that export:"

*    From Alaska's Cook Inlet
*   To Canada for consumption or use therein
*   In connection with refining or exchange of Strategic Petroleum Reserve oil
*   Of up to an average of 25,000 bbl/d of California heavy crude oil
*   That are consistent with findings made by the president under an applicable statute
*   Of foreign-origin crude oil where, based on written documentation satisfactory to BIS, the exporter can demonstrate that the oil is not of U.S. origin and has not been commingled with oil of U.S. origin


As noted above, the vast majority of U.S. crude exports go to Canada. Most of the other exports of crude oil are those that fall into the last category, exports of foreign-origin crude, imported into the United States but not comingled with U.S., origin crude oil. These exports typically occur because the owner of the imported crude oil cannot process or resell it in the United States. The license allows the imported crude to be exported.

EIA does not collect data on crude oil (or petroleum product) exports, but rather publishes data collected by the U.S. Census Bureau. The Census data show that since 2003, there have been only a handful of crude oil exports from the United States to a country other than Canada. These exports include small volumes to China, Costa Rica, France, South Korea and Mexico.

The 9,000 bbl/d of oil that the United States exported to China in January 2013 was a rare event. For confidentiality reasons, the U.S. Census Bureau is not allowed to publish specifics about particular shipments, but data available from the U.S. Census Bureau indicate this crude oil was not listed as a domestic export, implying that the crude oil was foreign-origin crude oil that was imported into the United States and then exported from the United States to China.

The 2 Energy Sectors You Should Invest in This Year

Dominick Chirichella: Natural Gas Prices Remain Firm

In spite of the downside miss in the weekly EIA Nat Gas inventory report the market has been in rally mode as prices have currently cleared the $4.16/mmbtu resistance area for the spot Nymex contract. Although the temperatures have been warmer the eastern half of the US has not yet seen consistent spring like temperatures which is keeping the bulls interested in pushing prices higher. In addition, the fact that total inventories are now 32.5 percent below last and 3.8 percent below the so called normal or five year average for the same week has put the market on alert that any unscheduled supply interruptions or sudden demand surges will send prices strongly higher.

The Nat Gas futures contract is entering a trading zone that has not been seen since the middle of 2011 or before the large imbalance of supply over demand started to take hold. If the spot contract can remain above the $4.16/mmbtu level it has a relatively clear area all the way to around the $4.40/mmbtu level. From a technical perspective the market is clearly in a bullish pattern as long as the spot contract remains above the new support level of around $4.16/mmbtu.

From a fundamental viewpoint the market is in the midst of a changing weather pattern as most of the country starts to experience spring like temperatures against a backdrop of the inventory cushion now solidly below normal as well as strongly below last year at this time. The fundamentals are going to have to provide support for the technical to remain in the new higher trading range.

The latest six to ten day and eight to fourteen day NOAA forecasts are providing a modest level of potential fundamental support as both forecasts are now projecting a large portion of the middle section of the US expecting below normal temperatures for the April 17th to April 25th timeframe. The forecast does not mean that there will be a significant amount of heating demand but it does mean there will be some in various parts of the country and it could result in injections coming in below both last year and the five year for the same timeframe thus widening the deficit further versus current levels.

Yesterday's EIA report was bullish versus the historical data but neutral to slightly bearish versus a comparison to the market consensus. The report showed a net withdrawal that was below the market expectations but greater than both last year and the five year average net injections for the same period. The 14 BCF withdrawal (strongly atypical for this time of the year) was below the market consensus calling for a withdrawal of around 21 BCF. The draw of 14 BCF was very near my model forecast (-15 BCF withdrawal) this week. The year over year inventory situation remains in a strong deficit position versus last year and has widened this week while the deficit versus the more normal five year average has also widened. The current inventory deficit came in at 66 BCF versus the normal five year average or about a negative 3.8 percent.

Read the entire CME Group article


Time to catch up on the Trend Jumper trades from this week
 

EIA Weekly Natural Gas Update for April 4th

Marketed natural gas production in the Gulf of Mexico federal offshore region falls to 6% of national total in 2012. Continuing a long term trend of decline, the contribution of marketed production of natural gas from the Gulf of Mexico federal offshore region accounted for 6.0 percent of total U.S. marketed natural gas production (4.2 billion cubic feet per day (Bcf/d) in 2012, according to data published in the Energy Information Administration’s (EIA) Natural Gas Monthly. In contrast, in the period from 1997 to 2007, marketed production from these same waters provided, on average, over 20 percent (11.7 Bcf/d), of U.S. marketed production.




Among the contributing factors to this decline:

• Increasing amounts of domestic, on-shore production, primarily from shale gas and tight oil formations. In 2012, nearly 40 percent (over 26 Bcf/d according to Lippman Consulting, Inc.) of U.S. dry natural gas production came from production in shale plays, increasing over 20 fold from 2000 levels. In 2012, the two most productive shale plays were the Haynesville play in Louisiana and Texas, and the Marcellus play in Pennsylvania. In the Marcellus play, despite reduced drilling activity, production increased by almost 70 percent in 2012 over year ago levels. Increased drilling in tight oil plays like the Eagle Ford play in Texas has contributed to increased associated natural gas production. 

• Relatively low natural gas prices. Low natural gas prices in recent years have diminished the economic incentive for off shore natural gas directed drilling. However, relatively high crude oil prices continue to support oil directed drilling and the production of associated gas, particularly in deep waters. New large deepwater projects directed toward liquids development are projected to reverse the decline in natural gas production from the Gulf of Mexico in 2015, according EIA's Annual Energy Outlook 2013 Early Release.

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Where is all the new Natural Gas Pipeline Construction?

U.S. natural gas pipeline capacity investment slowed in 2012 after several years of robust growth. Limited capacity additions were concentrated in the northeast United States, mainly focused on removing bottlenecks for fast growing Marcellus shale gas production. More than half of new pipeline projects that entered commercial service in 2012 were in the Northeast (see map below). Excluding gathering, storage, and distribution lines, project sponsors in the United States added 4.5 billion cubic feet per day of new pipeline capacity and 367 miles of pipe totaling $1.8 billion in capital expenditures in 2012.




Read the entire EIA article


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EIA: Saudi Arabia was world's largest petroleum producer and net exporter in 2012

Saudi Arabia was the world's largest producer and exporter of petroleum and other liquids in 2012, producing an average of 11.6 million barrels per day (bbl/d) and exporting an estimated 8.6 million bbl/d (net). Saudi Arabia produces more than three times as much of these liquids as the next largest member of the Organization of the Petroleum Exporting Countries (Iran), and as much as the rest of the Arab Middle East put together.

In addition to leading the world in production and exports, Saudi Arabia has an estimated 268 billion barrels of proved oil reserves, over 16% of the global total, and is the only country in the world with extensive spare oil production capacity, which can help cushion market disruptions. While Saudi Arabia has about a hundred major oil and natural gas fields, more than half of its proved reserves are contained in eight fields. Saudi Arabia's (and the world's) largest oil field (Ghawar) alone contains an estimated 70 billion barrels of proved reserves, more than the proved reserves in all but seven other countries.

 

In 2012, 16% of Saudi liquids exports were sent to the United States, accounting for 13% of total U.S. liquids imports. While Canada is the prime supplier of U.S. liquids imports, Saudi Arabia remains an important supplier.

Although leading the world in exports, Saudi Arabia's own liquids consumption is growing. Unlike the United States, Saudi Arabia uses significant amounts of oil for electricity generation, reaching as much as one million bbl/d during hot summer months. Electric demand has doubled since 2000 and is expected to continue its rapid growth. Without initiatives to facilitate fuel switching and increase efficiency, growing volumes of oil, expensive in relation to other fuels, will be consumed domestically.

Finally, as EIA has previously discussed, the choice of accounting conventions for measuring liquids production can also affect which country is considered the world's leading producer at a given date.

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EIA: Gulf Coast Crude Stocks Generally Fall Sharply in December Because of Inventory Taxes

Crude oil inventories in the Gulf Coast often fall sharply in December, averaging a decline of nearly 8 million barrels in that month from 1981 through 2011. Preliminary data for December 2012 show a decline of more than 12.5 million barrels in the region, bringing end of year crude inventories to approximately 165 million barrels.

The reason for this sharp decline: December 31 is the typical assessment date for taxes on crude oil stocks that are collected by many states/counties/municipalities in regions where the bulk of U.S. crude oil and petroleum product inventories are stored. To decrease crude inventories, companies can do a combination of the following: delay or decrease imports, increase runs at refineries, move crude oil out of the taxable region, or sell crude oil to other market participants.



Following December declines, inventories tend to recover in January. Although large crude oil draws can be an indication of demand outpacing supply, the December phenomenon typically does not reflect tightening of the oil market, but rather how companies in the region are taxed on crude stocks. During the middle of the year, crude inventories in the Gulf Coast region both rise and fall, averaging out to relatively small net changes in stocks for a given month.

At the end of December each year, parts of Texas and Louisiana, where significant volumes of crude oil are stored, assess ad valorem taxes (meaning, according to value) on end of year crude oil inventories. These taxes, along with the generally accepted accounting practice of last in, first out (LIFO) method used to value the assets, create an incentive to draw down crude stocks in the region at the end of the year in order to reduce the tax bill.

 

If oil prices have risen during the year, this accounting practice gives companies stronger incentive to reduce inventory because doing so will further limit their tax exposure. Conversely, if oil prices have fallen throughout the year, companies have less incentive to reduce crude held in storage.

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Biodiesel demand Estimates Now Provided in Petroleum Supply and Demand Balances

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Biodiesel production data were reported for the first time in U.S. and regional petroleum supply and disposition balances as published by the U.S. Energy Information Administration (EIA) in the Petroleum Supply Monthly (PSM) in May 2012. The biodiesel production data in the PSM will allow EIA to more completely account for biodiesel when calculating demand (measured as product supplied) for distillate fuel oil. Biodiesel production and other biodiesel data are now included in the item "Renewable Fuels Except Fuel Ethanol" in PSM supply and disposition tables.

In addition, previously published PSM data for January-April 2012 were revised to include biodiesel production. Similar revisions will be reported for 2011 when the Petroleum Supply Annual is released at the end of August 2012.



Product supplied is a widely followed measure of demand for petroleum products. For finished petroleum products (including distillate fuel oil), product supplied is calculated as the sum of production, imports, net receipts (only for regional data), and adjustments minus the sum of stock change, refinery and blender input, and exports. While not a measure of actual consumption, product supplied has proven to be a useful approximation of demand for petroleum products.

In the case of biodiesel, EIA assumes that any biodiesel that is produced is blended with diesel fuel, adding to the diesel fuel pool. This biodiesel production amount adds to the distillate fuel product supplied level, as shown on the graph. Including biodiesel production in the distillate fuel production volume added between 50 to 70 thousand barrels per day over the first five months of 2012.

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Heat Wave Can't Get You $8 Natural Gas in 2012

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From the staff at EconMatters.......

The Energy Department reported that natural gas in storage grew by 26 billion cubic feet to 3.189 trillion cubic feet for the week ended July 20. The inventory level was 15.8% above the five year average of 2.754 trillion cubic feet, and 18% above last year's level.

Low natural gas prices in the U.S. this year has not only tanked the stocks of many gas weighted producers, but also dragged down profits of U.S based oilfield services companies as a result of reduced gas drilling activity (See Chart Below). However, since hitting a 10 year low of below $2/mmbtu in April, Henry Hub benchmark prices has surged 69% hitting $3.214/mmbtu on Monday, July 30, the high of the year.



The latest bullish sentiment is fueled mostly by forecasts for more unusual heat this summer to increase air conditioning use. In addition, there's also an increase in usage/demand as lower natural gas prices have also attracted many utilities to switch from coal to natural gas for power generation. According to the EIA, electricity generated using natural gas was roughly even with coal for the first time ever in April. Historically, natural gas typically supplied just over 20% of the domestic electricity needs.


These positive indicators have prompted at least one article at Forbes to predict $8.00/mcf natural gas by "the approaching winter", that means another 160% rise in about four months.

Well, EIA did raise its estimate for domestic natural gas consumption this year, expecting demand to climb 3.3 bcfd, or 4.9%, from 2011 to 69.91 bcf daily driven mainly by a 21% jump in utilities coal-to-gas switching for power generation in 2012, offsetting declines in residential and commercial use, primarily due to a weak U.S. economy.



Nevertheless, the problem is natural gas starts to lose its cost advantage to coal at around $2.40 to $2.50 per mmbtu. So the current $3.20/mmbtu levels, if sustained, could take away one significant bullish swing factor in the natural gas fundamentals--demand from the power gen sector. If that happens, it is very likely there could be another record storage level before "the approaching winter," let alone $8/mmbtu.



The natural-gas market this year is now outpacing even the returns in oil and copper (i.e. Every dog has its day). However, our observation is that the NYMEX natural gas market a lot of times could be in a somewhat irrational "trend trading" mode driven mostly by traders totally disregarding the fundamentals. The current run-up seems to be in one of those "trend-trading" momentum, and likely will not last long after reality sets in. For now, we see Henry Hub continue to hover within the $2-$3/mmbtu range in the next twelve months barring a super sized hurricane knocking out production in the U.S. Gulf.

Check out more articles at EconMatters.Com

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EIA: Rail Deliveries of Crude Oil and Petroleum Products up 38% in First Half of 2012

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Railroads are playing a more important role in transporting U.S. crude oil to refineries, especially oil production from North Dakota's Bakken formation where there is limited pipeline infrastructure to move supplies. The amount of crude oil and petroleum products transported by U.S. railways during the first half of 2012 increased 38% from the same period in 2011, according to industry data.

The number of rail tanker cars hauling crude oil and petroleum products totaled close to 241,000 during January-June 2012 compared to 174,000 over the same period in 2011, according to the Association of American Railroads (AAR). Rail deliveries of crude oil and petroleum products in June alone jumped 51% to 42,000 tanker cars from a year earlier to an average weekly record high of 10,500 tanker cars for the month.

One rail tanker car holds about 700 barrels. This would be equivalent to about 927,000 barrels per day (bbl/d) of oil and petroleum products shipped, on average, during the first half of 2012 versus 673,000 bbl/d in the same period in 2011, and June 2012 shipments were almost 980,000 bbl/d.

Source: U.S. Energy Information Administration, based on Association of American Railroads.
Note: Crude oil and petroleum products rail shipments do not include ethanol. 

In 2009, crude oil accounted for 3% of the combined deliveries in the oil and petroleum products category tracked by AAR. The trade group estimates crude oil now accounts for almost 30% of the rail deliveries in this category, and says that crude oil is responsible for nearly all of the recent growth.

Much of the growth in shipping oil by rail is due to the rise in North Dakota's oil production, which has more than tripled in the last three years. North Dakota surpassed California in December 2011 to become the third biggest oil producing state and took over the number two spot from Alaska in March 2012.

Most crude oil is moved in the United States by pipeline. However, because of limited pipeline infrastructure in North Dakota's Bakken region, oil producing companies there rely on rail to move their barrels. Shipping oil by rail costs an average $10 per barrel to $15 per barrel nationwide, up to three times more expensive than the $5 per barrel it costs to move oil by pipeline, according to estimates from Wolfe Trahan, a New York City based research firm that focuses on freight transportation costs. Wolfe Trahan also notes that using rail tank cars allows oil producers to separate grades of crude more easily and ensure their purity than when different oils are mixed in a pipeline.

Argus Media reports that rail rates for unit trains moving Bakken oil to major refining centers on the Gulf Coast are about $12.75 per barrel to St. James, Louisiana and $12.25 per barrel to Port Arthur, Texas. The unit train delivery rate to New York Harbor is around $15 per barrel.
BNSF is the biggest railway mover of U.S. crude, transporting one-third of Bakken oil production alone with unit trains carrying up to 85,000 barrels of oil. The company's carloadings of crude oil and petroleum products increased 60% during the first six months of 2012.

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Spot Natural Gas Prices at Marcellus Trading Point Reflect Pipeline Constraints

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Daily natural gas spot prices between Tennessee Gas Pipeline (TGP) Zone 4 Marcellus and Henry Hub have diverged recently largely due to rising Marcellus production, which has outpaced the growth of available take away pipeline capacity in northern Pennsylvania. As a result, the spot price of natural gas at the TGP Zone 4 Marcellus trading point has fallen, at times considerably, below the spot price at Henry Hub in Louisiana, and is currently the least expensive wholesale natural gas in North America.

To address this rapid growth in natural gas production, several Northeast interstate pipeline projects were completed in 2011, adding nearly 1.5 billion cubic feet per day (Bcf/d) of capacity in Pennsylvania. Many additional pipeline projects have been proposed or are in various stages of completion in the Northeast to reduce transportation constraints caused by growing Marcellus natural gas production. EIA's website has information on the status of some of these pipeline projects.



Dry natural gas production in Pennsylvania, a key part of the Marcellus supply basin, continues to grow and according to Bentek Energy is now approaching 6 Bcf/d. Estimated June 2012 Marcellus dry natural gas production (5.7 Bcf/d) has nearly doubled since June 2011 (2.9 Bcf/d) and represents about 9% of overall U.S. dry natural gas production. Further, Bentek Energy estimates that there are over 1,000 natural gas wells that have been drilled in northern Pennsylvania but which are not yet producing natural gas because there is not enough interstate and gathering pipeline infrastructure to accommodate the new production.

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

Note: Reflects monthly averages of Bentek Energy's daily estimates of dry natural gas production for the state of Pennsylvania. These figures exclude a small amount of natural gas production received directly by local distribution companies and end users via gathering lines that are not subject to Federal Energy Regulatory Commission posting requirements for interstate natural gas pipelines.     

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Geology and Technology Drive Estimates of Technically Recoverable Resources

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is the remaining technically recoverable resource (TRR). TRR estimates are a work in progress, changing as more production experience becomes available and as new technologies are applied to extract these resources. The greatest uncertainty is associated with the "estimated ultimate recovery," or EUR, per well.

EIA updates its TRR estimates using the latest available well production data. EIA's recently released Annual Energy Outlook 2012 (AEO2012) contains a detailed discussion of TRR estimates and resource uncertainty. AEO2012 projections also include sensitivity cases varying the EUR per well and a high-TRR case. The TRR estimates provide context for the size of the resource, while projected production depends strongly on the number of wells, the EUR per well, other well characteristics, and economics.

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TRR estimates consist of "proved reserves" and "unproved resources." As wells are drilled and field equipment is installed and productivity is assumed, unproved resources become proved reserves and, ultimately, production. The TRR estimate for a continuous-type shale gas or tight oil area is the product of land area, well spacing (wells per square mile), percentage of area untested, percentage of area with potential, and the estimated ultimate recovery (EUR) per well.

The Annual Energy Outlook 2012 unproved TRRs are shown in the figures above for the major shale gas and tight oil formations. The formation parameters that result in these TRR are provided elsewhere. The volume of total TRR due to proved reserves is not shown. "Tight oil" refers to crude oil and condensates that are produced from low permeability sandstone, carbonate, and shale formations. The tight oil TRRs are for the entire formation, including the non shale portions.

Read the entire article at EIA.Com

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