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Despite worldwide moratoriums on fracking of new wells, natural gas prices continue to hover around $3 per MMBtu, up from a frighteningly low $2 per MMBtu. The natural gas industry it seems has outsmarted itself and overproduced while at the same time a global economic slowdown is reducing demand. This chart from the US Energy Information Administration shows a clear inverse relationship between domestic production and price.

Earlier this year Chesapeake Energy (CHK) announced that it might reduce production by cutting its natural gas rig count, and they’re not the only ones to do so. Overall natural gas rig counts began dropping slightly in the first half of 2012. Notice however, that the percentage of new rigs being deployed to extract natural gas has been steadily losing ground to oil rigs since prices peaked in 2008.

What boggles my mind is the lack of consumption in response to incredibly low natural gas prices. As the price of natural gas has fallen from a peak of roughly $10 MMBtu in 2008 to a low of about $2 MMBtu earlier this year total consumption in the US has been nearly flat. Assuming the second half of 2012 matches the first, we can expect total natural gas consumption in the US to reach just under 25,934 billion cubic feet. That is an 11.4% increase over 2008′s total consumption, which seems like a lot until you consider that the price of natural gas fell about 500% during that same period.

In the US, the biggest increases in natural gas usage are coming from electricity generation while vehicle usage has sadly remained flat.

The demand for natural gas in the United States might be stuck in the mud, but globally the usage of natural gas is blowing up. This is largely due to the popularity of using compressed natural gas as a vehicle fuel. Toyota (TM), General Motors (GM) and other automakers produce versions of their vehicles with factory installed compressed natural gas tanks and gasoline. The gasoline is used sparingly to provide power when the driver steps on the accelerator and the much cheaper natural gas makes cruising very inexpensive.

In addition to factory production models, retrofitting a gasoline vehicle with a CNG or liquefied propane gas tank can be done for less than a thousand dollars. In Thailand, where I spend most of my time, the cost of retrofitting a vehicle to run on CNG is recouped after driving about 10,000 km; consequently demand for natural gas in Asia is wildly outpacing that of the US.

Popular passenger vehicles that run on both compressed natural gas and conventional gasoline are widely available, and popular throughout Asia.

The US should eventually catch up to the developing world’s usage of CNG vehicles. In the meantime I think the best opportunities for investors to profit from advanced natural gas extraction techniques in the US will come from exporting liquefied natural gas.

Unfortunately the amount of natural gas exported by the US will remain right where it is until after the November elections. Many state lawmakers are pressing the Obama administration to allow more natural gas to be liquified and shipped overseas. According to Secretary of Energy Steven Chu, the administration is hesitant to allow more natural gas to be exported to foreign countries, like China, because they do not want to be responsible for higher prices at home. I’m sure that they are far more concerned about the Romney campaign distorting a decision to export more fossil fuels as an act of treason. I’m sure that soon after elections, exports of natural gas will be allowed to rise.

Cheniere Energy, Inc. (LNG) is betting the farm on future natural gas exports. Their Sabine Pass Liquefaction project is well underway and a new LNG terminal is to be built in Corpus Christi. So far, Cheniere is the only US company allowed to export LNG to countries without free trade agreements, albeit in limited quantities. India’s largest gas transmission company, GAIL signed a 20 year agreement with Cheniere to buy 3.5 million tons of LNG per year. A lift on export restrictions would almost certainly result in more contracts for Cheniere from India and other gas hungry nations.

Cheniere has had an incredible run up over the last two years. If liquified natural gas exporting restrictions are eased, the run up should continue.

Relying on favorable policy and commodity prices is risky business to say the least. Furthermore, Cheniere has posted negative earnings 5 quarters in a row. If you want to make a bet on Cheniere I strongly suggest a simple call spread. For example:

Buy December 2012 call with a strike of ’16′ (priced at $1.50)

Sell the December 2012 call with a strike of ’18′ (priced at $0.70)

Net debit to start: $0.80

Maximum Profit: $1.20

This trade gives you about a month and a half after the election for the Obama administration to approve, or reject, an increase in natural gas exports. Your upside is limited to $120 per contract, but your risk is limited to only $80 per contract. Even if you hold on to the contracts until the date of expiration you only need a stock price of $16.80 to break even.

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The U.S. Energy Information Administration on Thursday said Hurricane Isaac caused “considerable disruption” but little damage to natural gas processing plants along the U.S. Gulf of Mexico coast when the storm came ashore three weeks ago.

The EIA in its Today in Energy report said it invoked an emergency-activation survey to collect daily data on the status of plant operations in the affected area after Isaac came ashore on Aug. 28.

Despite the disruption as well as shut-in offshore gas production, there were few reports of damage to energy infrastructure from the low-level Category 1 hurricane.

There was also little effect on natural gas prices due to ample onshore production and surplus storage, the EIA said.

The last time the EIA invoked the activation survey, Form EIA-757B, was for Hurricane Ike in September and October 2008.

Isaac disrupted natural gas processing operations for more than 10 of the 13.5 billion cubic feet per day of total processing capacity in the area. On Sept. 7, a chart showed shut-in processing capacity was less than 4 bcf per day.

The survey captured plants with capacities greater than 100 million cubic feet per day.

Prior to Isaac making landfall, there were 25 natural gas processing plants in the affected area that were not undergoing maintenance, accounting for 12.6 bcf per day of available processing capacity.

Widespread power outages affecting nearly 1 million customers in Louisiana following the storm reduced the need for gas supplies, while the potential for flooding reduced or curtailed operations at many of the plants.

Plants most commonly attributed closures to a lack of upstream supply, although a few also cited damage to downstream infrastructure that would receive their dry gas or their natural gas liquids products, the EIA said.

Processing facilities purify and “dry out” raw natural gas from producing wells. This process results in pipeline-quality natural gas for delivery to end-users and a mix of natural gas liquids products to be separated by fractionators.

The Department of Interior’s Bureau of Safety and Environmental Enforcement’s final update on Isaac was released on Tuesday. The report showed that less than 5 percent, or 213 million cubic feet, of Gulf of Mexico gas production remained shut in.

At the height of the outages in late August, the storm had shut more than 70 percent, or more than 3.26 billion cubic feet, of daily offshore gas production.

The U.S. Gulf of Mexico has accounted for a progressively smaller share of U.S. gas production in recent years due to steadily declining offshore production volumes in the Gulf and the prolific growth of shale gas production in various onshore basins.

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The U.S. Energy Information Administration has updated energy statistics and an interactive map that highlights the role of the Gulf of Mexico in the U.S. energy picture.

As EIA reporetd, the Gulf of Mexico (GOM) area, both onshore and offshore, is one of the most important regions in the United States for energy resources and infrastructure.  In 2011, the Gulf of Mexico federal offshore region accounted for about 23% of total U.S. crude oil production and about 7% of total U.S. dry natural gas production.

The interactive energy infrastructure map contains information on power plants, storage terminals, pipelines, petroleum refineries, liquefied natural gas terminals, natural gas processing facilities, and electricity transmission lines in and around the Gulf of Mexico. Users may select the types of energy facilities to show or hide on the map.

EIA’s GOM Fact Sheet also includes updated statistics related to petroleum and other liquids supply, natural gas supply, refining capacity, natural gas plant capacity, and proved reserves.

Total domestic production of crude oil and natural gas increased in 2011, despite decreases in Gulf of Mexico federal offshore production of 15% for crude oil and approximately 19% for dry natural gas. Refineries along the Gulf coast comprised about 44% of total U.S. petroleum refining capacity, as of January 2012. Gulf coast natural gas processing plants accounted for 30% of total U.S. natural gas processing plant capacity, as of January 2012.

The updated GOM Fact Sheet can help analysts assess this region’s resources and infrastructure in light of potential tropical storm activity or other events. The Climate Prediction Center at the National Oceanic and Atmospheric Administration has forecasted near-normal tropical storm activity for the 2012 hurricane season, which for the Atlantic region runs from June 1 to November 30. As of August 7, 2012, NOAA has declared seven named storms or hurricanes in the Atlantic region: Alberto, Beryl, Chris, Debby, Ernesto, Florence, and Gilma.

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US carbon dioxide emissions resulting from energy use during the first quarter of 2012 were the lowest in two decades for any January-March period, according to US Energy Information Administration figures.

The country’s CO₂ emissions from energy consumption totaled 1,340 million metric tons during the first quarter of 2012, down nearly eight percent from a year, according to the EIA’s June Monthly Energy Review.

Normally, CO₂ emissions during the year are highest in the first quarter because of strong demand for heat produced by fossil fuels. However, such emissions during the first quarter in 2012 were low due to a combination of the warm winter that reduced heating demand, a sharp decline in the amount of total electricity generated from burning coal, and lower gasoline use, the EIA says. This year saw the warmest March ever recorded in much of the United States.

CO₂ emissions from coal were down 18 percent year-on-year to 387 million metric tons in the January-March 2012 period. Those was the lowest-first quarter CO₂ emissions from coal since 1983 and the lowest for any quarter since April-June 1986. The decline in coal-related emissions is due mainly to utilities using less coal for electricity generation as they burned more low-priced natural gas, the EIA says.

About 90 percent of the energy-related CO₂ emissions from coal came from the electric power sector. Coal has the highest carbon intensity among major fossil fuels, resulting in coal-fired plants having the highest output rate of CO₂ per kWh, the EIA says.

The share of electricity generated from coal-fired power plants dropped to 34 percent in March, the lowest level in at least 39 years, the EIA figures showed.

Coal generation decreased 29 billion kilowatt hours from March 2011 to March 2012, while natural generation increased 27 billion kilowatt hours during the same period.

Natural gas prices were near 10-year lows this winter, causing generators in states such as Ohio and Pennsylvania to increase their dispatch of natural gas-fired plants, EIA said. Newer natural gas-fired plants also operate more efficiently than older, coal-fired units, which increases the competitiveness of natural gas relative to coal, EIA said.

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Oil and gas companies invade states across the country in hopes of cashing in on newly discovered “black gold.” Some states are eager for the modern day Gold Rush but hurrying to develop policy on the controversial extraction method called hydraulic fracturing, or fracking.  

The U.S. Environment Information Agency (EIA) estimates that 827 trillion cubic feet of natural gas reserves are recoverable. That compares to Saudi Arabia’s natural gas reserves estimated to total about 275 trillion cubic feet, according to the Oil and Natural Gas Journal.  

“We have a supply of natural gas that can last America nearly 100 years,” said President Barak Obama in his 2012 state of the union address.

These formations are so large that experts say the U.S. can now become an exporter of natural gas in the next twenty years.

To put this into perspective, 1 trillion cubic feet of natural gas is enough to heat 15 million homes or to fuel 12 million natural-gas-fired vehicles for one year, according to the EIA.

The U.S. reserves address key national goals for energy independence and security. 

Thanks in part to hydraulic fracturing and the ability to drill horizontally, natural gas and oil trapped thousands of feet below the earth’s surface can now be extracted.

Hydraulic fracturing involves some 750 chemicals, some harmless such as salts or citric acid and some extremely toxic ones, such as benzene and lead, according to a congressional report issue in April 2011. The report noted that unexpected components such as instant coffee and walnut hulls appear in the mix.

Water under high pressure and sand also are used in the mix to penetrate shale rock formations that trap the oil and natural gas, almost sponge-like, deep in the earth.

Using fracking technology to tap newly found energy supplies leaves states across the U.S. debating regulations and oversight policies for fracking.

In Michigan this debate is now taking center stage.

“With energy prices continuing to soar, it is important that we develop diverse energy portfolio that protects Michigan consumers and also creates thousands of energy jobs throughout our state,” stated a report from the Michigan House of Representatives subcommittee on energy and job creation.

At the same time, Michigan is looking for ways to regulate fracking to protect the environment and residents. 

“In Michigan, we are fortunate to have a rule-making environment where the Office of Oil, Gas, and Minerals within the DEQ (Department of Environmental Quality), producers and concerned citizens have worked together to make sure Michigan continues to vigorously defend one of our states most valuable resources: our water,” stated the Michigan report, issued in April.

With the unemployment rate in the U.S. at around 8.2 percent, many states can benefit from this industry, which has plenty of room for employment.

“Experts believe this will support more than 600,000 jobs by the end of the decade,” Obama said in State of the Union address. 

According to the U.S. Bureau of Labor Statistics, oil and gas workers may not need a high school diploma and the median pay for those workers are about $18.00 per hour.

The northwestern region of North Dakota has seen a rapid increase in drilling. As of July 7, Baker Hughes, a consultant service that counts major oil and gas drilling rigs in the U.S. and Canada, confirmed that there are 196 total rigs that are operational in the state.

Compare this to three years ago when only about 70 rigs were operational.

With such rapid growth, some companies are having trouble finding employees. North Dakota’s unemployment rates have been steady since 2009, ranging from 3 percent to 4 percent.

But an increase in drilling in other states where the unemployment rates are high can help reduce it.

Take Michigan, for instance, where foreign competition and economic downturns hit the thriving car industry.

According to the Bureau of Labor Statistics from 2000 to 2006 Michigan felt the largest decline of any Midwest auto production state.

Some 73,600 jobs were lost, a decline of 32.5 percent. In terms of weekly wages, Michigan auto workers experienced a 13.9 percent decline on average.

Not only can the oil and gas industries bring new jobs to states, they can create a chain reaction in which all parts of states economy can benefit.

The Michigan House of Representatives subcommittee report stated that job creation from oil and natural gas generates $2 billion in economic activity and that it already provides more than 8,000 direct jobs in Michigan. 

Yet, the oil and gas industry can’t solve all of Michigan’s economic problems, but they can assure continued strength in the manufacturing industry that has the potential to increase jobs.

“Energy is the root of manufacturing and you need the energy for manufacturing capability,” said Hal Fitch of the Office of Oil, Gas and Minerals for the Department of Environmental Quality in Michigan. “A predictable energy supply is key for manufacturing.”

So far Michigan has established and set rules regulated and enforced by the department. State regulation focuses on the protection of property, wildlife and the environment, while ensuring good air quality and the proper disposal of waste from drilling.

Other states are taking action to regulate and even block oil and gas companies from fracking in their states.

For this reason and others, states are now entering a difficult balancing act: Tapping into natural resources, helping the economy and answering to public pressure from conservationists and residents who may be affected by hydraulic fracking.

New York State is struggling with this debate. New York is sitting on a large basin of natural gas deposits right near the border with Pennsylvania. 

Tapping into these new finds can help New York significantly reduce energy costs. However, residents in parts of the states are strongly opposed to any type of fracking that can potentially contaminate water supplies, according to New Yorkers Against Fracking, a lobbying site. 

New York is currently studying the impacts of fracking. In an email from the press office of the New York state Department of Environmental Conservation, there are currently no high-volume hydraulic fracturing operation in the state.

“Under state law, once it is determined that SGEIS (Supplemental Generic Environmental Impact Statement) will be conducted,” said Emily DeSantis, director of public information for New York’s Department of Environmental Conservation. “No permits can be considered until that process is complete,” 

In North Carolina, another state sitting on natural gas reservoirs, the state senate passed legislation to allow fracking recently but it was vetoed by Gov. Bev Purdue, a Democrat.

“It’s disappointing that the leaders in General Assembly would allow fracking without ensuring that adequate protections will be in place for drinking water, landowners, county and municipal governments, and the health and the safety of families in North Carolina,” Purdue said in a statement.
“I hope the General Assembly will re-visit this issue and strengthen the safeguards before fracking begins.”

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The U.S. Energy Information Administration (EIA) faces a number of challenges as it tries to do more with less money, including providing better analysis of the movement of crude oil from U.S. Midwest fields by rail and truck, the new EIA Administrator Adam Sieminski said Monday.

Sieminski, speaking at a Platts Energy Podium event, said he hopes to make the EIA’s statistical analyses “more timely, and punchier and more market relevant” as the agency strives to help policymakers grapple with thorny issues such as allowing crude oil exports in the future.

“One of the things EIA can do in responding to the inevitable budget pressure we’re going to face is find better ways to collect, analyze and disseminate the data – do it cheaper, do it faster and do it more accurately,” Sieminski said at the event in Washington, D.C. “Some of that might require a little bit of upfront investment. But in general, I think there are plenty of ways to improve the data collection at EIA.”

Sieminski said his vision for the agency, the statistical arm of the U.S. Department of Energy, is to place it “at the heart of a national conversation on energy,” tackling important issues that arise from rapidly changing dynamics in the oil and natural gas markets.

Last week, Sieminski said that the U.S. should not rule out sending crude oil overseas, especially as production from tight oil formations is expected to keep soaring. Sieminski reiterated that belief, saying that laws passed in the 1970s to prevent crude exports might be ripe for reexamination.

“We shouldn’t have to live with those if they don’t make sense in the modern context,” Sieminski said Monday. “If EIA can jump into that and provide good data and analysis to help policymakers look at that issue and be able to understand it that would be really fantastic.”

One area ripe for improvement is the EIA’s understanding of movement of crude from the Midwest to other parts of the country, Sieminski said. He said the movement of crude by rail and truck was not “built into EIA’s data collection effort.”

“So there’s a tremendous amount of oil now moving out of the mid-continent by rail, and EIA’s ability to get data on oil shipments like that is limited and it’s got to be improved,” he said. “It would be very useful in this whole question of trying to understand what’s going on in the mid-continent.”

He said the “infrastructure issues associated with oil movement from region to region in the U.S. is really important. It’s definitely an area where we could upgrade.”

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The U.S. Department of Energy’s Energy Information Administration issued the following news release:

The U.S. Energy Information Administration (EIA) today released the complete version of Annual Energy Outlook 2012 (AEO2012) which, in addition to the Reference case projections, includes 29 alternative cases which show how different assumptions regarding market, policy, and technology drivers affect projections of energy production, consumption, technology, and market trends and the direction they may take in the future.

“Uncertainty is inherent in long-term projections,” said EIA Administrator Adam Sieminski. “By modeling scenarios using a range of assumptions about market, policy, and technology drivers, we gain a better understanding of the potential impacts in critical areas of uncertainty.”

Key results highlighted in AEO2012 include:

The rate of growth in energy use slows over the projection period, reflecting moderate population growth, an extended economic recovery, and increasing energy efficiency in end-use applications

Overall U.S. energy consumption grows at an average annual rate of 0.3 percent from 2010 through 2035 in the AEO2012 Reference case. The U.S. does not return to the levels of energy demand growth experienced in the 20 years prior to the 2008-2009 recession, because of more moderate projected economic growth and population growth, coupled with increasing levels of energy efficiency and rising energy prices.

Existing Federal and State energy requirements and incentives play a continuing role in requiring more efficient technologies. New Federal and State policies could lead to further reductions in energy consumption. The potential impact of technology change and the proposed vehicle fuel efficiency standards on energy consumption are examined in several cases in the AEO2012.

Domestic crude oil production increases

Domestic crude oil production has increased over the past few years, reversing a decline that began in 1986. U.S. crude oil production increased from 5.0 million barrels per day in 2008 to 5.5 million barrels per day in 2010. Over the next 10 years, continued development of tight oil, in combination with the ongoing development of offshore resources in the Gulf of Mexico, pushes domestic crude oil production higher.

Because the technology advances that have provided for recent increases in supply are still in the early stages of development, future U.S. crude oil production could vary significantly, depending on the outcomes of key uncertainties related to well placement and recovery rates. Those uncertainties are highlighted in several cases completed as part of AEO2012 and discussed in an article examining impacts of uncertainty about current estimates of the crude oil and natural gas resources.

With modest economic growth, increased efficiency, growing domestic production, and continued adoption of nonpetroleum liquids, net imports of petroleum and other liquids make up a smaller share of total U.S. energy consumption

U.S. dependence on imported petroleum and other liquids declines in the AEO2012 Reference case, primarily as a result of rising energy prices; growth in domestic crude oil production to more than 1 million barrels per day above 2010 levels in 2020; an increase of 1.2 million barrels per day crude oil equivalent from 2010 to 2035 in the use of biofuels, much of which is produced domestically; and slower growth of energy consumption in the transportation sector as a result of existing corporate average fuel economy standards.

Proposed light-duty vehicle fuel economy standards covering vehicle model years 2017 through 2025, which are not included in the Reference case, could further reduce demand for petroleum and other liquids and the need for imports, and increased supplies from U.S. tight oil deposits could also significantly decrease the need for imports as examined in several cases in AEO2012.

Natural gas production increases throughout the projection period, allowing the United States to transition from a net importer to a net exporter of natural gas

Much of the growth in natural gas production in the AEO2012 Reference case results from the application of recent technological advances and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value than dry natural gas. Shale gas production increases in the Reference case from 5.0 trillion cubic feet per year in 2010 (23 percent of total U.S. dry gas production) to 13.6 trillion cubic feet per year in 2035 (49 percent of total U.S. dry gas production).

As a result of the projected growth in production, U.S. natural gas production exceeds consumption early in the next decade in the Reference case. The outlook reflects increased use of LNG in markets outside North America, strong growth in domestic natural gas production, reduced pipeline imports and increased pipeline exports, and relatively low natural gas prices in the United States.

When looking forward to 2035 there are unresolved uncertainties surrounding the technological advances that have made shale gas production a reality.

The potential impact of those uncertainties results in a range of outcomes for U.S. shale gas production from 9.7 to 20.5 trillion cubic feet per year when looking forward to 2035. Those uncertainties and their impact are examined in several cases that are summarized in an article in AEO2012.

Power generation from renewables and natural gas continues to increase

In the Reference case, the natural gas share of electric power generation increases from 24 percent in 2010 to 28 percent in 2035, while the renewables share grows from 10 percent to 15 percent. In contrast, the share of generation from coal-fired power plants declines. The historical reliance on coal-fired power plants in the U.S. electric power sector has begun to wane in recent years. Over the next 25 years, the share of electricity generation from coal falls to 38 percent, well below the 48-percent share seen as recently as 2008, due to slow growth in electricity demand, increased competition from natural gas and renewable generation, and the need to reduce emissions.

Although the current trend toward increased use of natural gas and renewables appears fairly robust, there is uncertainty about the factors influencing the fuel mix for electricity generation. AEO2012 includes several cases examining the impacts on coal-fired plant generation and retirements resulting from different paths for electricity demand growth, coal and natural gas prices, and compliance with environmental rules.

Total energy-related emissions of carbon dioxide in the United States remain below their 2005 level through 2035

Energy-related carbon dioxide (CO 2) emissions grow slowly in the AEO2012 Reference case, due to a combination of modest economic growth, growing use of renewable technologies and fuels, efficiency improvements, slow growth in electricity demand, and increased use of natural gas, which is less carbon-intensive than other fossil fuels.

Projections for CO 2 emissions are sensitive to economic and regulatory factors. These linkages result in a range of potential GHG emissions scenarios. In the AEO2012 Low and High Economic Growth cases, projections for total primary energy consumption in 2035 are, respectively, 100.0 quadrillion Btu (6.4 percent below the Reference case) and 114.4 quadrillion Btu (7.0 percent above the Reference case), and projections for energy-related CO 2 emissions in 2035 are 5,356 million metric tons (7.0 percent below the Reference case) and 6,117 million metric tons (6.2 percent above the Reference case).

The projections from the complete AEO2012, including the Reference case, all of the alternative cases, and supplemental tables showing the regional projections, can be found at: www.eia.gov/forecasts/aeo .

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Crude output in the United States is at its highest in 14 years, adding to inventories that are keeping oil prices in North America low and feeding into a global oversupply leading Arabian Gulf producers to adjust their export levels.

Production rose above 6 million barrels per day (bdp) in the first three months of this year, according to the US Energy Information Administration (EIA).

“Strong growth in US crude-oil production since the fourth quarter of 2011 is due mainly to higher output from North Dakota, Texas and federal leases in the Gulf of Mexico, with total US production during the first quarter of this year topping 6 million barrels per day for the first time in 14 years,” the EIA said.

In the final quarter of last year, the US produced 5.9 million bpd but the production increases were met with sluggish demand, as the US battles harsh economic times.

A lack of transport options from the US crude hub at Cushing, Oklahoma, has led to a supply glut there. A pipeline connecting the US Gulf coast to Cushing was reversed this month, but experts say the impact of unblocking this bottleneck has yet to be felt on inventory levels.

“Stocks in Cushing are still high, even with the opening of the pipeline,” said Sammy Al Mehaid, an oil market analyst at the office of the Opec governor for Saudi Arabia. “The extra supply is adding bearish momentum on the US domestic market.”

US crude inventories remain near heights last reached in 1990, EIA data shows.

The price of crude on the New York Mercantile Exchange (Nymex) has dropped from about US$98 to about $85 a barrel this year.

The Cushing bottleneck created a wide disparity between US and European prices, with the European benchmark Brent trading in the region of $100 a barrel.

Strong US production is adding to a global supply overhang that has pushed prices down in spite of the stand-off over Iran’s nuclear programme that added a hefty risk premium to the price of a barrel of oil.

“Price is not giving you a true picture of supply and demand, it’s still being highjacked by geopolitical uncertainties,” said Mr Al Mehaid.

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