When will we cross the Rubicon? There are two issues and perhaps two river and two events that will twist trader's allegiances in the oil market, and that is of course war and tapering. Oil prices (NYMEX:CLV13) are pushing back the timing of an attack on Syria, so now the market can focus on the price impact of Fed tapering. The Senate Foreign Relations Committee eked an approval of a war resolution by vote of 10–7, not exactly a ringing endorsement. What that means is that the October crude delivery will be unencumbered by war but may face the full fury of the Fed. The short term yields are rising as the economic data suggests that we will start the long journey back to interest rate normalcy. Whatever that happens to be.
Brent crude of course continues to be vulnerable. Not only does the market worry about war but it worries about tightness of supply. Forget Syria, Libyan oil production is taking its toll that even Libyan refiners have to close. High quality crude is getting harder to get and that means that Brent crude is most likely to spike. Not to mention Iraq where pipeline attacks and violence has impacted Iraq production.
It also means that the world will look to the U.S. to use their newfound production and refining capacity to fill the void from European refiners that will soon go into big time maintenance. Amrita Sen, chief oil market strategist at Energy Aspects Ltd., the new must have report says that planned maintenance will lower European refining capacity by 1.3 million barrels a day in September and 1.6 million in October and will reduce crude demand by 900,000 barrels a day.
Of course that means if the U.S. strikes, then Brent crude will lead any price surge. President Obama will arrive at the G20 and will try to make his case to the world that they have to act on Baser Assad and his regime. His host, Vladimir Putin, will be a tough sell and the market will wait to see if we get any sign that Putin will ease his opposition to an attack.
The American Petroleum Institute seemed to give the market a bit of support when it reported that crude oil inventories fell by 4.2 million barrels. Refiners are still running at a very high 91.0 clip and that came as gas stocks fell by 387,000 barrels and distillate stocks 109,000 barrels. It means that demand is very good and U.S. exports are running at a very high rate.
Today we get the Energy Information Administration report not only on petroleum but also on natural gas. Natural gas has been soaring on hot temperatures down south, but also on tropical storm activity. Tropical storm Gabriel has formed and should turn and go up the coast and miss the Gulf but there is a storm ahead of it and one behind it.
The Energy Information Administration reported, in its “Today in Energy,” that Underground natural gas storage fields in the American Gas Association's (AGA) East region have neared their capacity limits before each winter since 2005. Storage field utilization in the East has ranged between 87% to 92% before November of each year despite changes to market conditions. However, storage capacity utilization varies by region because of differences in weather patterns, types of facilities, pipeline constraints, proximity to supplies, and regulations. Storage levels and available capacity for working natural gas, or natural gas that is used for withdrawal, respond to a different set of factors in each region:
•East region. For many states in this region, local distribution companies are legally required to purchase and store working gas to ensure sufficient inventories to meet increased winter demand. As a result, working gas storage capacity generally tends to be full in the East by the end of October, regardless of weather and market conditions. The region consistently uses close to or above 90% of its working gas storage capacity by the end of October.
•Producing region. End-of-October capacity utilization levels vary more in this region, mainly because of the prevalence of salt cavern facilities. As of December 2012, salt caverns accounted for 407 billion cubic feet (Bcf), or 27%, of the 1,522 Bcf total working gas design storage capacity in the Producing region. These facilities operate under high pressure, facilitating quick turnaround for injections and withdrawals. This enables market participants in the region to more immediately respond to short-term price fluctuations. Injections and withdrawals thus follow a more flexible schedule, causing end-of-season storage levels to vary. In the past five years, working gas storage levels at the end of October have varied from roughly 74% of available storage capacity (2008) to 92% of capacity (2009).
•West region. As in the East region, storage operators in the West use their facilities to ensure that inventories are sufficient to meet increased demand during the winter months. Also, both interstate and intrastate natural gas pipelines use Western storage facilities to support load balancing. Storage levels are relatively stable and generally lower than in the East and Producing regions, due largely to unused capacity in depleted wells in areas such as the Williston Basin that do not have easy access to areas of high demand, although they have increased in recent years. Since 2005, end-of-October working gas storage capacity utilization has been between 59% and 72%.
The Producing region differs from the East and West regions in that its salt cavern storage facilities require lower volumes of base gas, which is natural gas required to maintain adequate pressure in the facilities. Since the beginning of 2012, base gas has accounted for about 41% of total storage capacity in the Producing region, versus 53% in the East region and 46% in the West region. This difference in the base gas required means that a relatively greater portion of storage capacity in the Producing region can be set aside for working gas. Changes in the Producing region's pre-winter working gas inventories have driven changes to overall inventories in the Lower 48 states.
The Short-Term Energy Outlook projects that U.S. working inventories will reach 3,800 Bcf by the end of October 2013, with April-October injections similar to those in 2008–11, but much higher than in 2012, when October 31 inventories reached a record 3,930 Bcf. Projected inventory levels for October 31, 2013 are lower than those for the same date in 2012 because of increased withdrawals in the Producing region during a colder 2012–13 winter, along with flattening production in 2013.