Southern California is poised to have greater natural gas supply flexibility this winter, buoyed by improved access to local storage and the completion of repairs on an important inbound pipeline. Ongoing pipeline outages and maintenance had limited flows over the past few years, creating supply constraints that were then compounded by restricted access to the Aliso Canyon storage field. This led to major volatility in gas prices, which spiked as high as $39/MMBtu in July 2018. Recent repairs and regulatory changes aim to alleviate the situation and limit the likelihood of dramatic pricing moves during the 2019-20 winter season. Today, we provide an overview of recent developments in the SoCal gas market.
With another month of anemic storage injections in September, Alberta natural gas storage levels remain on track to start the next heating season at a 13-year low. Still, while Alberta gas storage has been lagging well behind in terms of average injection rates and storage levels for many months now, forward winter contract prices for the Western Canadian gas price benchmark of AECO have budged only a little. There is potential for an improvement in storage injection rates during October after a recent regulatory approval affecting the Alberta gas pipeline system, but there is little time remaining in the current injection season to make much of a difference in inventory levels going into winter. Today, we conclude this two-part series with a look at why the AECO forward market remains largely unconcerned with low Alberta gas storage levels.
Alberta natural gas storage, one of the largest regional storage hubs in North America, is experiencing one of its slowest cumulative storage injection rates in years and could be headed to a 13-year low for storage levels by the end of the current injection season. That may seem ominous for the chilly Alberta and Canadian winter heating season, not to mention gas exports to the U.S. So far, though, winter gas forward prices for the Western Canadian gas price benchmark of AECO have registered a relatively modest market response, staying in line with last winter’s average spot price. Today, we take a closer look at the market’s apparent lack of concern over low Alberta gas storage.
Thanks to the shale revolution, U.S. refiners have spent the better part of the last two years achieving milestones in export volumes and run rates. The U.S. exported record volumes of gasoline and diesel last year. Much of that newfound international market share came at the expense of ailing refining complexes in Latin America, particularly in Mexico. That worked out great for U.S. refiners on the Gulf Coast, who could load up a tanker of fuel and have it delivered within a matter of days. Now the market on both sides of the border is shifting; the political landscape has changed in Mexico and gasoline demand growth in the U.S. is threatened by higher oil prices. Today, we lay out factors impacting exports and demand in the U.S. gasoline market.
During the first 7 months of 2015 the U.S. experienced record setting refinery crude processing and utilization rates. By the end of July crude inputs topped 17 MMb/d for the first time and nationwide refineries ran at over 96% of operable capacity - reaping the rewards of robust margins. But the party has been marred by a number of unexpected outages – the latest of which brought down a 250 Mb/d unit at BP’s Whiting, IN refinery last weekend – causing a spike in Chicago gasoline prices. Today we ponder why outages may be occurring and the upcoming impact of overdue fall maintenance.
In spite of a brief respite provided last week by increased geopolitical risk in Saudi Arabia, crude oil prices are still in the $50/Bbl range – down more than 50% since last Summer - and inventories at Cushing and on the Gulf Coast continue at record levels. The fall in crude prices was initially consistent across markets with international benchmark Brent trading within $1/Bbl of U.S. benchmark West Texas Intermediate (WTI) and Gulf Coast marker Light Louisiana Sweet (LLS) in January 2015. But since February the relationship between Brent, WTI and LLS has changed as the build up of Cushing inventories weighs on prices in the Midwest. Today we provide an update on crude price differentials at The Gulf Coast.
Freezing weather along the Atlantic Coast has disrupted refinery operations threatening supplies of refined products – in particular distillates – in an already tightly balanced market. The resultant spike in heating oil prices has encouraged European traders to ship cargoes to New York – a reversal of flow patterns seen in recent years. Today we look at northeast distillate fundamentals and explain why European imports are headed across the pond.
While producers are licking their wounds after a more than 50% oil price crash, refiners have continued to enjoy healthy margins – even in the face of the largest refinery strike since 1980. Strong refining margins, supported by an ongoing boom in refined product exports, continue to encourage high levels of refinery utilization in the Gulf Coast region – home to more than 50% of U.S. refining capacity. Today we look at how Gulf Coast refiners are faring after the oil price crash.
A week ago (September 8, 2014) we looked at Energy Information Administration (EIA) supply/demand data for the Gulf Coast Petroleum Administration for Defense District (PADD) III. Our analysis highlighted the dramatic changes since 2011 to the sources of crude oil for PADD III refineries that make up 50 percent of the nation’s processing capacity. Today we present a Gulf Coast crude supply demand forecast out to 2019 based on our assumptions about production, imports and refinery capacity as well as exports and movements in and out of PADD III.
Looking out over the next year and a half to 2016, Houston crude storage capacity looks to be lower than necessary to meet operational needs. With continuing increases in pipeline crude streams headed into the area in the next six months, we could see supply disruptions with consequences for price volatility. Probable victims of these disruptions would be producers looking to find a home at Houston refineries for their production. The solution is to build more storage but the market is not yet sending alarm signals to that effect. Today we conclude our series on Houston storage capacity.
Ever since US crude production began to increase in 2009 after 40 years of decline from its peak in 1970, refineries have been processing higher crude volumes. This summer (2014) crude processing volumes have been higher than at any time since the Energy Information Administration (EIA) began keeping records in 1982. Abundant supplies of reasonably priced crude in all regions as well as low refinery fuel costs are giving US refiners good reason to crank up their output. So much so that in the Midwest refinery output reached over 100 percent of capacity early in July. Today we describe the refining bonanza and how things might change in the not too distant future.
After tracking within $1/Bbl or so of each other for years, international benchmark Brent crude suddenly began to trade at a higher premium to US benchmark West Texas Intermediate (WTI) in 2010. The Brent premium widened out as far as $28/Bbl in November 2011 and averaged $18/Bbl in 2012. But during 2013 the relationship calmed down some to average $11/Bbl and in 2014 so far has averaged $8.11/Bbl – closing lower at $5.17/Bbl yesterday (June 10, 2014). Today we provide an update on the Brent/WTI crude price relationship.
Yesterday (April 30, 2014) the Energy Information Administration (EIA) reported yet another increase in Gulf Coast inventories as of April 25 - adding 5.7 MMBbl to set a new record of over 215 MMBbl of crude. Stocks in the region are now 27 MMBbl above the 5-year average and even if refiners cranked up output to the highest levels ever (96.5 percent utilization) the surplus would take at least 3 months to get back to “normal”. Crude prices are being impacted as the premium of Light Louisiana Sweet (LLS) crude at the Gulf Coast over West Texas Intermediate (WTI) delivered to Cushing, OK has narrowed close to $2/Bbl. With no crude exports allowed to ease the surplus it looks like Gulf Coast prices will remain under pressure. Today we look at prospects of reducing the crude surplus.
Cushing crude oil inventories have fallen by 28 percent from 42 MMBbl on January 24 to less than 30 MMBbl on March 14, 2014 according to Energy Information Administration (EIA) data. Since the startup of TransCanada’s Cushing Marketlink pipeline at the end of January, outgoing crude pipeline capacity has exceeded inbound supplies at Cushing and the surplus has been headed to the Gulf Coast. Backwardation in the futures market has also encouraged shippers to move supplies out of storage. Today we begin a new series looking at the Cushing exodus and the resultant growing Gulf Coast stockpile.
The recent dramatic narrowing of the WTI discount to Brent to around $3/Bbl (from $23/Bbl in February) took place at the same time as Cushing, OK crude inventories fell by 23 percent. Both these events have been trumpeted as signaling an end to the three-year logjam preventing landlocked crude supplies from reaching the Gulf Coast by pipeline. Yet the turnaround in Cushing inventories owes as much to declining inflows to Cushing from Canada and West Texas as it does to a flood of crude to the Gulf Coast. An uptick in refinery consumption in the Midwest and falling prices on the CME NYMEX West Texas Intermediate (WTI) futures market (backwardation) have also played an important part in the drop in Cushing inventories. Today we look at what lies behind the crude inventory slide.