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.
Daily energy Posts
Producers in the Bakken are making progress reducing the natural gas flaring that had put an unwelcome spotlight on the region. The fix, spurred in part by tightening regulations, is being made possible by the addition of new gas processing capacity and increased efforts to use “stranded” gas at the well-site. (A drilling slowdown associated with soft crude prices is providing an assist.) Today, we take a fresh look at what’s been happening on the flaring front in western North Dakota, where gas flares still light the nighttime sky.
The U.S. Midwest region is slated to get an infusion of cheaper Northeast natural gas supply later this year as the first of five new westbound pipeline expansions is expected to begin service in November. Already a couple of projects are moving gas to the Midwest from the Northeast. The Northeast-to-Midwest capacity will have a huge impact on the Midwest supply stack and consequently on prices. The Chicago Citygates forward curve shows prices flipping from premiums to discounts later this year. Today’s blog continues our look at how new pipeline capacity will re-shuffle the Midwest’s supply stack and change regional pricing.
Ever since crude oil prices began their precipitous fall in June 2014 market watchers have picked through the tealeaves of every OPEC statement - particularly those of Saudi Arabia - for signs of a change in policy. One widely watched signal comes every month when the Saudi’s publish differentials that determine the price customers pay for their crudes. Today we explain how Saudi pricing formulas work.
Fast-rising hydrocarbon production of “wet” natural gas in the eastern Utica and southwestern Marcellus has been creating tremendous opportunities for the small group of midstream firms that saw what was coming—and pounced. Gas processing capacity in the Utica/Marcellus as a whole now tops 7.6 Bcf/d, more than 12 times higher than five years ago.
Last year was a banner year for the sand mining companies that cater to the U.S. shale drilling services industry. That’s because in 2014 well operators significantly increased the amount of sand used to complete fracturing operations in shale plays – from an average of about 5 MMlb for a single well to 15 MMlb (7,500 tons) or more.
Cold weather, abundant supplies of natural gas and lower-than-normal winter gas prices spurred record power burns in January and February, and the power burn for the rest of 2015 is likely to be record-breaking too. It almost has to be; all the gas expected to be produced this year needs to go somewhere, and there’s only so much that can be stored. That suggests continued softness in natural gas prices—hardly good news for gas producers.
For years now, the international LNG trade has been based primarily on long-term contracts between buyers and sellers, and those deals have been indexed to oil prices. That long-standing regime is now tottering, however, and a New World Order that would add considerable flexibility to LNG trading—and increase the role of the LNG spot market—may be in the offing. That would have huge implications for U.S. natural gas producers who want to export increasing amounts of liquefied gas.
Natural gas production is growing faster in the Marcellus and Utica than any other part of North America. Even with lower prices, Appalachia natural gas production will probably hit record highs in the next few days, and NGL production is into the stratosphere, now more than four times where it was two years ago, growing on average 6% PER MONTH!
Newfield Exploration - the largest crude oil producer in Utah’s Uinta basin - has temporarily suspended new drilling operations there in response to lower prices. Other producers in the region have reduced their drilling and capex budgets as well. The cutbacks stem in part from the extra logistics expense required to deliver and process the thick yellow and black “waxy” Uinta crudes that do not flow at room temperature.
An average of 13 Bcf/d of natural gas flows into the Midwest from producing regions in Canada, the Midcontinent, the Southeast and the Rockies. Over the past 7 years the region has been in the crosshairs of major infrastructure and supply changes to the North American natural gas market, starting in 2008 with the Rockies Express (REX) pipeline and continuing today as surplus Northeast supplies reverse pipeline flows and push into the Midcontinent.
In the past 10 years Marcellus and Utica shale drilling has transformed the U.S. Northeast from a sleepy backwater of gas production into a powerhouse that (according to the Energy Information Administration) supplied 22% of total U.S. gas production in December 2014. NGL production from the region is already 8% of the U.S. total and likely headed toward 20% by 2020. These vast shale formations cover most of Pennsylvania, West Virginia and Eastern Ohio, but it turns out that most of the production comes from only 20 or so counties across those three states. Such geographic concentration has significant implications for regional infrastructure development and capacity. Today we describe where producers have found success in the region.
As if there weren’t enough reasons to add new natural gas pipeline capacity through New England, it’s time to consider another: the Sable Island and Deep Panuke gas production areas off the coast of Nova Scotia are quickly losing their oomph, and soon the Canadian Maritimes will need to rely more heavily on gas from other, more distant sources, including the Marcellus. Developing pipelines to move large volumes of Marcellus gas through New England to New Brunswick and Nova Scotia will not be easy though. Today we continue our look at the challenges of supplying gas to New England and its northern neighbors.
The proposed 400 Mb/d Shell Pipeline Company Westward Ho pipeline from St. James, LA to Nederland, TX was first touted in 2011 and initially expected to be in service by Q3 2015 but is now delayed at least until the end of 2017. The project is designed to replace the Shell Ho-Ho pipeline that used to ship crude from Louisiana to refineries on the Texas Gulf Coast until it was reversed in 2013. Westward Ho has struggled to attract shipper commitments to bring additional crude into the saturated Texas Gulf Coast market. Today we review the project’s rationale.
Does it make sense to build natural gas pipeline capacity that will only be used a few weeks a year? That’s a question that continues to spark debate in New England, where the existing pipeline network is sufficient most of the year but unable to supply the region’s growing number of gas-fired power plants during the coldest winter days. What’s the answer? Building gas pipeline capacity that will remain largely unused? Relying on oil and LNG as a permanent gas-supply backup for power generators? Or maybe building pipeline capacity to provide not only peak, wintertime service to generators but off-peak service to LNG exporters? Today, we continue our look at a vexing dilemma with major implications for Marcellus gas producers.
U.S. crude stocks are at their highest level in over 30 years and the contango market pricing structure continues to encourage increases in the stockpile. No one knows exactly how much storage space remains. The surplus is keeping U.S. crude prices low compared to international rivals but petroleum product prices (gasoline and diesel) are climbing higher, having bounced back from recent lows. Refining margins are sky high as bad weather and outages hamper operations. But as we describe today, the crude surplus remains a dark cloud on the horizon.