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.
In the five years since gas production began to take off in the Marcellus, gas processing capacity in the northeast has expanded nearly 13 times over from 600 MMcf/d to 7,600 MMcf/d. Natural gas liquids (NGL) production from those plants began to expand significantly in 2011 and is now over 245 Mb/d. Midstream companies have developed gas processing infrastructure from a small group of stand-alone plants into a fully integrated system designed to operate without the luxury of significant NGL storage capacity. Today we begin a new series describing how the innovative infrastructure build=out has overcome regional constraints.
Northeast natural gas prices have been flipped upside down over the last couple of years and have shown unprecedented weakness relative to Henry Hub due to capacity constraints preventing booming production reaching new demand markets. New infrastructure projects should relieve this congestion in the next two years but as we explain today, the current market view – expressed in the forward curve - does not appear to reflect that reality.
With prices for crude oil, natural gas and natural gas liquids still sagging, U.S. producers have been shifting their drilling focus to “sweet spot” wells in the nation’s most prolific plays, including the Permian Basin and the Eagle Ford. Capital spending plans for 2015 detailed the past few weeks show that, even with fewer active rigs and fewer new wells, hydrocarbon production in these best-in-class areas will continue to grow this year. As for next year and beyond, that depends. What does all this mean for NGL production—and expanded NGL-related infrastructure in the Permian and Eagle Ford? Today, we preview RBN Energy’s latest Drill Down report, which forecasts NGL production in the two plays and details existing and planned gas processing plants, NGL pipelines and fractionators there.
Last week (February 19, 2015) Enterprise Product Partners announced the start of line fill on their 780 Mb/d ECHO to Beaumont/Port Arthur pipeline. The new route will open access for Canadian heavy crude shippers on the recently completed Seaway Twin pipeline from Cushing to Houston to 1.5 MMb/d of refining capacity in Beaumont/Port Arthur including 0.3 MMb/d of heavy crude coker processing. These refineries were a key target of the Keystone-XL pipeline from Canada to the Gulf Coast that still awaits approval. Today we look at demand and competition for Canadian heavy crude on the Texas Gulf Coast.
Alan Greenspan coined the phrase "irrational exuberance" during his tenure as Federal Reserve chairman. He used it in a 1996 speech in reference to the excessively high prices of "dot-com" companies. He worried that assets were overvalued. Four years later, the dot-com bubble burst, confirming his concerns. Presently we are observing the last gasps of irrational exuberance in petroleum. Call it "petro-exuberance." This malady became apparent during a session on oil market issues at the World Economic Forum in Davos, Switzerland. Some panelists clearly had a case of irrational exuberance, an overenthusiasm no different from what we saw at the end of the dot-com and the housing crises.
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.
Will hold-by-production (HBP) drilling by producers acting to preserve their leases for the longer term end up sending U.S. oil and gas production volumes higher when energy fundamentals and prices suggest production should slow down? This has happened before, with one of the highest profile instances in the Haynesville Shale between 2009-13, leading to even lower natural gas prices. Could it happen again in the Marcellus this year? Today we continue our look at HBP lease provisions with a focus on the Marcellus.
Producer rates of return are far below where they were a few months back, and the Baker Hughes crude rig count is down 553 since November. A third of pre-crash crude rigs are now idled. That means that crude oil production will be falling soon, right? Not necessarily. There are a number of factors working to keep production up, not the least of which is the rapidly declining cost for drilling and completion services. Today we examine the impact of these factors, review RBN’s crude oil production scenarios and consider what it all means for the long-term relationships between prices, returns and production volumes.