Despite sagging oil and natural gas liquids (NGL) prices, investments in expanding midstream infrastructure continue in the Permian Basin and Eagle Ford. In the past several weeks, Energy Transfer Partners (ETP) said its Lone Star NGL unit will build a 533-mile NGL pipeline from the Permian to the Mont Belvieu, TX fractionation hub, and the company announced plans for a 200 MMcf/d natural gas processing plant along its Rich Eagle Ford Mainline natural gas pipeline (and another in the Eaglebine/Eagle Ford East). Today we continue our company-by-company look at midstream infrastructure development in the Permian and Eagle Ford with a focus on Energy Transfer.
Last week’s clarification from the Bureau of Industry and Security (BIS) about the process required to export lease condensate may make exports easier on paper but it won’t stimulate export demand. The BIS move is timely because available exports of this light hydrocarbon material could increase significantly, depending on what happens to crude prices. However current low price levels and questions about future overseas demand could diminish the significance of the BIS process improvements. Today we describe the BIS clarifications and whether they are likely to make a difference.
Welcome to 2015! No, the last few months of 2014 were not a dream – or nightmare, depending on your perspective. Crude oil prices really did come crashing to earth, sucking down NGL prices in the process. And natural gas prices followed, falling to $3/MMbtu last week. Price relationships are out the window, as are drilling budgets. Over the next few months, these markets will be going through some of the most dynamic changes in years, with unpredictable consequences. Unpredictable? Nah. No mere market turmoil will dissuade RBN from sticking our collective necks out a third year in a row to peer once more into the crystal ball. Today we wrap up RBNs Top Ten Energy Prognostications for 2015 – Year of the Goat – #5 to #1.
Time to sober up. Not from excessive New Year’s Eve reveling, but instead from the past five years of euphoria in the shale oil and gas markets. In the past two months crude oil prices have come crashing to earth, sucking down NGL prices in the process. And lately even natural gas has succumbed to the malaise, falling below $3/MMbtu this week. Price relationships are out the window, as are drilling budgets. Over the next few months, these markets will be going through some of the most dynamic changes in years, with unpredictable consequences. Unpredictable? Nah. No mere market turmoil can dissuade RBN from sticking out our collective necks to peer into the crystal ball for a third year in a row for 2015 – Year of the Goat. Really. We did not make that up.
In time honored RBN blogging tradition – we’ve been at this blogging business three years –we look back today at the 250 blogs posted this year to see which ones had the highest hit rates. The number of hits any blog gets tells you a lot about what is going on in the energy markets – which topics resonate with our members, and which don’t attract much attention. Last year the big hitter blogs came in about 17,000 hits. This year the big numbers are closer to 50,000. With that many folks paying attention these days it is even more important that we take a page out of the late Casey Kasem’s playbook to look at the top blogs of 2014 based on numbers of website hits.
It would be an understatement to say that the worldwide market for liquefied natural gas (LNG) is in flux. LNG production is up and heading higher, oil—and LNG--prices are down sharply from a few months ago, and Japan and other big consumers of LNG are more interested than ever in mitigating price and supply risk. All this comes as Japan, a primary target of prospective U.S. and Canadian LNG export projects, is grappling with the need to restart dozens of idled nuclear units so it can reduce the oil and LNG imports that have hurt its trade balance since the Fukushima disaster nearly four years ago. Today we consider recent developments and how they may affect Japan and its potential LNG suppliers on the North America side of the Pacific.
It’s been a big year for oil production from the Bakken formation in North Dakota with output passing the 1 MMb/d mark in April and expected to close out 2014 at 1.25 MMb/d. Crude netbacks (market price less transport cost from the wellhead) suffered during the first half of the year from narrowing coastal price differentials - denting the economics of crude-by-rail - the most popular option to get Bakken crude to market. Rail freight costs look set to increase in 2015 with new tank car regulations and requirements for wellhead treatment to remove volatile components. But those changes pale into insignificance compared to the recent crude price nosedive. That threatens to reduce producer revenues by billions of dollars in 2015 and puts the spotlight on higher transport costs to get crude to market from North Dakota. Today we look at the financial impact lower netbacks could have on Bakken producers.
It remains to be seen to what extent the recent crash in oil prices--and the sympathetic decline in prices for natural gas liquids (NGLs) - will lead to major drilling and production pull-backs in some U.S. shale plays. What seems clear, though, is that the higher-grade, liquids-rich areas at the heart of the Eagle Ford and Permian Basin will continue to experience at least modest levels of drilling activity and still-strong production for some time to come. That should provide considerable relief to the midstream companies that have been investing heavily in NGL infrastructure in the Eagle Ford and Permian the past few years. Today, we continue our company-by-company look at existing and planned natural gas processing plants, fractionators and NGL pipelines in two of the most productive plays in the U.S.
Most of the heavy crude oil arriving at the busy Hardisty hub in Alberta that throughputs up to 3.5 MMb/d – is already blended with diluent supplied closer to the production fields to the north. The diluent supply infrastructure to the oil sands today and planned for future expansion is primarily directed from Edmonton. But Hardisty fills an important role in final blending before the crude oil cocktail is transported to market. Today we round up our survey of Hardisty diluent requirements.
Crude oil production in the Gulf of Mexico is on the rebound, and headed into record territory as the fifth anniversary of the Macondo blowout approaches. Several major deepwater projects--including Hess and Chevron’s Tubular Bells—are starting to produce oil after years of development, and others will follow in 2015 and 2016. The gains in GOM crude production are significant; daily output now stands at about 1.5 MMb/d, and it’s seen rising to 2 MMb/d within three years. In today’s blog, “Tubular Bell—Gulf of Mexico Oil Gains Exorcise Macondo’s Ghosts,” we examine the resurgence in GOM oil production, and the reasons why recent investments in deepwater drilling may well pay off despite the oil price crash.
We saw a slight recovery in crude prices Friday (December 19, 2014) with CME NYMEX West Texas Intermediate (WTI) futures up $2.41/Bbl from Thursday’s close. At the same time CME NYMEX Henry Hub natural gas futures were down $0.18 to $3.464/MMbtu. That meant the crude-to-gas price ratio between these two commodities was up 1.5X to 16.3X from it’s recent low under 15X on Thursday. However futures markets indicate that market expectations for the crude-to-gas ratio are for it to remain at a low level between 15X (i.e. WTI in $/Bbl is 15X Henry gas in $/MMbtu) and 17X for most of the next decade. If that turns out to be true there are serious implications for shale drilling, gas processing and LNG export prospects in the U.S. Today we look at what may happen and why.
In the dead of the natural gas winter season when US producers count on strong margins from higher gas prices, the Transco Z6 New York hub is trading on average nearly flat with U.S. benchmark Henry Hub, LA – the delivery point for the CME NYMEX natural gas futures contract. This is a dramatic departure from historical winter norms in the Northeast market, where prices relative to Henry and just about every other gas hub in the Northeast have traditionally carried hefty premiums in the winter. Moreover, the forward curves indicate these basis levels are the new norm for Northeast pricing. The forward curve for Transco Z6 New York shows basis for 2015 barely above Henry Hub for the year, with several months at more than $1.00/MMBtu discount. Today we look at what’s behind major changes in northeast forward curves.
The need for natural gas processing capacity, new or expanded NGL pipelines and other infrastructure in the Permian Basin and the Eagle Ford has spurred a competitive frenzy among midstream companies. NGL production in the two prolific regions has more than doubled in the past four years; it now tops 1.1 MMb/d. Under RBN’s Growth Scenario that assumes output will continue to increase over the near term despite the recent price slump – production in the two regions would rise another 500 Mb/d by 2019. Given that infrastructure in parts of the Permian and Eagle Ford already is struggling to keep pace, it is quite possible that midstream companies will continue to develop new projects. Today, we begin our company-by-company look at existing infrastructure and planned projects.
West Texas Intermediate (WTI) CME NYMEX crude futures settled yesterday at $55.93/Bbl, down 52% since June 2014 and NYMEX Henry Hub natural gas futures settled at $3.619/MMBtu. The crude-to-gas ratio of these two energy commodities - meaning the crude price in $/Bbl divided by the gas price in $/MMBtu - was just over 15X. We have not seen a crude-to-gas ratio at this level since June 2010. Over the past 4 years the ratio has been far higher - averaging 27X and reaching a high of 54X In April 2012. That lofty four year run for the crude-to-gas ratio has arguably been responsible for much of the crude and natural gas liquids production boom since 2011 and a “Golden Age” of natural gas processing. Today we begin a two part series on the implications of a lower crude-to-gas ratio.
Developing new natural gas pipeline capacity in the Northeast isn’t easy. Environmental rules are tough, local citizens are well-organized, and—in New England in particular—the electricity market structure is not, shall we say, pipeline development-friendly. Still, with gas needs in the region rising, and all that Marcellus gas close at hand, midstream companies are doggedly and creatively pursuing pipeline projects, and making some headway. Today, we update efforts to advance the Constitution Pipeline, the Northeast Energy Direct project, and Access Northeast, all of which are planned to help move Marcellus gas into the heart of New England.