The combination of crashing crude prices and freight costs for long distance transport to refinery markets is tightening pressure on Bakken crude producer break-even economics. There is plenty of more expensive rail transportation capacity and not enough cheaper pipeline capacity to carry all production to market. For the moment producers appear to be sticking to favored markets on the East and West Coasts that can only be reached by rail. New pipeline capacity is two years away. Today we review the big shifts in North Dakota crude transport options.
The recent collapse in oil prices has thrown into question the future levels of crude, natural gas and NGL production in, among other places, the Permian Basin and the Eagle Ford. That will lead midstream companies to take a fresh look at the two regions’ existing and planned infrastructure to make sure they still are in line with pipeline, processing and other needs. Today, we conclude our series on the two regions’ natural gas processing plants, NGL pipelines and fractionators with a look at where we stand, and what’s ahead.
With crude prices close to six year lows and the futures market pointing higher, a number of the larger commodities trading houses are buying and holding cheap crude in huge floating tankers for later sale. For the trade to work, prices today must be lower than they are in the future and the spread must cover the storage cost and other expenses. Players in the floating storage game have to be high rollers – the minimum cost of a bet at this table is ~$100 million. Today we complete a two-part series on contango-spread trades with a look at floating storage.
Mexico probably has enough shale gas to meet its needs ‘til the vacas—or cows—come home. For technological, security and other reasons, though, it will take years for that now-trapped gas to be tapped on a large scale. In the meantime, Mexico is turning to U.S. gas suppliers, and billions of dollars of new pipelines are being built to transport vast amounts of gas south of the border from the Permian Basin, the Eagle Ford and other plays to run Mexican power plants and factories. Today we consider recent developments in U.S. gas exports to our southern neighbor.
Many in the Northeast are digging out from what turned out to be a typical snowstorm – not a “Superstorm”. Thanks to worse crises in the past, however, a federal Northeast Home Heating Oil Reserve was set up in 2000 and--thanks to Superstorm Sandy--federal and New York gasoline strategic reserves were put in place much more recently. The winter propane crisis of 2013-14 also sparked talk of a possible strategic reserve for propane. The theory behind establishing these stockpiles is that in markets that depend heavily on steady, reliable flow of energy products it’s important to have a cushion, a squirreled-away supply to avoid the price spikes and near-panic that can follow the words, “Sorry folks, we’re all out.” Today we examine what’s been done, how it’s worked, and what might be next.
The NYMEX gas futures curve for 2015 was sitting right at $3.00/MMBtu yesterday (January 27, 2015) as colder weather has halted it’s recent slide. This still puts outright prices in the Northeast gas forward curve in dangerous territory for producers – very close to breakeven levels – through 2015 and not much higher even beyond this year. With NGL prices no longer supporting drilling activity for many producers in the region, the gas forwards market is becoming a bigger factor in signaling producers’ drilling prospects. Today in Part 3 of our Forward Curve Series, we continue our look at Northeast forward curves, with a focus on the Dominion South Point price hub, its historical shape and the fundamentals behind where it stands now.
An ugly combination of sagging overseas demand for liquefied natural gas (LNG), new LNG supply coming online in Asia and cheaper oil dragging down prices has taken some wind out of the sails of U.S. LNG export prospects. After all, the LNG export boom was premised on rising world LNG demand and the pricing of gas at Henry Hub natural gas levels—a welcome alternative to traditional suppliers indexed to what used to be higher cost oil. The question becomes, will these setbacks just slow the pace of new LNG export projects in the U.S., or will the potential market be limited to the projects already locked in? Today, we consider recent developments and what they mean for LNG export projects—and U.S. natural gas producers.
On Friday (January 23, 2015) West Texas Intermediate (WTI) futures prices closed under $46/Bbl for the second time this year. RBN’s analysis of producer internal rates of return (IRRs) for typical oil wells indicates that Bakken IRRs have fallen from 39% in the fall of 2014 to just 1% today. IRRs for typical Permian wells are down to 3% and typical Eagle Ford wells are at breakeven. Everything is underwater or close to it except for the sweet spot wells with higher production. Today we present highlights from RBN’s IRR and breakeven analysis – published in full today in our latest Drill Down Report.
Since the start of 2015, crashing crude prices have opened up a new opportunity for traders to profit while producers bite their nails. In today’s oversupplied market, prices for prompt delivery are lower than they are for further out months – a market condition known as contango. That’s when traders put on contango spread trades that involve buying and storing crude to sell at a higher price later. Rapidly rising crude inventories at Cushing (up 3MMBbl last week according to the Energy Information Administration - EIA) suggest it’s a popular strategy. Today we explain how the trade works at the Cushing, OK trading hub.
The prolific, liquids-rich Permian Basin and Eagle Ford plays have attracted more than a dozen midstream companies interested in meeting the growing need for natural gas processing plants, fractionators and natural gas liquids pipelines. Some of the larger players have assembled broad-based portfolios of assets, while others have focused on more stand-alone NGL pipeline or gas processing investments. Today we begin wrapping up our series on NGL-related assets in two of the nation’s most important shale plays.
CME NYMEX crude oil prices were down again yesterday – with the West Texas Intermediate (WTI) contract closing at $46.39 down $2.30 over the holiday weekend and over 55% lower than its high 7 months ago in June 2014. Some are billing the free fall in crude prices as a showdown between U.S. shale producers and OPEC. That is because OPEC has apparently decided not to cut production to prop up prices in an over supplied market in hopes that lower prices would squeeze out U.S. shale producers. If that was the strategy then it isn’t working so far. Today we review crude producer plans for 2015 and find lower capital expenditure budgets and cuts in rig deployment contrast with expanded production.
There was no open outcry trading on the CME NYMEX yesterday because of the MLK holiday but after rallying on Friday U.S. crude prices resumed their descent here in electronic trading and the London ICE Brent contract lost $1.40/Bbl to close at $48.77/Bbl. Unsurprisingly the Baker Hughes oil drilling rig count is down by 209 (13%) since December 2014 as producers take a hard look at their production budgets. Yet production is still expected to increase in the short term – in part because the rigs that are left will focus on “sweet spots”. In today’s blog “It Don’t Come Easy – Low Crude Prices, Producer Breakevens and Drilling Economics – Part 2” Sandy Fielden looks at the assumptions behind RBN’s IRR and breakeven scenario analysis.
The half-century stand-off between the U.S. and Cuba appears to be ending, and improving relations could, over time, bring experts in Gulf of Mexico oil and natural gas exploration and production to the waters off Cuba’s northern coast. A lot of questions remain, though, chief among them how extensive Cuba’s offshore reserves really are and—just as important—how long it might take for a still-Communist Cuban government to warm up to working with energy-sector capitalists. Today we consider the long-term potential for hydrocarbon development in Cuba’s corner of the Gulf.
Lately the ethane market seems out of whack. Ethane production continues to increase even as it’s become the lowest margin (highest cost) feedstock for Gulf Coast petrochemical crackers – it’s main market. Ethane production by processing plants has been at an all-time high since June this year even as ethane prices fell to historical lows. Meanwhile, ethane inventories have fallen from their recent peak in July. How can all that make sense? Today we speculate as to what may be going on.
One positive element to the oil price crash is that consumers are paying less at the pump for their gasoline. Of course it is natural that prices at the pump don’t fall as fast as they do in spot or futures markets – there is a lag – usually measured in days. However, while average retail gas prices have fallen over $1/Gal in the past year – more or less in line with spot and futures markets, it seems that changes to diesel prices at the pump have lagged further behind refinery prices. The result is that retail buyers filling their diesel truck at the pump have benefited far less from the oil price windfall than gasoline powered vehicle owners – at least so far. Today we review the data.