The U.S. natural gas market is carrying about an 850-Bcf surplus in storage versus last year and the 5-year average. But it looks like the surplus will finally start to contract in earnest over the next few weeks. So the big question is -- will it be fast enough to prevent crippling supply congestion by this fall? With Canadian storage inventories also high and U.S. gas production still averaging slightly higher than last year, it seems record demand will be needed to bring storage into balance. Today we look at the prospects for demand this summer to trump last year’s record demand.
On December 18, 2015, Congress and President Obama ended the 40-year ban on U.S. crude oil exports to countries other than Canada. Today the arbitrage window doesn’t make much economic sense for most exports – Light Louisiana Sweet on the Gulf Coast is about the same price as Brent in the North Sea. But the prospect of selling crude abroad remains tantalizing for a depressed U.S. upstream, and U.S. producers have begun to consider the possibilities for more significant export volumes. But does the U.S. have the right stuff? Will the qualities of U.S. crudes be competitive in global markets? In today’s blog, we begin a series to consider the qualities of U.S. crudes that are likely to be favored by international crude buyers.
With the first month of storage injection season now behind us, the weekly storage report from Energy Information Administration (EIA) shows U.S. natural gas stocks at about 850 Bcf higher than last year. While the surplus vs. 2015 has contracted from over 1,000 Bcf at the start of injection season April 1, it has a long way to go before the gas market is out of the woods, and prices are reflecting that. The CME/NYMEX Henry Hub contract for June delivery settled Wednesday at $2.141/MMBtu, down 68 (24%) from last year, and the balance-of-summer strip is priced at an average $2.408/MMBtu as of yesterday’s settles, 48 cents (17%) lower than a year ago. Given the sheer size of the overhang at this point, the pace of the surplus contraction will be at least as important to price direction as the fact that it is contracting. Today we look at the various supply and demand factors that could either help or hinder the market to whittle down the storage surplus this summer.
Shell Chemicals is taking steps that suggest it finally may be ready to pull the trigger on a long-debated petrochemical complex which would include an ethylene plant (steam cracker) and three polyethylene units in the heart of the “wet” Marcellus/Utica natural gas liquids production region. If the $3+ billion project advances to construction soon, it would significantly impact ethane market dynamics, not just in Ohio/Pennsylvania/West Virginia but along the Gulf Coast too. And if it turns out we’re in for extended stagnation in drilling and production, the Shell cracker also may undermine plans to build additional NGL pipeline capacity out of the Marcellus/Utica—or any other cracker there. Today we discuss the likelihood of Shell proceeding with its Beaver County, PA cracker and the effects the project’s development might have.
On Friday of last week, two more large E&Ps filed for Chapter 11 – Ultra petroleum with $3.8 billion in unsecured debt and Midstates Petroleum filing with a $2 billion debt-for-equity swap deal. Over the past 18 months there have been 65 E&P bankruptcies – mostly small companies, but nine companies make up 75% of the $28 billion in total debt exposure of all of these firms. This chaos in the oil, gas, and NGL markets is having all kinds of financial and strategic ramifications. One of the consequences of all of the turmoil could be a wave of asset sales, demands for contract restructuring, and more bankruptcy proceedings. But there can be some real opportunities in all this chaos if you know what to look for, understand where the needs and pitfalls can lie, and especially to recognize that “the sun’ll come up tomorrow.”
More than 3,000 MW of new, natural gas-fired generating capacity is either under construction in New England or will be soon, but some of the gas pipeline projects that would ease long-standing constraints into and through the six-state region have hit rough patches. Kinder Morgan in mid-April suspended plans for its Northeast Energy Direct project, a “greenfield” pipeline across Massachusetts and southern New Hampshire, and a few days later the state of New York denied the co-developers of the already-delayed Constitution Pipeline—a key link between the Marcellus and New England--a needed water quality permit. The fates of some other major projects in the Northeast are uncertain too. Today, we provide an update on pipelines in the land of Yankees and Red Sox.
Fueled by soaring domestic production of natural gas liquids (NGLs) like propane and butane, U.S. liquefied petroleum gas (LPG) export volumes the past three years have rocketed to the top, surpassing exports by the old Big Three of LPG: United Arab Emirates, Qatar and Algeria. But that rise in LPG exports may be ending, and the share of exports made from Gulf Coast docks may be in for a decline. More propane and butane will be pulled from the Marcellus and Utica to the docks at Marcus Hook, PA, and demand for propane on the Gulf Coast—from new propane dehydrogenation plants and flexible steam crackers—will be climbing. That suggests that less LPG may need to be exported from the Gulf Coast to keep the market in balance. In today’s blog we continue our look at the soon-to-open Panama Canal expansion with an updated examination of U.S. LPG export terminals along the Gulf Coast.
The prospects for an ever-expanding boom in propane exports from the U.S. Gulf Coast are dimming, even as export volumes stand at near-record levels and as new export capacity continues to come online. Why? It comes down to supply and demand. With oil and NGL prices at today’s levels, propane production is leveling off, not rising, and U.S. Gulf Coast domestic demand for propane will be increasing—from new propane dehydrogenation (PDH) plants and propane’s use in ethylene steam crackers—at the same time that export volumes out of the East Coast are quadrupling. In today’s blog we consider the possibility that what goes up must come down.
In connection with year-end 2015 earnings announcements, North American exploration and production companies (E&Ps) continued to announce large reductions in 2016 capital budgets. But the most dramatic news is that RBN’s analysis of a study group of 30 E&Ps indicates that these companies are finally expecting oil and gas production to fall in 2016 after a 7% gain in 2015. In today’s blog we update our continuing analysis of E&P capital spending and oil and gas production guidance.
Several new propane dehydrogenation (PDH) plants are coming online along the U.S. Gulf Coast. Now developers in Alberta are making plans for the province to become the next hot spot for PDH plant development. Final Investment Decisions (FIDs) are due over the next year or so on two projects aimed at taking advantage of the increasing volumes of propane being produced in western Canada—propane so plentiful, in fact, that they are paying to have it hauled off. But what if propane prices rise due to increasing U.S. demand, more exports and lower U.S. production? What might such developments do to PDH economics? What could make Alberta different? Today, we consider the drivers behind two (maybe three) prospective PDH projects in Alberta, and look at how they may affect the propane market on both sides of the 49th parallel.
The story of crude-by-rail (CBR) in North America is that of a victory of good old U.S. ingenuity over the lack of pipeline capacity that stranded booming shale oil production in 2012. The lower cost to market of “on-ramp” rail terminals allowed surging crude production a route to (mainly) coastal refineries - igniting a building boom over 4 short years that has left 82 load terminals and 44 destination terminals operating today - many of them now underutilized. Along the way monthly lease rates for rail tank cars that reached $2,750/month at the height of the boom are down to $325/month after the bust – with many lease holders paying daily rent to park their empty cars. Today we conclude our series reviewing the state of CBR today.
The U.S. natural gas market ended the winter withdrawal season with inventories carrying a record high overhang and an enormous surplus versus previous years. Since then, the historic surplus has begun to contract, and the CME/NYMEX Henry Hub futures contract has responded, rallying 11.2 cents since April 1st to settle at $2.068/MMBtu Thursday. Now, well into the third week of injection season, the big questions are whether the recent bullishness can be sustained and what it will take to relieve the surplus in storage. In today’s blog, we assess how the existing surplus will impact summer storage activity and prices.
After a series of construction setbacks, the Panama Canal expansion is finally expected to come online by mid-2016. The wider, deeper canal locks will enable any LPG ship (up through Very Large Gas Carriers, or VLGCs) on the planet to take the time- and money-saving short-cut, and also will accommodate all but a few of the world’s biggest liquefied natural gas (LNG) vessels. That can only help U.S. liquefied petroleum gas (LPG) and LNG exporters, who for competitive reasons need the low transportation costs to Pacific Basin markets that shipping in super-bulk will provide. Today we discuss how the expansion project may boost exports of hydrocarbons from the U.S. Gulf Coast.
A year ago (April 2015) the price spread between Light Louisiana Sweet (LLS) the St. James, LA benchmark light crude and Permian West Texas Intermediate (WTI) delivered to Houston was roughly $2.50/Bbl. In the first quarter of 2016 – following the end of the crude export ban and the crash of crude prices below $40.bbl – that spread narrowed to 30 cents/Bbl. This price differential change has thrown a wrench into traditional Gulf Coast price relationships that encouraged the flow of crude east from Houston to Louisiana. Further changes are expected as pipeline projects due to be completed in the next two years will deliver Bakken and Permian crude direct to St. James. Today we wrap up our series on St. James with a look at changing crude prices and flows.
Mexico’s need to import increasing amounts of transportation and cooking fuels--mostly gasoline, diesel, and liquefied petroleum gas (LPG)—from the U.S. is spurring an infrastructure development boom on both sides of the Rio Grande. Over the past few years this has been a frequently reoccurring pattern: A fast growing market for hydrocarbons emerges, and the need to efficiently move increasing volumes of product from points A and B to points C, D and E quickly becomes urgent. All hands are called on-deck: trucks, railroads, barges, pipelines—plus storage facilities and distribution terminals. Today, we consider the latest initiatives to deliver gasoline, diesel, jet-kero and LPG from Texas to its southern neighbor.