Sarnia, ON is one of Canada’s leading refinery and petrochemical centers, and for good reason. From the start –– 158 years ago, with what Canadians claim to be the world’s first oil well in the Western Hemisphere –– the Sarnia area has had geology and geography on its side, and it doesn’t hurt that it’s within 500 miles of more than half the people in North America. But the interconnecting infrastructure that drives Sarnia’s Chemical Valley isn’t nearly as well known or understood as the pipelines, railroads, storage and refineries along the U.S. Gulf Coast. Also, it should be noted, Sarnia has become one of the biggest beneficiaries of Marcellus/Utica production of ethane and other natural gas liquids, the mother’s milk of the petchem sector. That alone makes it worth discussing. Today, we begin a series on a lynchpin of Canada’s hydrocarbon production and processing sector.
Crude oil has always been the big draw for producers in the Permian –– and in the especially prolific Delaware Basin within the Permian –– but the wells there also produce large volumes of “wet” natural gas that needs to be gathered, processed and transported to market. A lot’s been written about the Permian’s still-strong oil production and the infrastructure developed to support it; we’ve also covered natural gas liquids (NGLs) in the play. Now it’s time to delve into the gas processing and gas pipeline capacity out of West Texas and southeastern New Mexico, including pipes into the increasingly important Mexican market. Today, we discuss recent developments on the gas side of the U.S.’s hottest (remaining) oil production area.
Whether or not Shell Chemicals follows through on its plan to build a $6 billion ethylene plant near Pittsburgh, PA –– and when that steam cracker comes online –– will have a significant impact on the U.S. ethane, ethylene and polyethylene markets. By consuming an estimated 90-100 Mb/d of ethane, the cracker’s operation would reduce the volume of ethane that needs to be moved out of the “wet” Marcellus/Utica production area, trim the amount of ethane available for export from marine terminals, and likely push ethane prices higher than they would otherwise be. Today, we examine what’s driving plans for the Northeast’s first cracker, and what effects the plant will have.
Canadian ethylene plants have been receiving U.S.-sourced ethane by pipeline for two and a half years now, and waterborne ethane exports from Marcus Hook, PA to Norway started earlier in 2016. Soon the real fun will begin, when Enterprise Products Partners initiates (and quickly ramps up) ethane exports from a new, 200 Mb/d terminal on the Houston Ship Channel at Morgan’s Point. The destinations of the ships leaving Morgan’s Point are likely to be places like India, Brazil, Europe, and maybe even Mexico. Today, we consider the imminent bump-up in U.S. ethane export capacity, the international markets ethane will be headed to in the near-term, and the longer-term question about how much ethane exports can grow.
The U.S. Northeast now produces all the propane and butane it needs on an annual basis (Energy Information Administration - EIA PADD 1 plus Utica production from Ohio), but the seasonal nature of the region’s demand—and a dearth of in-region storage—means a lot of the natural gas liquid (NGL) production needs to be railed to storage facilities elsewhere during the warmer months, then be moved back in to meet wintertime needs. This propane/butane back-and-forth raises costs and reduces producer netbacks. Surely there is a better way. Today, we continue our review of NGL storage (or the lack thereof) in the Northeast, and how proposed NGL storage facilities in the region might help.
Every day, the “wet” Marcellus and Utica shale plays are producing significant volumes of ethane, all of which needs to be moved out of regional plants, fractionators and de-ethanizers immediately, either by “rejection” into natural gas or on pipelines to the Gulf Coast, Ontario, or to an export terminal in Marcus Hook, PA. A leading midstream company—MPLX’s MarkWest subsidiary—has developed an ingenious, integrated approach for handling much of that ethane (and dealing with any disruptions), but its ethane-management system is not a regional cure-all, and the likely development of an ethylene plant in the heart of the Marcellus/Utica would only increase the region’s ethane-handling needs. Today, we continue our examination of natural gas liquids (NGL) storage needs in the Northeast with a look at how nearby ethane storage might help midstream companies that are not integral parts of MarkWest’s “ethane loop.”
Ever-increasing production of natural gas liquids (NGLs) in the U.S. Northeast is highlighting—and exacerbating—what has always been a challenge for the region: a serious lack of nearby NGL storage capacity. In the years before NGL production took off in the “wet” Marcellus and Utica shale plays, this storage shortfall mainly affected propane and butane, with their very seasonal demand; the lack of Northeast NGL storage required a huge wintertime influx of propane and additional butane that had been stockpiled elsewhere. More recently, with Northeast NGL production booming, propane and butane barrels need to be moved out of the region by rail during the non-winter months and be railed back when the weather turns colder and motor gasoline blending limits are higher—killing producer netbacks in the process. Add to that a new (and equally vexing) challenge: dealing with the vast quantities of ethane being produced in the wet Marcellus/Utica. There is currently no in-region demand for ethane and (unlike propane and butane) you can’t just load surplus purity ethane onto rail cars. Today, we begin a series on the need for more NGL storage in the Northeast, and the pros and cons of a specific proposed storage project.
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.
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.
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.
Prices headed up!! That’s something that you haven’t heard much lately. But big changes are just over the horizon for NGLs as new petrochemical plants and export projects come online. These projects will encounter a market environment far different than what was expected when they were being planned. Instead of an oversupplied market driving NGLs lower relative to crude oil and natural gas, the projects will confront a tight market, with NGL prices higher relative to the other hydrocarbons. In today’s blog we explain why what must go up must come down, and vice versa.
Blood, Sweat & Tears 1969 hit, Spinning Wheel tells us: “What Goes Up, Must Come Down”, and U.S. propane stocks are no exception. Having built to a record 106 MMBbl the week of November 20, 2015, (according to the Energy Information Administration – EIA), storage congestion became the topic of the day, but while this record is noteworthy, what is far more significant is the rapid descent propane stocks have taken since late November in spite of the 2015-16 El Nino “winter of no winter”. This is the second non-winter that the U.S. has experienced over the past five years, the last one occurring in 2011-2012. However, there are big differences in today’s market dynamics relative to 5 years ago, namely propane exports to the tune of 850 Mb/d. In today’s blog, we’ll walk through the market dynamics that have resulted in extremely steep propane stock draws since late November 2015.
Just a few years ago, the possibility of overseas ethane exports was almost incomprehensible. Lack of infrastructure, high handling costs, no suitable ships and minimal market demand made ethane exports seem extremely unlikely. But then the shale gas boom transformed the ethane market. Now U.S. ethane production greatly exceeds demand and each day hundreds of thousands of barrels of ethane are being rejected into the natural gas stream. Consequently a few pioneers are hammering through the challenges associated with overseas ethane exports, including the construction of specialized tankage, loading facilities, ships and unloading facilities. And international chemical companies are spending hundreds of millions of dollars to modify olefin crackers to use the cheap feedstock. Now the first of those pioneers has made it to the new ethane frontier. In today's blog we examine the impact of imminent ethane exports from the Energy Transfer/Sunoco Terminal at Marcus Hook, PA.
Prices for CME/NYMEX West Texas Intermediate (WTI) have been on a rollercoaster this week – falling under $30/Bbl one minute then jumping back over $32/Bbl the next. Yesterday (February 4, 2016) WTI closed down 56 Cents at $31.72/Bbl. CME Henry Hub natural gas futures fell back under $2/MMBtu to close at $1.972 yesterday. That left the crude-to-gas ratio (WTI divided by Henry Hub) at just over 16 X – a little higher than the 15 X range we’ve been seeing this year. That is nearly half as much again as the 27X average between 2009 and 2014. The futures market implies that low ratios could continue for years – with December 2024 values implying a ratio of 13.3 X. The potential consequences of these low ratios are dramatic for the natural gas liquids (NGL) business as well as the competitiveness of U.S. natural gas in international markets. Today we describe the implications.