Keyera Corp. and SemCAMS Midstream, two major midstream players in Western Canada, in mid-May announced they are proceeding with the construction of their joint-venture project — a new NGL and condensate pipeline system out of the liquids-rich Montney and Duvernay plays of Alberta. The planned Key Access Pipeline System would provide the first direct competition for the transportation of NGLs and condensate out of these producing regions, currently dominated by Pembina Pipeline Co. Any and all transportation options for the movement of condensate and other NGLs out of the Montney and surrounding plays will likely be welcomed by Western Canadian natural gas producers, who are looking to capitalize on oil-sands producers’ growing demand for homegrown sources of condensate for use as diluent in bitumen transportation. Today, we provide key details about the project and how it fits into the region’s existing condensate/NGLs market.
Enbridge is taking a serious look at converting its Southern Lights pipeline, which currently transports diluent northwest from Illinois to Alberta, to a 150-Mb/d crude oil pipe that would flow southeast. The potential reversal of Southern Lights is made possible by the facts that Western Canadian production of natural gasoline and condensate — two leading diluents — has been rising fast, and that demand for piped-in diluent from the Lower 48 is on the wane. Alberta producers could sure use more crude pipeline capacity out of the region — and getting crude down to the U.S. Midwest would give them good access to a variety of markets. With Western Canadian diluent production increasing fast, maybe Kinder Morgan’s Cochin Pipeline, another diluent carrier, could also be flipped to crude service later on. Today, we consider how Southern Lights’ conversion/reversal might help.
The Utica and “wet” Marcellus plays in eastern Ohio, northern West Virginia and western Pennsylvania are producing increasing volumes of natural gas liquids and field condensates that need to be moved to market. In response, MPLX, a master limited partnership formed by Marathon Petroleum Corporation (MPC) six years ago, has been implementing a multi-part strategy to develop new or expanded pipeline takeaway capacity through the Midwest to deal specifically with the heaviest NGLs — natural gasoline and other pentanes — and with field condensates. That work is now largely done, the results have been positive, and MPLX is now undertaking the next phase of its strategy that will further expand the system’s capacity and add a new element: the ability to transport batches of two other, lighter NGLs — normal butane and isobutane — on a few of the same pipelines. Today, we discuss the next steps the company is taking to facilitate the transport of liquid hydrocarbons out of the Utica and Marcellus.
Several oil-sands expansion projects committed to when crude oil prices were double what they are today are finally coming online, and midstream companies active in Alberta are building new crude/diluent pipelines and storage capacity to keep pace. New storage caverns for natural gas liquids are also in the works, giving a much-needed boost to Canada’s Energy Province. Today we conclude our series on midstream infrastructure under development in or near Western Canada’s oil sands region that move and store hydrocarbon liquids.
Oil-sands expansion projects coming online and the resulting need for more diluent are among the drivers behind a number of midstream infrastructure projects in the province of Alberta, including natural gas processing plants and fractionators; oil and diluent pipelines; and oil/NGL storage facilities. The total volume of work is surprising, considering the fact that oil-sands production economics are iffy right now, if not downright upside down. Today, we continue our look at midstream projects under development within Canada’s Energy Province, this time focusing on gas processing and fractionation facilities.
More midstream projects than you might expect are “goin’ on” in the Western Canadian province of Alberta, considering the challenges that bitumen/crude oil and natural gas producers there continue to face. There are several drivers behind the relatively long list of oil and diluent pipelines; gas processing plants and fractionators; and oil/NGL storage facilities being built in Canada’s Energy Province, but much of the work is being done to meet the expected needs of oil-sands expansion projects approved during better times and set to come online soon. Today we begin a blog series on Alberta midstream projects with an overview of where the province’s energy sector stands today.
Production in Alberta’s oil sands region is gradually rebounding after devastating wildfires that forced output scale-backs and temporary shutdowns of some production facilities, terminals and pipelines. It may be a while before life—and production—in the oil sands are back to normal, but Canada’s National Energy Board, producers and others expect the region’s output to continue to rise (if only gradually) the next few years, reflecting long-term oil sands expansion projects committed to when oil prices were more than double what they are today. There are very different views, though, about whether the oil sands will eventually need more takeaway capacity in the form of new or expanded pipelines. Today, we continue our look at the oil sands post-wildfires with a review of existing and proposed pipeline capacity.
Wildfires are notoriously unpredictable and, sure enough, as soon as the worst seemed to be over in the Fort McMurray, AB area, new flare-ups in mid-May threatened oil sands production areas north of the city. Thanks to heroic efforts by Alberta fire crews, no production area has experienced any significant damage (so far at least—fingers crossed), but a few work camps have been destroyed or damaged, and will need to be rebuilt. Good news is trickling in though, such as Imperial Oil’s May 19 announcement that it has restarted limited operations at its Kearl oil sands site. If, as everyone hopes, the wildfires are brought under control within the next few days, it seems likely that oil sands production will ramp up gradually over the next few weeks, and that by mid-summer Alberta’s output might be close to the 3.1 MMb/d that the province was producing before the fires were sparked.
It will take at least a few weeks, but it seems likely that production in the Alberta oil sands will return to near normal levels, setting the stage for continued incremental growth over the next few years as expansion projects committed to when oil prices were much higher come online. Although fires are still burning, the devastation in and around Fort McMurray, AB--the unofficial capital of the oil sands region—that forced tens of thousands of people from their homes, prompting oil sands staffing shortages, production scale-backs and a handful of temporary production shutdowns has moved beyond most oil sands operations. But the wildfires’ chain of effects didn’t end there; at one point, crude oil output declines were estimated at upwards of 1 MMb/d (about one-third of Alberta’s normal production of 3.1 MMb/d) caused world oil prices to inch up, some refineries in the U.S. Midwest that depend on Alberta-sourced oil have been forced to scramble for replacement crude, and natural gas prices fell to near zero for a brief period. Today, we begin a two-part look at post-wildfire prospects for the region, and—looking ahead--at the possible need for more pipeline takeaway capacity.
Most Canadian oil sands crude production comes from very expensive mining or underground steam heating operations designed to produce consistently for decades that are costly to shutter in a downturn. Right now the crude netbacks (market price less transport costs) for these projects are more or less under water depending on transport routes. Yet production continues and new projects are still coming online. Today we estimate the netbacks (market price less transport cost) that Canadian producers are realizing.
If you think that yesterday’s 13 year-low CME/NYMEX crude settlement price ($26.21/Bbl – February 11, 2016) is bad news for struggling U.S. producers then try putting yourself in Canadian producer’s shoes! The headwinds facing Western Canada’s heavy oil sands these days would try the patience of a saint. Prices for benchmark Western Canadian Select (WCS) blend in Alberta traded as low as $12.50/Bbl in January 2016 – clawing back to $14.06/Bbl on February 10, 2016. But by the time gathering, transport and diluent purchase costs are subtracted, the netback (market price less transport cost) at the lease is negative for many producers – especially when shipping by rail. To be clear, that’s below zero at the wellhead! Yet there are few signs that production is falling off – at least in the short term. Today we lament the ongoing plight of Canadian producers.
Over 400 Mb/d of Gulf Coast condensate splitter projects could be online by the end of 2016. These splitters will compete for condensate feedstock with local refineries in the Eagle Ford able to process 475 Mb/d of light crude and condensate. Another 700 Mb/d of stabilization capacity in the Eagle Ford could be used to process condensate for export. But with low crude prices stalling production growth, splitter economics could suffer if demand exceeds supply and condensate prices increase as a result. Today we conclude our update on Gulf Coast splitters.
Production of lease condensate at the wellhead and plant condensate from processing natural gas liquids (NGLs) has increased rapidly in the Ohio Utica over the past two years. Timely investment by local refiner Marathon and infrastructure developments to ship condensate to Gulf Coast refiners have proved the primary market for Utica condensate so far. The proximity of the region to diluent pipelines to Canada has also prompted infrastructure projects. Today we describe projects to deliver condensate to Alberta.
Data from the new Energy Information Administration (EIA) monthly report on crude-by-rail (CBR) shows that shipments from Canada increased from less than 10 Mb/d two years ago in January 2012 to over 130 Mb/d in January 2015. The increase in CBR movements mirrors increasing Canadian crude exports to the U.S. – the majority of which are still pipeline movements. Today we look at the destination markets for Canadian CBR in the light of congested pipeline capacity out of Western Canada.
Since we began this series on diluent supplies to Canada (used to blend with heavy oil to facilitate pipeline shipment), questions about diluent supply have been overshadowed by the bigger concern with falling crude prices. Right now, oil sands producers are probably more concerned with understanding the economics of their expansion projects and whether to go ahead with new oil sands development programs than with securing diluent supplies. Nevertheless, falling diluent costs in Edmonton have provided some relief to existing producers. Today we look at how improving diluent supplies and better prices for Canadian crudes have reduced diluent costs.
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.