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.
Daily Energy Blog
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.
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.
The U.S. has a surplus of light hydrocarbon liquids – much of it in the form of field condensate produced at the wellhead and plant condensate extracted from natural gas at processing plants. Declining domestic demand leaves both field and plant condensate increasingly reliant on export markets. Trouble is those export markets are far from secure and the oil price crash isn’t making things any easier. Today we preview RBN’s latest Drill Down report – a deep dive into the supply and demand balance for field and plant condensate.
Hardisty is the main export hub for Western Canadian crude travelling to market in Eastern Canada or the U.S. That role will expand when (and if) the TransCanada Keystone XL and Energy East pipeline projects are completed. With 3.5 MMb/d of mostly heavy crude passing through, you might expect Hardisty terminals to require significant volumes of diluent. But in fact only one outbound diluent pipeline serves Hardisty region gathering systems. Today we explain why Hardisty requires less diluent.
Although as everyone ought to know by now, overall crude prices have dropped more than 35% in the past six months, prospects for the prolific Permian Basin continue to look rosy. Wide price discounts experienced by Permian producers at Midland, TX versus West Texas Intermediate (WTI) crude delivered to Cushing, OK over the past 13 months have narrowed recently in anticipation of the Plains All American Sunrise pipeline coming online. Permian production has been surging all year and midstream companies continue to invest in and expand takeaway capacity. Today we review ongoing infrastructure plans to handle growing output.
Prices for U.S. domestic benchmark West Texas Intermediate (WTI) crude on the CME NYMEX futures exchange crashed $7.54/Bbl to $66.15/Bbl Friday (November 28, 2014) - down 11 percent since the Wednesday before Thanksgiving and 38 percent since their recent high in late June. International benchmark Brent crude prices on the ICE futures exchange fell 10 percent to $70.02 /Bbl over the holiday and are down 39 percent since June. The underlying cause is oversupply but the short term trigger for last week’s nosedive was OPEC’s failure to respond to falling prices at their Thanksgiving meeting in Vienna by reining in production. Today we discuss the fate of crude prices after the OPEC meeting.
Between them the TransCanada Grand Rapids, Enbridge Norlite and Devon/MEG Access pipelines currently being planned and built out will be able to deliver an extra 1 MMb/d of diluent to oil sands producers by 2017. That’s more than producers currently expect to need until 2030. The diluent will be shipped north from Edmonton terminals to production plants and blended with bitumen before making the return trip as dilbit or railbit destined for long-haul transport by pipe or rail to U.S. and Canadian markets. Today we describe the pipeline build out plans.
We estimate October 2014 Eagle Ford condensate production at 690 Mb/d and have identified 450 Mb/d of stabilization capacity that meets Bureau of Industry and Security (BIS) standards to classify the processed output as OK for export. That should make it possible for an estimated 230 Mb/d of processed condensate to be exported from the Gulf Coast in 2015. All that is needed to open the floodgates are more transport routes to export docks. Today we describe current and future routes planned by Enterprise to get segregated processed condensate to market.
With Western Canadian oil sands bitumen output increasing rapidly, producers need more diluent to blend with their production so that it can flow to market in pipelines. That means delivering diluent to remote locations as far as 250 miles northwest of Edmonton. Smaller oil sands projects typically get their diluent delivered by rail or truck but pipeline infrastructure is being built out for larger projects as their production comes online. Inter Pipeline (IPL) diluent delivery volumes on their Polaris pipeline at the end of 2013 were just 20 Mb/d. By 2017 that volume could be to 1.2 MMb/d. Today we detail IPL and Plains build out plans.
Kinder Morgan expect to commission the first 50 Mb/d of condensate splitter capacity at their Galena Park terminal in Houston during the next month. The capacity is leased to BP North America and will be supplied with condensate via Kinder’s Eagle Ford pipeline gathering network. Another 235 Mb/d of condensate splitter capacity could be online by 2017 – most of it in Corpus Christi. Meanwhile the jury is still out on whether it makes more sense for a producer to use a condensate splitter or to just process their condensate through a stabilizer with distillation. Either way the resulting products seem likely to end up in the export market. Today we detail the splitter plans.
The price discount for Canadian heavy crude benchmark Western Canadian Select (WCS) sold in Hardisty, Alberta versus Gulf Coast equivalent heavy grade Maya has narrowed from $35/Bbl last November to less than $12/Bbl today. The discounts to Maya this year have been less than the cost of rail transportation between Western Canada and the Gulf Coast – reflecting improving crude takeaway capacity. Next month the 600 Mb/d Flanagan South pipeline from Chicago to Cushing and the 450 Mb/d Seaway Twin from Cushing to Houston will open more new capacity for Canadian crude to compete against Maya at the Gulf Coast. The result is likely to be even lower differentials. Today we discuss the likely impact.
Current analysis of how Western Canadian producers can find supplies to meet a growing need for diluent material to blend with their heavy crude and bitumen suggest that up to 485 Mb/d of imports will be needed by 2019. But there is a growing belief that increased production of condensate from the Montney and Duvernay shale plays in Western Alberta and British Columbia will supply far more diluent than previously expected – reducing that import requirement significantly. Today we look at plans by Pembina to ship increased diluent supplies to Edmonton from domestic Canadian sources.
