What a deal! Take as much butane as you want — all for the low, low price of less than 10 cents/gallon (c/gal). That was the situation in Edmonton, AB, last November and the price stayed dirt cheap until a few days ago. Given a decline in demand for butane in crude blending, along with growing NGL production, the NGL processing and storage hub in Western Canada was awash in butane as winter approached. It remains flush with product today — and the price for Alberta butane is still low. How did this happen, and how will it play out over the next few months? Today, we examine the factors that led the Edmonton NGL market to see a price fall to near zero c/gal for the second time this decade.
Daily Energy Blog
Wednesday, 4/10/2019
Category:
Natural Gas Liquids
Tuesday, 4/09/2019
Category:
Natural Gas
The winter 2018-19 natural gas market was one of the most chaotic in recent memory, with the NYMEX Henry Hub futures contract last fall rocketing up to nearly $5/MMBtu in a matter of weeks, only to collapse in late 2018/early 2019 down to near $2.60 by early February. The physical gas market also swung to extremes in recent months, setting both the highest ($200/MMBtu at the Sumas, WA, hub) and lowest (negative $9.00/MMBtu at the Waha hub) trades ever recorded in the U.S. These anomalies occurred amid steep supply growth from the Marcellus/Utica and Permian producing regions and rapidly advancing demand, particularly from burgeoning LNG exports along the Gulf Coast, while infrastructure scrambled to keep pace to bridge the two. And there’s more of that volatility ahead. Close to 5 Bcf/d more LNG export capacity is being added this year alone, and Lower-48 gas production is poised to continue growing. Today, we lay out our view of the recent volatility and the biggest factors shaping the gas market over the next five years, based on Rusty Braziel’s Backstage Pass Fundamental Webcast last week.
Monday, 4/08/2019
Category:
Natural Gas Liquids
Rising natural gas liquids production in the Niobrara is increasingly straining existing pipeline capacity out of the region and has spurred midstreamers to propose various combinations of new pipelines, expansions to existing pipelines and pipeline conversions in order to ease constraints. One of the latest entrants is a joint venture of Williams and Targa Resources that would expand Rockies producers’ ability to move mixed NGLs to the Mont Belvieu, TX, hub for fractionation and marketing/export. Williams plans to build a 188-mile pipeline — Bluestem — that would extend from its Rockies-to-Conway, KS, Overland Pass Pipeline to Kingfisher County, OK. For its part, Targa will build a 110-mile extension of its new Grand Prix NGL pipeline from southern Oklahoma north into Kingfisher to connect with Bluestem. As part of the deal, Williams has also contracted substantial volumes on Grand Prix as well as at Targa’s fractionation facility at Mont Belvieu. Today, we discuss Williams and Targa’s plan.
Sunday, 4/07/2019
Category:
Crude Oil
Crude differentials in the Permian are getting squeezed. The spread between Midland and WTI at Cushing widened out to near $18/bbl at one point in 2018, when pipeline capacity was scarce. But that same spread averaged a discount of only $0.25/bbl in March 2019. Differentials between Midland and the more desired sales destination at the Gulf Coast are also in a vise. What gives? Production in the Permian continues to climb, but the rapid pace of growth we saw in 2018 has slowed down a bit lately, with fewer rigs in service and fewer new wells being brought on each month. More importantly, we’ve seen several new pipeline expansions and pipeline conversions come online in bits and bursts — in some cases, ahead of schedule — and this new chunk of pipeline space has compressed Midland pricing. In today’s blog, we begin a series on Permian crude takeaway capacity and differentials, with a look at the handful of new projects that have come online in the past few months and what has happened to Permian prices as a result.
Thursday, 4/04/2019
Category:
Natural Gas
The shutdown of natural gas production from the Sable Offshore Energy Project on Canada’s East Coast as of January 1, 2019, increased the Canadian Maritimes’ reliance on gas exports from New England this winter as consumers worked to link up with fresh supply to replace SOEP. The tightening supply in the region has prompted expansion plans from TransCanada to move more Western Canadian and Marcellus/Utica gas to New England utilizing its Mainline and other eastern systems. Today, we conclude our series examining the potential impacts of SOEP’s demise by examining new plans to bring more gas to the region.
Wednesday, 4/03/2019
Category:
Natural Gas
Ten weeks after an explosion crippled a key natural gas takeaway route out of the Marcellus/Utica, the capacity finally has been fully restored. Texas Eastern Transmission two days ago said it’s lifting all restrictions on the affected section of pipe. The outage began on January 21 and partial service resumed eight days later, but TETCO’s Northeast production receipts during the event averaged about 700 MMcf/d lower than usual and the line’s flows to the Gulf Coast were cut by 30-40%. That, along with two severe polar-vortex periods in January that overlapped with the outage, caused a reshuffling of flows across other pipelines in the region. Today, we wrap up this series with a look at the implications of the outage on the Northeast gas market and what to expect now that it’s ended.
Tuesday, 4/02/2019
Category:
Crude Oil
A primary focus of E&Ps during the Shale Era has been driving down the cost of drilling and completing wells — doing so lowers producers’ break-even costs and increases their profitability. With the volumes of frac sand being used in the Permian and many other plays having grown dramatically in the past five years, a big push is on not only to minimize the cost of the sand itself, but to maximize the efficiency of sand delivery and sand management at the well site. All this has been spurring E&Ps to assume responsibility from oilfield service companies for the frac sand supply chain — anything from directly sourcing the sand to managing “last-mile” logistics. Today, we continue our series on the rapidly changing frac-sand world, this time concentrating on producers’ growing involvement in sand procurement and management.
Monday, 4/01/2019
Category:
Financial
Crude oil and natural gas prices went through a lot of ups and downs in the 2014-18 period, but the general trend was down. The average price of WTI crude topped $100/bbl in the first half of 2014; by year-end 2018 it stood at $45/bbl. Similarly, the NYMEX natural gas price topped $6.00/MMBtu in early 2014 but fell to a low of about $2.50/MMBtu last year and averaged little more than $3.00/MMBtu. The 44 major U.S. E&P companies we track sought to weather this storm of declining prices by drastically repositioning their portfolios and slashing costs to stay competitive in a new, lower price environment. Their efforts appear to have worked: 2018 profits surged in comparison with 2017 results and approached returns recorded in 2014, when commodity prices were much higher. So why are E&P stock prices languishing? Today, we look at the divergence between investor sentiment and the actual financial performance of U.S. E&P companies.
Sunday, 3/31/2019
Category:
Crude Oil
Some shipowners plan to comply with the IMO 2020 deadlines for limiting sulfur in ship emissions by installing scrubber devices to clean the exhaust generated by burning less expensive high-sulfur bunker fuel. For many, this may work out to be more economical, at least in the interim, than using more costly IMO 2020-compliant fuel with sulfur content of no more than 0.5% or converting the vessel to run on an altogether different fuel such as liquefied natural gas. However, narrowing “sulfur spreads” this year have put that compliance strategy at risk by tripling the time it would take for shipowners to recoup their scrubber investments. Today, we continue an analysis of the changing economics of scrubber installation in the run-up to IMO 2020.
Thursday, 3/28/2019
Category:
Natural Gas
Midstreamers have been struggling to keep processing and natural gas pipeline constraints at bay in Oklahoma’s SCOOP/STACK plays, and the situation hasn’t gotten any easier in the past 18 months or so. Associated gas production from the Cana-Woodford has surpassed expectations, climbing 1 Bcf/d in that time to new highs near ~4.5 Bcf/d. Efforts by pipeline operators to keep pace with production gains have largely been on a piecemeal basis, mostly to tie in processing plants or modify/expand existing systems. Cheniere Energy’s Midship Project is looking to change that. The greenfield project, which received its final notice to proceed with construction from the Federal Energy Regulatory Commission (FERC) late last month, will level-shift takeaway capacity out of Oklahoma up by 1.44 Bcf/d in one fell swoop by the end of 2019. Today’s blog provides an update on Midship and other expansions in the region.
Wednesday, 3/27/2019
Category:
Natural Gas
Permian natural gas prices are having a rough spring. After a volatile winter that saw two periods of negative-priced trades followed by a period of relatively strong prices, values at the Permian’s major trading hubs hit the skids earlier this week just as Spring Break set in for most in the Lone Star state. Once again, pipeline maintenance and burgeoning production appear to be the main culprits, but this upheaval feels different, in our view. Clearly, the price crash has reached a new level of drama, with day-ahead spot prices at West Texas’s Waha hub now settling below zero — some days by more than $0.50/MMBtu. Gas production has raced higher too, now within striking distance of 10 Bcf/d, on the coattails of continued oil pipeline capacity expansions, but new gas pipeline takeaway capacity is an estimated six months away. What becomes of Permian gas prices in the meantime, and how much worse could already-negative prices get? Today, we discuss the drivers behind the latest price deterioration and assess what’s ahead for the Permian natural gas markets.
Tuesday, 3/26/2019
Category:
Natural Gas
The second wave of North American LNG export projects is officially underway. LNG Canada took final investment decision (FID) last October and would be the first large-scale LNG export facility in Canada. Golden Pass followed in February, marking the beginning of the next round of LNG export build on the U.S. Gulf Coast. Sabine Pass Train 6 is expected to get the green light any day, and at least eight more projects are targeting FID this year. But how likely are these projects to go ahead? And what exactly does it take for a project to reach that financial milestone? Today, we begin a two-part blog series on the factors affecting U.S. and Canadian LNG export projects’ prospects for taking FID and our view on the projects making progress towards joining the second wave of LNG exports.
Monday, 3/25/2019
Category:
Crude Oil
Crude production is at all-time highs in the Bakken and the Niobrara, and the latest pipeline-capacity expansions out of both regions have been filling up fast. At the same time, producers in Western Canada are dealing with major takeaway constraints and are on the hunt for still more pipeline space. Midstream companies are trying to oblige, proposing solutions like a major Pony Express expansion or a new Bakken-to-Rockies-to-Gulf Coast fix — the Liberty and Red Oak pipelines — that could help address all of the above. The catch is that, with multiple producing areas funneling crude along the same general eastern-Rockies corridor and the outlook for continued production growth uncertain, how’s a shipper to know whether to sign a long-term deal for some of the incremental pipe capacity now being offered? Today, we consider the need for new takeaway capacity, the potential for an overbuild scenario, and what it all means for producers and shippers.
Sunday, 3/24/2019
Category:
Crude Oil
Over the past three years, the U.S. frac sand market has been transformed. Demand for the sand used in hydraulic fracturing is more than twice what it was in early 2016. Dozens of new “local” sand mines have come online, slashing the need for railed-in Northern White Sand in the Permian and a number of other fast-growing plays. Frac sand prices have fallen sharply from their 2017 highs. And exploration and production companies, which traditionally outsourced sand procurement and “last-mile” sand logistics to pressure pumpers and other specialists, are taking a more hands-on approach. It’s a whole new world. Today, we continue our series on the major upheavals rocking the frac sand world in 2019 with a look at the development of local sand sources in the Eagle Ford, SCOOP/STACK and the Haynesville.
Thursday, 3/21/2019
Category:
Crude Oil
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.
