Three weeks ago, Hurricane Harvey threw a wrench in — well in a lot of things — but also into the natural gas market, curbing gas demand for power generation, curtailing pipeline exports to Mexico and stymying LNG exports. The market is still digesting the full impact of these disruptions and their potential effects on the gas market balance and storage. Adding to recent market shifts is the start-up of Energy Transfer Partners’ (ETP) Northeast-to-Midwest Rover Pipeline Phase 1A on September 1, which already is flowing 0.7 Bcf/d and lifting gas production out of Ohio. The market is hurtling towards winter, with just five weeks or so left until heating demand typically starts showing up and storage facilities officially begin to flip into withdrawal mode. What can recent supply and demand volumes tell us about what to expect from the gas market this winter? Today, we wrap up our most recent gas market update series with a forward look at potential scenarios for supply, demand and storage in the coming withdrawal season.
Daily energy Posts
The widely held expectation that Permian NGL production will rise sharply through the early 2020s has set off fierce competition among midstream companies to develop new pipeline capacity out of the play — mostly to the NGL storage and fractionation hub in Mont Belvieu, TX, but also to Corpus Christi. Only some of the incremental pipeline takeaway capacity being planned is likely to be needed, though, raising the stakes among midstreamers to line up the long-term commitments they need to finance and build their projects. Today we continue our series on NGL-related infrastructure in the U.S.’s hottest shale play with a look at efforts to add new takeaway capacity as NGL production in the Permian ramps up.
The surge in crude oil, natural gas and natural gas liquids (NGL) production in the Permian is driving a massive buildout of midstream infrastructure designed to move the hydrocarbons to end-use markets. On the gas processing front, there are literally dozens of projects announced or in the planning phase that are scheduled to start up over the next two years. Some are small projects aimed at a few producers, while others are set to significantly expand processing capacity and affect large areas of the basin’s gas gathering and transmission network. Today, we discuss Vaquero Midstream’s ambitious Delaware Basin gathering and processing projects.
Despite a 12% decline in crude oil prices from their December 2016 highs, the 43 top U.S. exploration and production companies (E&Ps) we’ve been tracking are largely maintaining their aggressive 2017 drilling and completion capital spending plans, announcing a mere $1.0 billion — or 1.5% — decline in total investment since the plans were unveiled. The industry’s apparent confidence in the long-term profitability of its aggressive development of the major U.S. resource plays is in sharp contrast with eroding investor sentiment that has driven Standard & Poor’s (S&P) E&P Index 29% lower than its late-2016 peak. The companies that announced modest investment reductions — about one-third of our universe of 43 E&Ps — cited cost savings from increased drilling efficiency and divestments as well as the lower short-term price outlook as reasons for the cuts. Today we review the changes in the overall outlook for 2017 upstream capital spending and oil and natural gas production, and take a quick peek into our three peer groups: those that focus on oil, those that focus on gas, and diversified E&Ps.
On August 4, the U.S. Senate confirmed two new commissioners for the Federal Energy Regulatory Commission (FERC), restoring the three-member quorum legally required for FERC to vote. The Senate action ended a six-month dry spell during which FERC could not issue any orders, and thus could not approve any of the many pipeline projects pending there. What does it mean that FERC can act again to approve new projects? And does that mean the industry can move forward at the pace it needs? Today we explore these questions and assess what it will take to get some key gas infrastructure projects back on track.
Despite starting the 2017 injection season on April 1 with much less gas in storage than last year, U.S. natural gas prices in recent months have struggled to return to $3.00 levels. The market has been dealing with a mixed bag of factors, with demand down significantly, mostly due to milder-than-normal weather and the rise of competing generation sources. On the supply side, even though production has been flat and imports from Canada down, those developments combined with higher exports of LNG have not been enough to prevent larger injections into storage. Now, prospects for a price rally are waning as summer gives way to the more temperate shoulder season. Where does that leave the gas market heading into winter? Today, we begin a series looking at how gas market fundamentals have shaped up this summer as well as prospects for the winter.
Production of natural gas liquids in the Permian is growing so quickly that within a year or two some parts of the super-hot play may experience NGL takeaway constraints. That is good news for the owners of the eight existing NGL pipelines out of the Permian, which are likely to see flows on their pipes increase as NGL production rises — assuming, that is, that they have capacity to spare and that they are connected to natural gas processing plants within the faster-growing parts of the region. Today we continue our blog series on Permian NGL production, processing and pipelines with a look at ONEOK’s West Texas LPG Pipeline and the Chevron Phillips Chemical EZ Pipeline.
The stars may finally be aligning for two related crude oil infrastructure projects that, if undertaken, would provide an important new pathway to overseas markets for Bakken, western Canadian and other North American crude. The first would involve reversing the Capline Pipeline, which was built to transport crude north from the U.S. Gulf Coast to Midwest refiners; the second would make modest physical changes to the Louisiana Offshore Oil Port — better known as LOOP — to allow the crude import facility off the Bayou State coast to load crude onto ships, including Very Large Crude Carriers (VLCCs). Today we look at the new infrastructure and market forces that may finally spur Capline’s reversal and lead imports-focused LOOP to enable exports.
Nearly two-thirds of the effective NGL pipeline takeaway capacity out of the Permian is controlled by Energy Transfer Partners and DCP Midstream. But there are several other NGL pipelines used to flow Permian NGLs to faraway storage facilities and fractionators — assuming, that is, that their natural gas processing plants are connected to the pipe alternatives in question. Today we continue our blog series on the NGL side of the Permian with a look at Enterprise Products Partners’ Chaparral and Seminole pipelines and Enterprise’s and BP’s Rio Grande Pipeline, including the volumes of NGLs that have been flowing through them.
Natural gas deliveries for export via Cheniere Energy’s Sabine Pass LNG terminal in Louisiana reached a record in late July, topping 2.5 Bcf/d. In the first seven months of 2017, exports have added an average of 1.5 Bcf/d — or more than 300 Bcf total — of baseload gas demand year on year. Thus far, the terminal has been operating with three liquefaction trains. Now the fourth train, which would bring on another 650-MMcf/d of potential export demand, is nearing completion. The incremental gas deliveries are scheduled to come just as winter heating season is kicking off and likely will tighten the gas market. Today, we look at the latest developments at the terminal.
Associated natural gas production from North Dakota’s oil-focused Bakken Shale is rising as rigs are being added in the region. Bakken gas output reached a record 1.18 Bcf/d this past May. The incremental gas production in the area is intensifying competition with imports from the already-beleaguered Western Canadian Sedimentary Basin (WCSB), which share the same pipeline capacity and target the same Midwest demand markets. The trend also is prompting calls for more pipeline capacity out of the Bakken. How much more capacity is needed and by when? Today, we look at existing natural gas takeaway capacity and flows out of the Bakken.
Growth in LNG supply and demand, the ongoing restructuring of the LNG sector and other factors are giving new significance to the nearly 500 specialized, oceangoing vessels that transport the supercooled, liquefied natural gas around the world. It used to be that the vast majority of LNG was delivered in milk run-like fashion under long-term contracts between suppliers and buyers, but that’s no longer the case. Now, the LNG market is much less structured and more fluid, with spot-market sales becoming more common and with the captains of some LNG-laden vessels not sure where they will end up as they head out of port. Today we describe the ins and outs of the shipping sector that moves hundreds of millions of metric tons of LNG annually.
The year-ago completion of Energy Transfer Partners’ Lone Star Express NGL pipeline from West Texas to the Mont Belvieu storage and fractionation hub near Houston was a big deal. The new, 533-mile pipe increased effective NGL takeaway capacity out of the Permian by more than 25% and gave Energy Transfer a larger conduit for moving NGL produced at its Permian natural gas processing plants directly to the company’s still-growing complex of fractionators in Mont Belvieu. Energy Transfer also owns another big NGL pipeline out of the Permian: the Lone Star West Texas Gateway. Today we continue our blog series on the NGL side of the Permian with a look at what is currently the biggest fish in the play’s NGL pond.
In the Energy Information Administration’s (EIA) latest ethane production stats — for the month of May — gas plant production of ethane exceeded 1.4 MMb/d for the first time. In the same month, ethane exports also hit a record at 191 Mb/d, and ethane demand for petrochemical production — you guessed it — hit still another all-time high, topping 1.2 MMb/d. All this is just the beginning. These numbers and the throughput of any midstream infrastructure transporting or fractionating ethane will continue to increase over the next two years as new, ethane-only crackers come online, ethane rejection dwindles and overseas exports of ethane ramp up. By 2020, U.S. ethane demand is expected to reach 2 MMb/d — up by two-thirds from where it stands now. Today we continue our series on rising ethane demand, how the new demand will be met and what it all means for ethane prices.
Production cuts by Saudi Arabia and other OPEC producers have had a profound effect on Asian refiners’ crude oil procurement by opening the door to more U.S., Canadian and North Sea crude deliveries to the Far East and South Asia. Of the four major Asian refining countries, China has seen the largest drop in imports of East of Suez crude, which includes oil produced in the Middle East, the Asia-Pacific region, Australasia and far-east Russia, but India, Japan and South Korea have experienced declines as well. What’s going on? And what does it mean for Atlantic Basin crude producers? Today, we discuss recent changes in global crude price differentials and Asian crude import slates, which include more imports from the U.S.
The utilization of NGL takeaway pipelines out of the fast-growing Permian is determined to a significant degree by the natural gas processing plants that the pipes are connected to. Midstream companies prescient — or lucky — enough to own NGL pipelines that extend out of the hottest, most productive sub-regions within the Permian’s Midland and Delaware basins are benefiting not only from higher NGL volumes now, but the likelihood of even fuller pipes as Permian production continues to ramp up. Today we continue our blog series on the NGL side of the Permian phenomenon with a look at existing gas processing plants in the play and their connections to NGL pipelines that move y-grade to storage and fractionators.