The NGL storage and fractionation hub at Mont Belvieu, TX, grabs all the attention, but more than 1 MMb/d of fractionation capacity — nearly one-third of Texas’s total — is located elsewhere in the Lone Star State. And with NGL production and demand for fractionation services soaring in the Permian, SCOOP/STACK and other nearby plays, the market will need all the fractionation capacity it can find. We’ve heard that there’s little, if any, gap between what the existing fractionators in Mont Belvieu can handle and what they’re being asked to process. That’s music to the ears of fractionation-plant owners elsewhere in Texas — assuming they aren’t already at capacity themselves, they might be able to pick up some overflow business from Mont Belvieu. Today, we continue our review of fractionators and other key NGL-related infrastructure along the Gulf Coast.
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Mexican demand for U.S.-sourced refined products continues to increase, but Mexico lacks the infrastructure required to efficiently import, store and distribute large volumes of gasoline and diesel. That has spurred the rapid build-out of new port and rail terminals, new pipelines and new storage capacity on both sides of the U.S.-Mexico border. At the same time, Mexico’s state-owned energy companies are gradually opening access to their existing refined-products pipeline and storage networks — which helps a little, but not enough. Today, we discuss the latest round of midstream projects tied to U.S. exports of motor and jet fuels to its southern neighbor.
Since early this year, the Midland crude differential has continued to widen, trading one day last week at a discount of $15.75/bbl to West Texas Intermediate (WTI) at Cushing, the widest spread since August 2014 before settling back to $11.25/bbl on Monday. The wide price differential is a result of fast-growing production in the Permian and bottlenecked takeaway pipelines. But the trajectory of this increasing price spread has been anything but smooth. Lately, we have seen a blip in the price differentials right around the 19th or 20th of the month. In each of the last three months, for a short-lived 24 to 48 hours, the Midland-Cushing price differential has narrowed by $2/bbl or more as Permian shippers have gone on feeding frenzies. Today, we look at these brief upticks in pricing and the pipeline and trader mechanics behind them.
Mont Belvieu may be the epicenter of NGL storage, fractionation and distribution along the Gulf Coast, but the rest of Texas offers almost half as much fractionation capacity — about 1 MMb/d of it — and a good bit of storage and pipeline connectivity too. These are particularly important facts in the summer of 2018, when demand for fractionation services in Mont Belvieu is at or near an all-time high and increasing volumes of NGLs are headed toward the hub. So what else has the Lone Star State got on the fractionation and NGL storage front? And are these assets experiencing the same strong demand as their counterparts in Mont Belvieu? Today, we continue our review of fractionators and key NGL-related infrastructure.
Lower 48 dry gas production has climbed 3 Bcf/d since April to nearly 82 Bcf/d this month to date, which is an average ~9 Bcf/d — or 12% — higher year-on-year. Despite that meteoric rise in supply, the U.S. gas storage inventory, which started the injection season well below year-ago and five-year average levels, continues to carry a substantial deficit. That’s because record demand volumes thus far have managed to keep storage injections in check. Today, we provide an update of the demand factors affecting the 2018 gas injection season.
The slower-than-hoped-for build-out of natural gas pipelines and gas-fired power plants in Mexico has been a source of frustration for producers in the Permian Basin, who face pipeline takeaway constraints to their west, north and east and who desperately want to send more gas south. But it’s not just the Permian that benefits as the doors to the Mexican market creak open. The Eagle Ford — the Permian’s less glamorous step-sister — was the primary source of the first wave of gas exports to points south of the border. Now, with the recent opening of the Nueva Era Pipeline from the Rio Grande to power plants and other customers in Monterrey and Escobedo, another Mexican demand outlet will be made available to South Texas producers. Today, we discuss Howard Energy Partners and Grupo CLISA’s newly completed pipeline and the boost it gives to Eagle Ford production.
The planned implementation of the International Maritime Organization’s rule slashing allowable sulfur-dioxide emissions from ocean-going ships on January 1, 2020, would create significant demand for 0.5%-sulfur marine fuel — a refined product that few refiners produce today. That could present a big challenge to the global refining sector, which will be called upon to produce marine fuel that complies with “IMO 2020,” as the rule is commonly known. But refiners have stepped up before, and if the IMO 2020 mandate proves to be unachievable and would put global commerce at risk, there could be ways to deal with it — including exemptions or implementation delays. In any case, the move toward much cleaner bunker fuel will be a boon to complex refineries along the U.S. Gulf Coast and elsewhere that can break down bottom-of-the-barrel “residual” fuel oil into feedstocks for gasoline, diesel and other high-value products. Today, we continue our analysis of IMO 2020 and its effects.
After treading near the 79-Bcf/d level this past spring, Lower 48 natural gas production surged about 1.5 Bcf/d higher in the last three weeks of June to record highs approaching 82 Bcf/d by month’s end. The supply gains suspended the market’s bullish view of the persistently large storage deficit compared with last year and the five-year average and reeled in the prompt CME/NYMEX Henry Hub futures contract from the $3/MMBtu mark — at least for now. Where did the gains occur and how much of that influx truly is new production versus volumes returning from seasonal maintenance? Today, we examine the drivers behind the recent production jump.
For the first time ever, U.S. crude oil exports have hit the 3 MMb/d mark — a once-unthinkable pace equivalent to sending out 10 fully loaded Very Large Crude Carriers a week. VLCCs, with their 2-MMbbl capacity and rock-bottom per-bbl delivery costs, are the most cost-effective way to transport crude to distant markets like China and India. But there’s still only one terminal on the Gulf Coast that can fill a VLCC to the brim — the Louisiana Offshore Oil Port — and pipeline connections from key Texas and Oklahoma plays to LOOP are limited. Elsewhere along the coast, VLCCs need to be loaded in offshore deep water by reverse lightering from smaller vessels — a slower and more costly loading process. Change is a-comin’, though. Companies are testing the docking and partial loading of VLCCs at terminals along the Texas coast, and plans for a number of greenfield facilities capable of partially — or even fully — loading the gargantuan vessels at the dock are being considered. Today, we review the latest efforts to streamline the loading of VLCCs and what they mean for crude-export economics.
There was a time when natural gas prices in the Permian Basin spent most of the summer bouncing within a few cents of the benchmark Henry Hub, as ample pipeline takeaway capacity and seasonally strong demand combined to keep a lid on price blowouts. Times have certainly changed, with ballooning local production overwhelming existing takeaway capacity and widening the price spread between Permian gas markets and Henry Hub. However, the erosion in Permian gas basis has been anything but orderly. The current market is defined by significant swings in gas basis, depending on factors such as pipeline maintenance and weather. So, while the trend in Permian gas basis is decidedly lower, the path to get there is looking like a gut-wrenching roller coaster ride. Today, we look at recent swings in Permian natural gas basis pricing.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.
For 10 years prior to 2018, the differential between propane prices at the Conway, KS, hub averaged less than a nickel per gallon below Mont Belvieu. In fact, between 2013 and 2017, the price spread was only 3.5 c/gal — excluding a winter 2014 Polar Vortex aberration — which basically reflects the cost of moving barrels 700 miles north-to-south. Not this year, though. After starting 2018 at 3 c/gal, the propane price spread took off, and has averaged 18 c/gal since April, some days moving above 26 c/gal, far above the per-bbl cost of transporting propane 700 miles south to Mont Belvieu. Is it pipeline capacity constraints? In part. But there is a much more significant factor driving this differential wider, not only in the propane market, but across all five of the NGL purity products. What is this mysterious factor? To find out, read on. But here’s your first clue: the problem is not in Kansas anymore.
For a while, the 840 Mb/d of NGL fractionation capacity that was added in Mont Belvieu, TX, between 2013 and 2016 — combined with the 1.2 MMb/d of capacity already in place before that four-year fractionator construction boom — was more than enough. But the run-up in NGL production in the Permian, SCOOP/STACK and other liquids-rich plays in 2017 and the first half of 2018 is quickly increasing the demand for fractionation services and challenging Mont Belvieu’s ability to keep up. Now, another 465 Mb/d of fractionator capacity is under development. Will they be finished soon enough? Will still more be needed? Today, we continue our review of fractionators, NGL and purity-product storage and other key infrastructure, this time with a look at ONEOK and Gulf Coast Fractionators’ assets.
Crude oil and natural gas production in the Bakken are at record highs, and with the surge in production has come infrastructure constraints and higher rates of flared gas, renewing concerns about possible production shut-ins. As gas production volumes exceeded gas processing capacity, the flaring rate in April 2018 rose to 15% of total monthly volumes –– precisely the current limit set by North Dakota’s gas capture plan and three percentage points above the 12% cap due to kick in this November. Rig counts, producers’ drilling plans and $70/bbl crude oil prices all point to further production growth, which means that without additional processing capacity — or a change in the gas-capture policy — it will be increasingly difficult for producers and processors to comply. Today, we look at the latest developments in Bakken gas production, gas-related infrastructure and the gas capture policy.
Permian natural gas fundamentals were rocked with some major infrastructure news on Monday, when Kinder Morgan announced its plans to build the 2-Bcf/d Permian Highway Pipeline (PHP) from Waha to the Texas Gulf Coast. The announcement revealed that EagleClaw Midstream, a Blackstone Energy Partners portfolio company, has signed a letter of intent to become a 50% owner in the project and commit natural gas volumes to the pipeline. Adding firepower to the project, Apache Corp. is committing significant volumes to the pipeline too, with an option to take an ownership stake. While Kinder Morgan and EagleClaw Midstream stopped short of a final investment decision (FID), the destination flexibility that PHP’s tie-ins with other key pipes offer makes the project a major contender in the race to become the second new long-haul natural gas pipeline out of the Permian. Today, we discuss the latest infrastructure development in the Permian natural gas market.
The weeks-long shutdown at Syncrude Canada’s oil sands production facility in northeastern Alberta will alleviate pipeline takeaway constraints that have significantly widened the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) crude oil. But when Syncrude returns later this summer, there’s every reason to believe that the constraints will too, as will the need for significantly more crude-by-rail shipments. Railed volumes out of Western Canada have been increasing in recent months, but not by enough to avert WCS-WTI differential blowouts to $25 and even $30/bbl. The catch is that most of the rail-terminal capacity built a few years ago is mothballed, and that railroads are reluctant to dedicate more locomotives and personnel unless shippers make one-, two- or even three-year commitments to take-or-pay for that logistical support. Today, we consider the ongoing challenges Western Canadian producers face in moving their crude to market.