Crude oil inventory levels aren’t the only thing in a constant state of flux at the crude storage hub in Cushing, OK. A year ago, we blogged extensively about Cushing’s major players, storage assets and incoming and outgoing pipelines, as well as plans for new pipes that highlight the hub’s continued significance, even in an increasingly Permian- and Gulf Coast-focused energy sector. A lot has changed since then, though. Some pipeline projects into and out of Cushing have advanced to final investment decisions (FIDs), while others have floundered or foundered. Also, brand-new pipeline projects have been announced, as was a big acquisition that will make Energy Transfer a major player in Cushing storage. Today, we begin a short series on recent developments at the Oklahoma oil hub and how they reflect changes in the ever-evolving U.S. energy markets.
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Recently Published Reports
| Product | Title | Published |
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| NATGAS Billboard | Growing Storage Surplus Likely To Limit Price Upside | 2 days 10 hours ago |
| NATGAS Billboard | EIA Called to Report a +99-Bcf Storage Injection Today | 3 days 10 hours ago |
| Crude Oil GUSHER | Crude Oil GUSHER - October 9, 2019 | 4 days 4 hours ago |
| NATGAS Billboard | Market Consolidates Amid Cooler Weather | 4 days 10 hours ago |
Daily energy Posts
New fractionation plants, steam crackers and export facilities are being built along the Gulf Coast, all spurred by rising U.S. production of natural gas liquids. This incremental NGL output and these new projects are putting serious pressure on existing NGL pipeline and storage infrastructure, and prodding the development of new salt-cavern storage capacity for mixed NGLs, NGL purity products, and ethylene and other olefins. Also, new, expanded and repurposed pipelines to enhance NGL-related flows throughout the region are in the works. Today, we continue our series on NGL storage facilities along the Gulf Coast with a look at Easton Energy Services’ plans for more underground storage capacity in Markham, TX, and new NGL and olefin pipelines.
The CME/NYMEX prompt Henry Hub natural gas price yesterday settled at about $2.28/MMBtu, down 40 cents from the summer peak of $2.68 in mid-September. That’s also a long way down from the $3-plus prices seen at this time last year. What’s more, daily prompt-month contract settlements this injection season, from April to present, have averaged the lowest in over 20 years. This, despite the Lower-48 gas storage inventory starting the 2019 storage injection season in April well below year-ago and five-year-average levels. How did we get here? Today, we begin a short series breaking down the supply-demand fundamentals that brought the gas market to its knees in recent months.
With another month of anemic storage injections in September, Alberta natural gas storage levels remain on track to start the next heating season at a 13-year low. Still, while Alberta gas storage has been lagging well behind in terms of average injection rates and storage levels for many months now, forward winter contract prices for the Western Canadian gas price benchmark of AECO have budged only a little. There is potential for an improvement in storage injection rates during October after a recent regulatory approval affecting the Alberta gas pipeline system, but there is little time remaining in the current injection season to make much of a difference in inventory levels going into winter. Today, we conclude this two-part series with a look at why the AECO forward market remains largely unconcerned with low Alberta gas storage levels.
Demand for ethane from U.S. steam crackers is rising as recently completed ethane-only crackers ramp up to full production and additional crackers are finished. To keep pace with demand growth, a portion of the ethane now being “rejected” into the natural gas stream and sold for its Btu value will instead need to be left in the mixed-NGLs stream and fractionated into purity-product ethane. This raises two questions. First, in which shale plays will this shift from ethane rejection to ethane production occur? And second, how much will ethane prices need to increase to encourage the shift and make the required incremental volumes of ethane available? Today, we continue a series on ethane-market developments with a look at where the next tranche of ethane supply will come from and how high ethane prices might need to rise.
The Permian Basin’s crude oil market over the last 18 months has exhibited so many dynamic changes that dedicated observers may be suffering from a bit of neck strain, if not outright whiplash. We’ve seen production rise at an unprecedented rate, followed by a period of slower growth. We’ve also watched the Permian very quickly transform from a region desperate for new long-haul pipeline capacity to a hotbed for midstream investment and infrastructure growth. While we’ve closely tracked these big-picture changes, a lot of other, smaller-scale knock-on effects have been occurring too, with potentially significant implications for the basin’s supply pricing and transportation economics. Today, we explain why the changing fortunes of Permian crude haulers may benefit producers in the basin.
U.S. LNG exports have climbed from zero to about 6 Bcf/d in less than four years. This year to date alone, three new liquefaction trains have come online at three different terminals with an additional train at Freeport LNG and Elba Liquefaction’s first four mini-trains in the commissioning process. The completion of these and other projects around the globe, particularly in Australia, have led to an oversupplied global market, made worse this year by a mild winter and high natural gas storage levels in Europe, and nuclear restarts and slowing demand growth in Asia. These dynamics sent international prices spiraling downward in recent months. Then, in September, prices briefly spiked up as regulatory news out of Europe suggested higher global gas demand. In the midst of all this market turmoil, U.S. export cargoes have remained unfazed. But the shifting fundamentals have played a role in where U.S. cargoes ultimately end up. Today, we begin a series looking into how liquefaction capacity contracts and international prices affect cargo destinations from U.S. LNG terminals.
During the 2010s, the Marcellus/Utica region has experienced an astonishing 16-fold increase in natural gas production, from 2 Bcf/d in early 2010 to more than 32 Bcf/d today. The region’s rapid transformation from minor energy player to superstar came with a lot of infrastructure-related growing pains, many of them tied to the urgent need for more gas pipeline takeaway capacity. Takeaway constraints have largely been addressed — at least for now — but producers’ continuing efforts to develop “wet,” liquids-rich parts of the Marcellus/Utica have resulted in an ongoing requirement for more gas processing and fractionation capacity. Put simply, as wet-gas production ramps up, so must the region’s ability to process that gas and its associated natural gas liquids. Today, we continue a series on existing and planned gas processing and fractionation projects in the Northeast with a look at the growing role played by Williams and its new Canadian partner.
The U.S. ethane market has experienced major ups and downs in the past couple of years. First, there was sharply rising demand from new steam crackers, a fractionation-capacity crunch and soaring ethane prices. Then came an ethane demand slump, plummeting prices and a big jump in inventories. More recently, though, the market seems to have returned to a state of relative equilibrium. Ethane prices have settled in — at least for now — at about 22 cents/gallon (gal), a couple of pennies below where they had been standing rock-steady before all hell broke loose. Ethane demand from existing steam crackers is rising again, and new cracker capacity is coming online. The questions now are, with demand on the upswing, will ethane prices be rising too — and, if so, by how much? And what does that mean for steam cracker economics? Today, we discuss recent developments in the ethane market and explain why there’s good reason to believe that ethane prices won’t be spiking anytime soon.
After months of severe natural gas pipeline constraints, Permian producers and shippers are reveling in the relief of new takeaway capacity. Kinder Morgan’s Gulf Coast Express (GCX) Pipeline, which began flowing initial volumes in mid-August, last week began full commercial service on its 2-Bcf/d greenfield route from the Permian to South Texas. Actual volumes on GCX are hard to come by, but all indications are that flows are ramping to near capacity. That surge in Permian outflows in recent weeks has propelled natural gas prices at the regional benchmark Waha Hub — which traded as low as $5.00/MMBtu below zero earlier this year and fell into negative territory as recently as August 8 — to nearly $2/MMBtu, levels not seen at the hub since last winter. However, with the sting from negative prices only now just fading, many in the market are wondering if this rally is here to stay or just a temporary reprieve. Today, we look at the latest developments in the Permian natural gas market.
Limetree Bay Refining’s plans to restart the former Hovensa plant in St. Croix, U.S. Virgin Islands, at the end of 2019 will add significant refining capacity to the North American stack, helping to offset the loss this year of the 335-Mb/d Philadelphia Energy Solutions plant in Pennsylvania. Limetree Bay is also poised to fill a void in Caribbean refining that’s been left by Venezuela’s economic collapse as well as the International Maritime Organization’s 2020 changes to the bunker fuel market. But the facility is not without its challenges, from high fuel costs and stiff competition from Gulf Coast refineries to tropical storms. Today, we conclude an analysis of the operation and potential markets for the refinery.
There already are indications that newly available takeaway-pipeline capacity out of the Permian Basin is goosing crude oil production growth there. Flows on those new pipes — Plains All American’s Cactus II and the EPIC system — are ramping up, crude exports are setting new records, and the end of big price discounts for oil at Midland versus Cushing and the Gulf Coast are giving Permian producers an economic incentive to produce more. And more takeaway capacity is on the way, including the 900-Mb/d Gray Oak Pipeline, which is slated to come online in the fourth quarter. Fast-rising production is putting new pressure on producers and their midstream partners to build and expand crude gathering systems and shuttle pipelines — especially in the Permian’s Delaware Basin, which has a lot less gathering pipe in the ground than the Midland Basin and which is poised for phenomenal production growth the next few months and years. Today, we discuss highlights from our second Drill Down Report on Permian gathering systems, this one focusing on developments in the fast-growing Delaware Basin in West Texas and southeastern New Mexico.
A build-out of NGL fractionators, steam crackers and export terminals for ethane, LPG and ethylene is actively in progress along the Gulf. This growth is spurring the development of new storage capacity — not just at the Mont Belvieu NGL hub, but in other, nearby areas with access to fracs, crackers and export docks. Much of this new storage capacity is being developed by companies that fractionate mixed NGLs and sell so-called “purity products” to meet their internal needs. However, at least one project is being built by what you might call an “independent,” whose aim is to connect to multiple pipelines and provide storage services to customers, without taking title to products alongside their customers. Today, we continue our series on existing and planned NGL storage facilities along the Gulf Coast with a look at Caliche Development Partners’ new storage complex in Beaumont, TX.
There’s a tough race underway among U.S. LNG developers jockeying for position in the global LNG market. U.S. supply growth has spurred the development of more than two dozen LNG export projects, the bulk of them along the Texas/Louisiana Gulf Coast. But regulatory bottlenecks and deepening oversupply conditions in international markets are creating strong headwinds and slowing the momentum for some of these massive projects, making it harder and harder for them to reach the regulatory and commercial milestones they need to pass before they can progress to the construction phase. That said, several projects have eked out big wins in recent weeks, including Tellurian’s $7.5 billion memorandum of understanding with India’s Petronet LNG Ltd for its Driftwood LNG project, signed just this past weekend, and LNG Ltd.’s 2-MMtpa sales and purchase agreement for its Magnolia LNG, inked early last week. Today, we provide highlights of recent regulatory and commercial developments that are pacing the proposed export capacity additions.
Every week, traders far and wide watch inventories at the storage hub of Cushing, OK, for insight into the U.S. crude oil market. Cushing has long been the epicenter for crude trading in the U.S., and while that role has shifted as the Gulf Coast gains more prominence, inventories at the Oklahoma hub are still a valuable indicator for traders looking for supply and demand trends. Recently, we’ve seen Cushing stocks drop significantly, declining for 11 straight weeks since the beginning of July to their lowest levels since last Thanksgiving. Today, we review the recent drop at Cushing, and discuss how a few changes in supply and demand fundamentals, plus strong pricing motives, helped drag down stockpiles this summer.
You may not know it by the look of the S&P E&P stock index, which has been flirting with record lows in recent weeks, but exploration and production companies are continuing to defy the industry’s legendary boom-and-bust cycles by pumping out increasing volumes of crude oil and natural gas while slashing spending. Some types of E&P companies have fared better than others in this lower-price environment. How are they continuing to generate substantial production growth under sharply lower capital investment programs? Today, we update our analysis of capital expenditures and production growth based on the second-quarter results of the 43 U.S. oil-focused, gas-focused, and diversified producers we track.