It’s safe to say that Permian producers had a good Christmas. Sure, their stock prices may be off a bit and their rig counts are down. But the absolute prices they are paid for their crude oil are up by almost $20/bbl versus this time in December 2018, and the price spreads between the Permian and neighboring markets have significantly narrowed as a result. What’s driving this change? There are a variety of factors at play, but chief among them is the new pipeline infrastructure that has helped lift Permian producers’ oil price realizations. Today, we check in on the status of one of the major new pipelines that have contributed to the seismic shift in the Permian oil market this year.
Despite last month’s much-publicized start-up of two new crude oil pipelines from the Permian Basin to the Gulf Coast — Plains All American’s Cactus II and EPIC Crude Holding’s EPIC Pipeline — tangible evidence of how much crude is actually moving on those pipelines has been hard to come by. That’s because crude oil pipelines don’t post daily flow data, like some natural gas pipelines do, and shipper volumes are a closely held secret that often only becomes available long after the fact. However, Cactus II and EPIC both deliver into the Corpus Christi, TX, market area, where a number of export facilities have been waiting to move Permian barrels out into the global market. We’ve been keeping a close eye on Corpus-area docks and have noticed a significant increase in export volumes over the last few days — a clear indication that Permian crude on Cactus II and EPIC has broken through to the global market. Today, we detail a recent rise in Corpus Christi oil export volumes driven by new supply from the Permian Basin.
Battered by a flood of new supply and limited pipeline takeaway capacity, prices for Permian natural gas and crude oil have spent a lot of time in the valley over the past 18 months. West Texas Intermediate (WTI) crude oil prices at the Permian’s Midland Hub traded as much as $20/bbl less than similar quality crude in Houston last year. That’s a big oil-price haircut that producers have had to absorb while ramping up production. However, the collapse in the Permian crude oil differential was tame compared to what happened with Permian natural gas prices. Prices at the Waha Hub in West Texas traded as low as negative $5/MMBtu, a gaping $8/MMBtu discount to benchmark Henry Hub in Louisiana. As bad as that all was, new pipeline takeaway capacity has arrived, and Permian prices are beginning to claw their way out of the depths. Today, we look at how new pipelines are impacting the prices received for Permian natural gas and oil.
It’s no secret by now that Permian oil markets have struggled over the last two years as nagging takeaway-pipeline constraints put a damper on production growth and, at times, hammered pricing in the basin. Like the Houston Astros’ opponents in the AL West, though, the days are numbered now for Permian oil market constraints, as two new large-diameter pipelines from West Texas to Corpus Christi will be in-service by the end of the month. One of those pipes, Plains All American’s Cactus II, is set to enter service this week. Today, we assess the potential implications of the latest Permian long-haul pipeline expansion, and introduce RBN’s new weekly publication, Crude Oil Permian!
It’s been nine months since Plains All American’s Sunrise II crude oil pipeline started service out of the Permian to the Wichita Falls, TX, crude hub. In that time, it has transformed the balance of supply versus downstream takeaway capacity at Wichita Falls and become a critical conduit of Permian crude to the Cushing and Gulf Coast markets. What’s more, Plains is planning to build the Red Oak Pipeline from Cushing through Wichita Falls to the Gulf Coast in 2021, which will further solidify Sunrise II as an important outlet for Permian oil for some time. With two other new long-haul Permian crude pipelines — EPIC and Cactus II — days away from starting interim service to the Gulf Coast, an analysis of Sunrise II’s impacts thus far provides some clues as to how future expansions will reshape the region. Today, we discuss how Plains’ Sunrise II project has affected crude oil flows from the Permian to Wichita Falls, and from there to Cushing and the Gulf Coast, as well as what its role will be when Red Oak comes online.
Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the types running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That’s not basis, but absolute price, a long-anticipated possibility that became reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won’t see new greenfield pipeline capacity for at least 10 months. What happens next isn’t clear, but expect Permian gas market participants to be a little excitable or jittery over the next few months. Today, we review this latest complication for Permian natural gas markets.
Crude oil inventories at Cushing have been in a free fall. After last peaking at more than 69 MMbbl in April 2017, stockpiles have decreased to less than 22 MMbbl recently, nearing all-time lows for tank utilization at the Oklahoma crude-trading hub. While we’ve seen volumes drop quickly in the past, inventories have now declined for 12 straight weeks at a staggering pace. Traders, refiners, and other market participants are starting to fret. Is this just another cyclical trend or are market factors exacerbating the impact? Today, we examine the influence of historical pricing trends on Cushing inventories and why it seems that demand factors are speeding up the drop.
Over the last year or so, Plains All American Pipeline — a large, crude oil-focused master limited partnership (MLP) — has twice made significant changes to its corporate structure and distribution process to free capital to fund organic growth, reduce debt, and strengthen distribution coverage. The changes are efforts to fix a problem: As oil prices plunged, PAA’s distribution coverage fell below 100% in 2015 and 2016, forcing the company to add debt and issue equity to raise cash. An initial restructuring that Plains undertook in mid-2016 included eliminating the incentive distribution rights (IDRs) payable to its general partner — the IDRs had been draining $620 million per year. (For more on IDRs, see Changing Horses in Midstream.) The change resulted in a 21% reduction in the distribution to limited partners as PAA set a minimum annual distribution coverage target of 115%. But plunging profits from the company’s Supply & Logistics segment eroded its coverage to 99% in 2017, triggering another comprehensive review of how it calculates its distribution. In late August, Plains announced a 45% reduction in the annual distribution, from $2.20 per unit to $1.20 per unit, and said it would base future distributions only on the results from its fee-based Transportation and Facilities segments. Today we preview our new Spotlight Report on Plains, which provides a detailed analysis of the likely future performance of all three segments of this major midstream MLP.
New pipelines to increase crude oil takeaway capacity from major producing areas like the Permian and the Bakken to oil storage and distribution hubs like Houston, TX and Cushing, OK seem to garner most of the media’s attention. Just outside the spotlight’s glare, though –– and even during the ongoing slump in oil prices –– midstream companies are building several “demand-pull” pipelines to move crude to refineries more efficiently, and to give refineries easier, cheaper access to new, desirable supplies. Today, we begin a look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.
The St. James, LA crude trading hub provides feedstock to 2.6 MMb/d of regional refining capacity as well as refineries in the Midwest. St. James is also an important distribution hub for crude from North Dakota, South Texas, the Gulf of Mexico and onshore Louisiana as well as imports arriving at the Louisiana Offshore Oil Port (LOOP). Crude storage and midstream infrastructure at St. James has been expanding in recent years as the trading hub handles larger volumes of domestic production. Today we begin a new series looking at infrastructure and crude pricing at St. James.
Crude oil production growth in Oklahoma over the past two years has been so rapid that apparently the State of Oklahoma “misplaced” (under-reported?) as much as 100 Mb/d of output according to a recent Energy Information Administration (EIA) report. Whatever the true production numbers a couple of central Oklahoma plays continue to attract new drilling and infrastructure investment in the face of the oil price meltdown. Today we describe new infrastructure in the region.
According to the latest Energy Information Administration (EIA) monthly Drilling Productivity Report, crude production from the Niobrara shale in Colorado and Wyoming peaked at 491 Mb/d in April 2015 and is forecast to decline by ~100 Mb/d to 388 Mb/d through March 2016 – in response to falling crude prices and lower drilling activity. Meantime midstream companies are still building new pipeline capacity out of the region with the Saddlehorn and Grand Mesa projects set to add 350 Mb/d of takeaway capacity this year (2016). The pipeline build out has already caused a shift of crude shipments away from crude-by-rail (CBR) that peaked in December 2014. Yet as we describe today - rail terminals and infrastructure are still under construction in the region.
Over the past few years, midstream companies have responded to the boom in crude oil and lease condensate production in the Eagle Ford and the Permian by developing significant new pipeline capacity to, as well as storage and dock facilities in, both Houston and Corpus Christi. Now, with production in the Eagle Ford off its high and growth in the Permian slowing, these same midstreamers (and producers, marketers, refiners, and exporters of condensate and other refined products) are taking stock, and assessing not only what new infrastructure might still be needed in this period of lowered expectation, but whether shifting more of their attention (and liquids) towards Corpus instead of Houston might be warranted. Today, we continue our look at Corpus Christi’s increasing role as a crude/condensate powerhouse.
The flood of domestic light shale crude showing up at the Texas Gulf Coast by pipeline in the past two years is not best matched to most refineries in the region that are configured to run heavier crude. But flows across the Gulf Coast to refineries in the Mississippi Delta more suited to process light crude are constrained by a lack of pipeline capacity between Texas and Louisiana. New domestic shale crude has been delivered to eastern Gulf Coast terminals such as St. James by rail but narrowing coastal differentials to inland prices have reduced the CBR advantage. Today we detail how new pipeline projects promise to increase the flow of crude from Texas to the Eastern Gulf.
The Plains All American (PAA) Cactus Pipeline comes online in the West Texas Permian this month (April 2015). Cactus will bring up to 250 Mb/d of crude and condensate from Midland and McCamey in the Permian to Gardendale, TX - the heart of the Eagle Ford shale – linking the two basins for the first time by pipeline. It also forms a major component of an expanded pipeline and dock infrastructure owned by a combination of PAA and Enterprise Product Partners (EPD) set to deliver as much as 600 Mb/d of crude and condensate to Corpus Christi and 470 Mb/d to Houston by the end of 2015. Today we describe how a good deal of those deliveries will be processed condensate eligible for export.