The sharp increase in U.S. crude oil exports over the past couple of years is tied primarily to Texas ports — mostly Corpus Christi and the Houston Ship Channel. Louisiana, a distant second in the crude-exports race, has a long list of positive attributes, including the Louisiana Offshore Oil Port (LOOP) — the only U.S. port currently capable of fully loading the Very Large Crude Carriers that many international shippers favor. It also has mammoth crude storage, blending and distribution hubs at Clovelly (near the coast, connected to LOOP) and St. James (up the Mississippi). In addition, St. James is the trading center for benchmark Light Louisiana Sweet, a desirable blend for refiners. The catch is that almost all of the existing pipelines at Clovelly flow inland — away from LOOP — many of them north to St. James. That means infrastructure development is needed to reverse these flows southbound from St. James before LOOP can really take off as an export center. Today, we continue a blog series on Louisiana's changing focus toward the crude export market and the future of regional benchmark LLS.
Necessity is the mother of invention, and the desperate need to transport increasing volumes of crude oil out of the severely pipeline-constrained Permian is spurring midstream companies and logistic folks in the play to be as creative as humanly possible. With the price spread between the Permian wells and the Gulf Coast exceeding $15/bbl in recent days — and possibly headed for $20/bbl or more soon — there's a huge financial incentive to quickly provide more takeaway capacity, either on existing pipelines or by truck or rail. Are more trucks and drivers available? Is there an idle refined-products pipe that could be put back into service? Could drag-reducing agents be added to an existing crude pipeline to boost its throughput? How quickly could that mothballed crude-by-rail terminal be restarted? Today, we discuss frenzied efforts in the Permian to add incremental crude takeaway capacity of any sort — and pronto.
U.S. crude oil exports have averaged a staggering 1.6 MMb/d so far in 2018, up from 1.1 MMb/d in 2017, and the vast majority of these export volumes — 85% in 2017 — have been shipped out of Texas ports, with Louisiana a distant runner-up. The Pelican State has a number of positive attributes for crude exporting, though, including the Louisiana Offshore Oil Port (LOOP), the only port in the Lower 48 that can fully load the 2-MMbbl Very Large Crude Carriers (VLCCs) that many international shippers favor. It also has mammoth crude storage, blending and distribution hubs at Clovelly (near the coast and connected to LOOP) and St. James (up the Mississippi). In addition, St. James is the trading center for benchmark Light Louisiana Sweet (LLS), a desirable blend for refiners. The catch is that almost all of the existing pipelines at Clovelly flow inland — away from LOOP — many of them north to St. James. That means infrastructure development is needed to reverse these flows southbound from St. James before LOOP can really take off as an export center. Today, we consider Louisiana's changing focus toward the crude export market and the future of regional benchmark LLS.
Even with crude oil prices down $1.67/bbl yesterday, the wide differential between Permian prices and those in destination markets held up, with WTI Midland trading at $15.60/bbl below the same quality of oil on the Gulf Coast. This has become a red-hot topic for all Permian-watchers. For example, in first quarter earnings calls, a number of producers not only reported their Permian well productivity and drilling plans, they also reviewed how much firm pipeline space they have signed up for in the Permian and how they plan (or hope) to avoid negative financial consequences from the differential blowout. With so much demand for new pipeline space, shouldn’t it be easy to get a bunch of shippers signed up for long-term commitments to fund a new project? Today, we’ll look at what it takes for commitments to pay off massive pipeline projects, the hurdles midstream companies go through to achieve it, and the possibility of new pipeline projects getting added to the development schedule.
For a month now, the number of active drilling rigs in the U.S. has topped 1,000, the first time that’s happened since the spring of 2015, when the rig count was in the midst of a frightening tailspin — it fell from more than 1,900 in November 2014 to only 400 in May 2016. What a long, strange trip it’s been, not just for the rig-count total but for gains producers have seen in drilling productivity and in crude oil and natural gas production per well. Exploration and production companies are doing far more with less, trimming costs and increasing returns in the Permian, the Marcellus/Utica and other key production basins to levels few would have thought possible a few years ago. Today, we review the key changes we’ve seen in drilling productivity, and what they mean for U.S. E&Ps and midstream companies and the rig count going forward.
Seems like just about everything to do with energy markets is up these days. Crude oil prices are back to the levels of late 2014. Crude production hit a 10.6 MMb/d record volume last week, while lower-48 natural gas has been bouncing around an 80 Bcf/d record level. Exports of crude, gas and NGLs are at all-time highs. But all those hydrocarbon molecules must find their way from the wellhead to market, and in several high-growth regions, that is becoming increasingly problematic, as midstream infrastructure struggles to keep up. In our recent School of Energy, we examined these developments, considering their impact on production trends, domestic demand and the outlook for growth in export volumes. Did you miss it? Not a problem. We taped the whole conference, and School of Energy Online is now available in 12 hours of streaming video, along with all the Excel models, slides, and graphics that we use to tie energy markets together. Today, in this unabashed advertorial, we review some of the highlights of the conference.
Large-scale and well-funded producers in the Permian have built dedicated gathering systems and signed up for pipeline-takeaway options to keep their barrels moving to markets at the Gulf Coast and Cushing. For the most part, smaller producers don’t have the same options, for a variety of reasons. More and more, barrels from outside the core areas of the Permian are competing for the last bits of pipeline space and producers are being forced to rely more heavily on Permian trucking companies to help keep their crude flowing. Truckers are being asked to make less desirable, less economical and longer hauls, and are passing those costs back to the producer. With pipeline takeaway capacity maxed out, trucking capacity is being pushed to the limit too, with several potential upstream impacts. Today, we look at trucking options for smaller producers in second-tier production areas, the impact of boom-bust cycles on trucking companies and what tight trucking capacity means for the basin as a whole.
If you’ve been watching market prices over the last week, you’ll have noticed that Permian differentials have tightened a bit. With the capacity of the new Midland-to-Sealy pipeline ratcheting up and the 146-Mb/d Borger refinery near Amarillo coming back online, there has been a brief respite for crude oil prices in West Texas. But soon, continued growth in crude production will again max out pipeline capacity out of the Permian until one of the major new pipes starts operating in 2019. In the interim, producers and traders without firm pipeline space will be taking deep price discounts, all the while attempting to maintain their revenue streams by sticking to their development plans or, at the very least, avoiding the specter of well shut-ins. Today, we dive into the current state of affairs regarding Permian pipeline allocations, the impact on producer logistics, and what it all means for price differentials.
As Permian crude differentials continue to widen, trading at a $8.45/bbl discount to Magellan East Houston this week, a lot of people are pointing fingers at midstream companies for not completing new takeaway pipeline projects quickly enough. But even in the oil patch, it takes two to tango and producers can also share some of the blame. Historically, the focus in the Permian has been on larger producers, with their sprawling acreage positions and their focus on creating long-term competitive advantages through efficient drilling programs. Many of the smaller, private equity-backed producers adopted more short-term strategies. Their game has been to prove undervalued acreage and then flip those assets to more substantial players. But these strategies are beginning to change. Today, we continue our series on Permian differentials with a look at how the recent ramp-up in the development of second- and third-tier production areas is affecting the region’s crude oil output, pipeline takeaway constraints and price differentials.
The Permian is a beehive of activity on the burgeoning water midstream front — the pipelines, saltwater disposal wells and other assets being built to facilitate the delivery of water to new wells for hydraulic fracturing and the transport of “produced water” from the lease to disposal or treatment sites. But the Bakken — arguably the birthplace of the water midstream sector nearly a decade ago — is no slouch, and a model of sorts for the infrastructure build-out now under way in the Permian. The volume of water needed for Bakken well completions is up sharply in recent years; more important still, the region is generating more than 1 MMb/d of produced water, and producers and water midstreamers alike are building new takeaway pipelines and drilling new SWDs to more efficiently deal with it. Today, we discuss water- and produced-water-related infrastructure in one of the U.S.’s largest production regions.
Price differentials in the Permian Basin are widening at a rapid pace. The discount for Midland crude to West Texas Intermediate (WTI) at Cushing has widened by over $4/bbl since the beginning of March and the discount to Magellan East Houston (MEH) crude was over $7/bbl yesterday. Permian production is increasing at a breakneck pace as new players are entering the scene. Private equity-backed exploration and production companies (E&Ps) are no longer just acquiring and flipping acreage, as they are being forced to prove their assets are profitable and can generate a return on investment. The combination of large drilling plans from the majors and new production from these smaller operators — with no new pipeline takeaway capacity in sight — has sent Permian crude pricing into a tailspin. Today, we begin a new series on the recent slide in Permian prices, how new producer strategies are contributing to it, and what it means for pipeline space, trucking and midstream infrastructure.
Crude oil and natural gas production in Oklahoma have fully rebounded from the declines that followed the 2014-15 collapse in oil prices and stand at 21st-century highs. While the active rig count in the state — at about 120 in recent weeks — is off 10% from its post-crash peak in mid-2017, the productivity of new wells continues to rise, as does interest in the Merge play between the SCOOP and STACK production areas in central Oklahoma and in the Arkoma Woodford play to the southeast. All that has put additional pressure on the state’s existing pipeline and gas-processing infrastructure and spurred continuing activity among midstream companies. Today, we begin a review of ongoing efforts to add incremental processing and takeaway capacity in the hottest parts of the Sooner State.
With crude prices in the $60s, oil-producing basins other than the Permian are finally seeing signs of life, and that includes the Rockies. But volumes flowing through the most important Rockies crude oil hub — at Guernsey, WY — are down. Moreover, the price of oil at Guernsey is up, trading at least flat and sometimes at a premium to the downstream market at Cushing, OK, suggesting that committed shippers are having to bid up the price at Guernsey to secure barrels for their downstream pipeline commitments. What about production from the nearby Powder River Basin? Well, Powder River oil production is up, and the rig count there is double what it was this time last year, so you might think there would be more than enough barrels at Guernsey. But not so. Who’s to blame? We need to look no further than the Bakken and the Dakota Access Pipeline (DAPL) to discover our culprits. Today, we check in on the market at Guernsey and consider the impact of DAPL, the implications for Rockies crude oil outflows, and what it all means for Guernsey price differentials.
Crude oil production in the Permian Basin is coming on strong — faster than midstreamers can build pipeline takeaway capacity out of the basin. You can see the consequences in price differentials. On Friday, the spread between Midland, TX and the Magellan East Houston terminal (MEH) on the Gulf Coast hit almost $5.00/bbl, a clear sign of takeaway capacity constraints out of the Permian. We’ve seen different variations of this scenario play out in recent years, most recently last fall, just before the first oil started flowing through the new Midland-to-Sealy and Permian Express III pipelines, and it’s not good news for Permian producers. Now Permian output is again bouncing up against the capacity of takeaway pipelines and in-region refineries to deal with it. As we’ve seen in the past, that’s a warning sign for possible price-differential blowouts. Today, we discuss the fast-changing market dynamics that put Permian producers at risk for another round of depressed Midland prices.
Western Canadian Select (WCS), a heavy crude oil blend, has been selling for about $25/bbl less than West Texas Intermediate (WTI) at the Cushing, OK, hub — a hard-to-bear experience for oil sands producers that have made big investments over the past few years to ratchet up their output. And the WCS/WTI spread is unlikely to improve much any time soon. Pipeline takeaway capacity out of Alberta has not kept pace with oil sands production growth, and existing pipes are running so full that some owners have been forced to apportion access to them. Crude-by-rail (CBR) is a relief valve, but it can be costly. Worse yet, production continues to increase and the addition of new pipeline capacity is two years away — maybe more — so deep discounts for WCS are likely to stick around. Today, we discuss highlights from our new Drill Down Report on Western Canadian crude markets.