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.
First came the “aha moment,” the realization that the Permian’s unusually complex geology — with multiple layers packed with hydrocarbons — is a solvable puzzle, and that the financial rewards for exploration and production companies could be very attractive. Then came the highly competitive scramble to acquire acreage in the most promising parts of the Permian’s Delaware and Midland basins. Now, with many producer’s acreage largely de-risked, competition to provide needed gathering systems and processing plants is white-hot, with some midstreamers in the prolific Delaware offering to write big checks to producers up front for commitments to infrastructure that in some cases is still on the drawing boards. These pay-to-play deals are ricocheting through the Permian business development community — at least in the Delaware. Today, we discuss recent developments in producer/midstreamer relations in the nation’s most active hydrocarbon play.
U.S. crude oil exports from the Gulf Coast remain at a high level, as does interest in transporting crude to Asia and Europe in Very Large Crude Carriers (VLCCs) capable of carrying as much as 2 million barrels (MMbbl) each. The catch is that only one Gulf port — the Louisiana Offshore Oil Port (LOOP) — can send out fully loaded VLCCs, and so far LOOP has loaded only one; other Gulf ports need to fill or top off the gargantuan tankers in open waters using reverse lightering. Plans are afoot to allow greater use of VLCCs, but how long will they take to implement? Today, we discuss the economic benefits of exporting crude on supertankers, the growing use of VLCCs for Gulf Coast exports and the challenges exporters face in utilizing them even more this year and next.
The combination of rising Western Canadian crude oil production, little-to-no available pipeline takeaway capacity and setbacks for pipeline projects appear to be breathing new life into crude-by-rail (CBR) activity. CBR played an important supporting role earlier this decade, helping address incremental takeaway needs until new pipelines came online. And there would seem to be plenty of CBR capacity at hand this time around — the region saw some serious over-building of crude-loading terminals in 2014-15. But there may be challenges in getting some of that CBR capacity back online quickly. Today, we continue our series on Western Canadian crude, this time focusing on the crude-by-rail factor.
Production growth in the Permian Basin continues to have profound effects on the crude oil, natural gas and NGL markets. It also has helped to spur the rapid development of what is, in effect, another midstream sector: one that focuses on the delivery of large volumes of water for hydraulic fracturing and — just as important, and even more challenging — the gathering and transportation of vast and increasing amounts of “produced water” that emerge from Permian wells with crude and associated gas. Until now, most Permian produced water has come from legacy conventional wells, but last year, the water volumes from unconventional, tight-oil wells caught up and their share will only rise from here on out. That’s a problem for producers — and a big one — because they can’t just re-inject the water back into the producing formation like they can with conventional wells. Today, we discuss highlights from RBN’s new Drill Down Report on water-related issues and infrastructure in the U.S.’s hottest shale play.
Three major crude oil pipeline projects now under development would add nearly 1.8 MMb/d of much-needed takeaway capacity out of the Western Canadian Sedimentary Basin (WCSB), a region hit hard by pipeline constraints and widening price differentials. But each of the three projects — Kinder Morgan’s Trans Mountain Expansion (TMX), Enbridge’s Line 3 Replacement Project and TransCanada’s Keystone XL — continues to face regulatory challenges and it remains unclear how many of the projects will advance to construction and how soon the first of them might come online. It’s also possible that one or more may go the way of Northern Gateway and Energy East, two major pipeline projects that went belly-up after years of planning. Today, we continue our blog series on Western Canadian crude oil with a look at Keystone XL and its prospects.
Corpus Christi, TX, is quickly becoming a strategic hub for U.S. crude oil exports. Since the repeal of the crude oil export ban in December 2015, crude exports from the Sparkling City by the Sea have increased to nearly 500 Mb/d — and that may be just the beginning. Numerous pipeline and terminal projects have been announced to receive, store and ship out a lot more crude from the Permian and Eagle Ford shale plays, with an increasing share of those barrels destined for the international market. Today, we discuss recent developments in crude exports out of South Texas.
With Western Canadian crude oil production rising, available pipeline takeaway capacity shrinking and crude-by-rail volumes rebounding, midstream companies are ramping up their efforts to get long-planned pipeline projects built. But that’s no easy task. Virtually every plan to add new takeaway capacity out of Alberta — Canada’s #1 energy-producing province — continues to face regulatory hurdles, and it remains to be seen which of the pipeline projects will be completed, and when. We can’t just throw up our hands, though, and say, “Who knows?” With pipeline constraints out of Western Canada worsening by the month and having profound negative effects on the price of Western Canadian Select (WCS), there’s real value in reviewing in some detail what these pipeline projects are up against. Today, we discuss what’s being planned on the takeaway front and where these projects stand.