RBN Energy

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.

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.

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.

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.

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 21^st-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.

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.

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.