Here at RBN, we frequently receive questions about our thoughts on the value of storage. Whether it be crude, natural gas, or NGLs, we answer like any good consultant, “It depends.” What operational need does this storage serve? Where is it located? Does it have optionality for receipts and deliveries? These factors and many more can affect both the strategic and tactical value of a storage asset. Those assets that are integrated into midstream systems and facilitate movements from the upstream to the downstream are generally better poised for success. Those attempting to carve out a niche in isolation or relying on uplift purely from commodity price fluctuations … well, good luck to them. Today, we begin a series examining the value of — and changing markets for — crude oil storage.
The Permian Basin has attracted more than its share of midstream start-up companies over the past few years, and for good reason. The region has experienced big gains in crude oil, natural gas and NGL production, and that’s put stress on the Permian’s already significant pipeline infrastructure and spurred the development of many new projects. One new midstreamer that’s made a big splash is Lotus Midstream, which, since it was formed in early 2018, has partnered with some of the Permian’s biggest players — including ExxonMobil and Plains All American — to advance the now-sanctioned 1.5-MMb/d Wink-to-Webster crude pipeline. It’s also acquired Occidental Petroleum’s (Oxy) Centurion pipeline system, which includes a lot of crude gathering pipe and is one of the two main takeaway links between the Permian and the Cushing, OK, hub. What’s Lotus up to, and how is it shaping Permian crude transportation? Today, we examine what has quickly become one of the largest midstreamers in the U.S.’s hottest shale play.
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.
A few months back, we discussed the quandary that crude oil shippers face when deciding whether to commit to proposed new pipeline capacity out of the Bakken and the Niobrara, and from the Cushing, OK, hub to the Gulf Coast. The dilemma boils down to this: more capacity is needed, based on current constraints or projected growth (or both), but there’s some reluctance among shippers to make long-term commitments. Their worries are that production gains might slow and too much takeaway capacity might be built, resulting in bidding wars for barrels at the lease to fill shipper commitments. Well, in recent weeks there’s been a bit of a break in the project logjam; among other things, P66 and its partners have decided to proceed with the construction of both the Liberty Pipeline, from the Bakken and Niobrara to Cushing, and the Red Oak Pipeline, from Cushing to Houston and Corpus Christi via Wichita Falls, TX. And that’s not all. Today, we provide an update on efforts to develop new pipeline capacity from North Dakota and the Rockies to Oklahoma and beyond.
Old age and treachery will always beat youth and exuberance. So the saying goes, and it often holds true for midstream projects as well as people. Many times we’ve written that existing pipe in the ground beats new pipeline projects; it’s frequently easier and faster to expand the capacity of an older pipe than it is to build an entirely new pipeline. But eventually, contracts on these old pipelines expire, and as they do, shippers may have new, more attractive options — maybe proposed new pipes offer better connections to gathering systems, the ability to segregate batches of crude oil, and/or access to more desirable markets. Most importantly, they probably are willing to charge a lower tariff. In the Permian, we’ve seen a slew of new pipelines advance to construction by promising lower and lower shipping costs to move crude from West Texas to the Gulf Coast. Today, we look at how older pipelines’ re-contracting efforts will be affected by their competitors’ lower tariffs and operational advantages.
Only a few months after major crude oil takeaway constraints out of the Permian Basin caused price spreads to widen, the pipeline network serving the U.S.’s most prolific shale play may be on the brink of becoming overbuilt. We’ve already seen a number of new expansions and pipeline conversions completed in the past six months, and construction is underway on another 2 MMb/d of new pipeline capacity scheduled to come online between now and the first quarter of 2020. Beyond that, a few remaining projects have been proposed but have not yet reached final investment decisions. No midstream group wants to build a pipeline that will be half full, and no producer wants to make a 10-year commitment to a pipeline if there are going to be plenty of other options available. So who blinks first? In today’s blog, we review the Permian pipeline projects that are still on the fence and examine what factors will determine whether they end up being a “go” or a “no.”
Crude differentials in the Permian are getting squeezed. The spread between Midland and WTI at Cushing widened out to near $18/bbl at one point in 2018, when pipeline capacity was scarce. But that same spread averaged a discount of only $0.25/bbl in March 2019. Differentials between Midland and the more desired sales destination at the Gulf Coast are also in a vise. What gives? Production in the Permian continues to climb, but the rapid pace of growth we saw in 2018 has slowed down a bit lately, with fewer rigs in service and fewer new wells being brought on each month. More importantly, we’ve seen several new pipeline expansions and pipeline conversions come online in bits and bursts — in some cases, ahead of schedule — and this new chunk of pipeline space has compressed Midland pricing. In today’s blog, we begin a series on Permian crude takeaway capacity and differentials, with a look at the handful of new projects that have come online in the past few months and what has happened to Permian prices as a result.
Crude production is at all-time highs in the Bakken and the Niobrara, and the latest pipeline-capacity expansions out of both regions have been filling up fast. At the same time, producers in Western Canada are dealing with major takeaway constraints and are on the hunt for still more pipeline space. Midstream companies are trying to oblige, proposing solutions like a major Pony Express expansion or a new Bakken-to-Rockies-to-Gulf Coast fix — the Liberty and Red Oak pipelines — that could help address all of the above. The catch is that, with multiple producing areas funneling crude along the same general eastern-Rockies corridor and the outlook for continued production growth uncertain, how’s a shipper to know whether to sign a long-term deal for some of the incremental pipe capacity now being offered? Today, we consider the need for new takeaway capacity, the potential for an overbuild scenario, and what it all means for producers and shippers.
The market is used to crude oil spreads in the Permian Basin being volatile. Fast-paced production growth, the addition of new takeaway pipelines — and the rapid filling of those new pipes — have all impacted in-basin pricing, and we’ve seen differentials from the Permian to its downstream markets — Cushing, OK, and the Gulf Coast — widen and narrow as supply and demand fundamentals have changed. But recently, things have gotten a lot wilder. In September 2018, the Midland discount to WTI at Cushing blew out to almost $18/bbl, then narrowed to less than $6/bbl only three weeks later, thanks largely to the start-up of Plains All American’s much-ballyhooed, 350-Mb/d Sunrise Expansion. As Sunrise started to fill up, price differentials initially widened for a brief period of time. But, as we kicked off 2019, the Midland-Cushing spread quickly shrank further and then flipped, with Midland last Friday (January 25) trading at a $1/bbl premium to Cushing crude. You might wonder, how the heck did that happen? In today’s blog, we discuss how things play out when a supply glut evaporates and traders are suddenly caught in a tight market.
The possibility of reversing the flow on Capline — the U.S.’s largest northbound crude oil pipeline — has been discussed for a number of years now. Finally, it may be on the horizon. The three owners of Louisiana-to-Illinois pipeline announced last week that this month they plan to initiate a binding open season for a reversed Capline system that would enable southbound flows starting in the third quarter of 2020 — only a year and a half from now. And, as we discuss in today’s blog, reversing Capline’s direction could open up new crude-slate possibilities for Louisiana refineries and boost crude exports out of the Bayou State.
The Cushing, OK, storage and trading hub plays critically important roles in both the physical and financial sides of the crude oil market. Located at a central point for receiving crude from a wide range of major production areas — Western Canada, the Bakken, the Rockies, SCOOP/STACK and the Permian among them — the hub also has numerous pipeline connections to Gulf Coast refineries and export docks, and to a large number of inland refineries. And, with Cushing’s 94 MMbbl of storage capacity and status as the delivery point for NYMEX futures contracts for West Texas Intermediate, the hub’s inventory levels and the WTI-at-Cushing price are closely watched market barometers. But like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s place in the energy world has been in flux. Most importantly, Permian production has been surging, the ban on U.S. oil exports is a fading memory, and the Gulf Coast — not Cushing — is where most U.S. crude production wants to go. Today, we discuss Cushing’s changing role and highlights from RBN’s new Drill Down Report on the U.S.’s most important crude hub.
During the summer of 2018, crude oil inventories at the trading hub in Cushing, OK, dropped to extreme lows. With estimated tank bottoms around 14.6 MMbbl, Cushing stockpiles hit 21.8 MMbbl for the week of August 3. Traders’ alarm bells were ringing, and upstream and downstream observers were wondering if low storage levels were going to cause significant operational issues. But just when it seemed tanks were nearing catastrophic lows, inventories reversed course and started to climb. Since August, crude stocks have increased by 13.6 MMbbl, or nearly 60%, and there is now talk of potentially too much crude en route to Cushing, maxing out capacity there. There are many contributing factors to this most recent inventory swing, with increased domestic production and the tail end of refinery turnaround season being two of the bigger fundamental drivers. But the main catalyst has been the shift from a backwardated forward curve to a contango forward curve in the WTI futures market. Today, we continue our Cushing series with a snapshot of recent contango markets and the impact those prices have had on stockpiles at the central Oklahoma hub.
The race is on and here comes WTI up the backstretch. On November 5, CME Group launched a Houston WTI futures contract, challenging a similar trading vehicle from Intercontinental Exchange (ICE) that started up in mid-October. Ever since crude flows to the Gulf Coast took off five years ago, the crude market has been clamoring for a trading vehicle that would accurately reflect pricing in the region that dominates U.S. demand from refineries, imports and exports. Now there are two. But their features are quite distinct. ICE’s contract reflects barrels delivered to Magellan East Houston, while CME’s contract is based on deliveries into Enterprise’s Houston system. The specs are different, as are the physical attributes of the two delivery points. Will both survive? Probably not. Futures markets tend to concentrate liquidity — trading activity — into a single vehicle that best meets the needs of the market. So, which of these will come out on top? That’s what the crude oil market wants to know. In today’s blog, we delve into the differences between the two new futures contracts for West Texas Intermediate (WTI) crude delivered to Houston and ponder the market implications of these new hedging and trading tools.
Crude oil production has been increasing in virtually all of the shale and tight oil plays that send their output to the storage and distribution hub in Cushing, OK. A number of pipeline projects are being built and planned to accommodate that growth, and — despite the fact that two-thirds of Cushing’s existing storage capacity is currently unused — several million barrels of new tankage is being installed at the hub, again in anticipation of incremental needs in 2019, 2020 and beyond. So it should come as no surprise that midstream companies also are planning a good bit of new pipeline capacity out of Cushing, some to refinery customers in the Midwest and Midcontinent areas but some to refineries and export docks along the Gulf Coast. Today, we continue our series on the “Pipeline Crossroads of the World” with a review of rock-solid and potential plans to enable more crude to flow out of the central Oklahoma hub.
There’s been a lot of talk lately that the crude oil hub in Cushing, OK, is losing its luster — that it may not be as important as it once was. Folks point to the precipitous, months-long decline in crude inventories that started last fall, or to the fact that just about all of the planned oil pipelines out of the red-hot Permian are pointed toward Gulf Coast refineries and export docks, not central Oklahoma. Then you’ve got ICE and CME’s new WTI futures contracts, both deliverable in Houston — another challenge to Cushing. While Cushing’s role as the epicenter of crude storage and trading may be in flux, rumors of its demise have been greatly exaggerated, as evidenced by the long list of midstream projects under development to transport more crude to — and out of — the Oklahoma hub, and to add storage tanks there. Just yesterday (November 5), in fact, Magellan Midstream Partners and Navigator Energy Services announced plans for what would be the first new Cushing-to-Houston pipeline since 2014. Today, we continue our comprehensive review of the “Pipeline Crossroads of the World” with a look at the many capacity-expansion efforts now under way.