Well, now we all know how it feels when the bottom falls out. In fact, it seems there is no bottom, with WTI crude at Cushing settling on Wednesday at $20.37/bbl, down $6.58/bbl. There is no point in belaboring the sad story here. You can read about pandemics, OPEC price wars and collapsed markets in every periodical on the planet. Likewise, there is no point in trying to predict what will happen next. Any pundit who tries to predict future prices in this environment is picking numbers out of the air at best. But at RBN, we are energy market analysts. As such, we are compelled to analyze something. And in these market conditions, there is one thing we can hang our hat on: No matter how bad things get, hope springs eternal. Thus, the market consensus is that things will be better a year from now, and even better a year after that. The implication? In a flash, crude is in steep contango, and that has repercussions for pipeline flows, regional price differentials and for storage — in production areas, at refineries, in VLCCs on the water, and especially at Cushing, OK, the king of oil storage hubs. Today, we examine one aspect of the chaos that now envelopes all aspects of energy markets.
Occidental Petroleum’s recent acquisition of Anadarko Petroleum made Oxy the #1 producer in the Denver-Julesburg (D-J) Basin and gave it a majority stake in Western Midstream Partners, which owns crude-gathering and other midstream assets in the D-J, the Permian and the Marcellus. While Western Midstream’s gathering focus had been on helping Anadarko meet its own midstream needs, Oxy sees the partnership taking on a broader role as a provider of gathering services to third parties as well. Toward that end, Oxy and Western Midstream a few days ago announced a series of agreements designed to allow Western Midstream to operate as an independent company. Today, we continue a series on crude-related infrastructure in the D-J with a look at Western Midstream’s gathering and related assets owned in part by the basin’s largest oil, natural gas and NGL producer.
Private equity is playing a critically important role in the build-out of crude oil gathering systems in the Denver-Julesburg (D-J) Basin, where rising production volumes — and the expectation of further growth, especially in and around Weld County, CO — are spurring a number of major projects. For proof, you need look no further than ARB Midstream, which, with backing from Ball Ventures’ BV Natural Resources, has developed the largest privately held crude transportation and storage network in the D-J through a combination of acquisitions and new construction. Producers have dedicated a quarter of a million acres to it. Today, we continue a series on crude-related infrastructure in the D-J with a look at ARB Midstream’s fast-expanding asset base there.
Crude oil gathering systems play an important role in a matter critical to producers, marketers and refiners alike: crude quality. Well-designed gathering systems can help deliver crude with the API gravity and other characteristics that refiners desire and are willing to pay a premium for. This has become a particularly big deal in the Denver-Julesburg Basin, where a big expansion of gathering capacity is under way, and where the market gives extra value to “Niobrara-spec” crude with an API of 42 degrees or lower. Today, we continue a series on existing and planned pipeline networks to move D-J-sourced crude from the lease to regional hubs and takeaway pipes with a look at Taproot Energy Partners’ system.
As a most eventful decade for the U.S. energy industry draws to a close and 2020 looms, it’s a perfect time to consider what’s ahead for the midstream sector — and, more important from an investor’s standpoint, for the individual companies within it. The last few years have driven home the point that while all midstreamers are impacted to some degree by what happens on a macro-level, the relative success of each company is tied to the myriad decisions its leaders make over time regarding which basins and hubs to focus on and which assets to build, expand, acquire or divest. Assessing these micro-level assets and the contributions they each make to a company’s bottom line requires particularly deep analysis. Today, we discuss key themes and findings from East Daley Capital’s newly issued 2020 Midstream Guidance Outlook.
The doubling of crude oil production in the Denver-Julesburg Basin over the past 18 months spurred a rapid build-out of crude gathering systems and other infrastructure. Unlike the sprawling Permian Basin, with its numerous centers of drilling and production activity in parts of West Texas and southeastern New Mexico, the vast majority of the D-J Basin’s incremental crude output has come from Weld County, CO. Understandably, Weld County also is where most of the D-J’s crude gathering systems are located, and where most of the gathering system expansions are being planned and built. Today, we continue a series on existing and planned pipeline networks to move D-J crude from the lease to regional hubs and takeaway pipes.
Crude oil production in the Denver-Julesburg (D-J) Basin has nearly doubled since January 2016 — only the Permian has outpaced the D-J’s growth rate over the same period — and production there now averages about 640 Mb/d. The D-J has just about everything producers want, including an unusually intense concentration of hydrocarbons within four geologic layers, or “benches,” only a few thousand feet below the surface, low per-well drilling costs, and direct pipeline access to the crude hub in Cushing, OK. Production growth in the D-J has spurred a rapid build-out of crude gathering systems and other infrastructure, especially in Colorado’s Weld County, the epicenter of D-J activity, which is located a short drive northeast of Denver. Today, we begin a series on existing and planned pipeline networks to move D-J crude from the lease to regional hubs and takeaway pipes.
Every so often, there’s talk that the crude oil hub in Cushing, OK, isn’t as important as it used to be. Don’t believe it. Want proof that Cushing is alive and well? Consider the growing list of pipeline projects into and out of the hub that have been coming online or advancing to final investment decisions, as well as the efforts to push Cushing’s storage capacity toward the 100-MMbbl mark. Midstream companies have committed to building more than 800 Mb/d of new pipeline capacity from Cushing to other hubs and to refineries, and another 1.6 MMb/d of capacity is in the pre-FID development stage. Today, we conclude a mini-series on recent developments at the Oklahoma oil hub with a look at storage expansions, new Cushing players, and outbound pipeline projects.
Crude oil inventory levels aren’t the only thing in a constant state of flux at the crude storage hub in Cushing, OK. A year ago, we blogged extensively about Cushing’s major players, storage assets and incoming and outgoing pipelines, as well as plans for new pipes that highlight the hub’s continued significance, even in an increasingly Permian- and Gulf Coast-focused energy sector. A lot has changed since then, though. Some pipeline projects into and out of Cushing have advanced to final investment decisions (FIDs), while others have floundered or foundered. Also, brand-new pipeline projects have been announced, as was a big acquisition that will make Energy Transfer a major player in Cushing storage. Today, we begin a short series on recent developments at the Oklahoma oil hub and how they reflect changes in the ever-evolving U.S. energy markets.
Every week, traders far and wide watch inventories at the storage hub of Cushing, OK, for insight into the U.S. crude oil market. Cushing has long been the epicenter for crude trading in the U.S., and while that role has shifted as the Gulf Coast gains more prominence, inventories at the Oklahoma hub are still a valuable indicator for traders looking for supply and demand trends. Recently, we’ve seen Cushing stocks drop significantly, declining for 11 straight weeks since the beginning of July to their lowest levels since last Thanksgiving. Today, we review the recent drop at Cushing, and discuss how a few changes in supply and demand fundamentals, plus strong pricing motives, helped drag down stockpiles this summer.
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.