U.S. energy markets are coming to the end of their latest infrastructure cycle just as the reality of tight capital markets is sinking in. Permian crude oil and natural gas takeaway constraints are being relieved by new pipeline capacity. Long-delayed LNG terminals and NGL-consuming petrochemical plants are coming online. Essentially all growth in crude, gas and NGL production volumes is being exported to global markets that — so far, at least — have been absorbing the incremental supply. But there is a chill in the air. Besides the recent bump-up in crude prices tied to last weekend’s attack on Saudi oil facilities, commodity prices have remained stubbornly low. Easy access to capital is a thing of the past. No longer can private equity count on the build-it-and-flip asset investment model. Yup, it’s another inflection point in the Shale Revolution that we’ll start exploring today. All this has huge implications for energy flows, infrastructure utilization and price relationships across all of the energy commodities.
Limetree Bay Refining plans to restart a former Hovensa plant in St. Croix, U.S. Virgin Islands, at the end of 2019. The refinery’s initial processing capacity of 200 Mb/d represents a significant addition to the North American stack, helping to replace the loss this year of the 335-Mb/d Philadelphia Energy Solutions plant in Pennsylvania. If it opens on time before the year’s end, Limetree will be well-positioned to fill a void in Caribbean refining that’s been left by Venezuela’s collapse as well as the International Maritime Organization’s (IMO) 2020 changes to the bunker fuel market. The plant’s location in the middle of world trade routes conveys some advantage, but it must compete with U.S. Gulf Coast refineries to supply regional markets. While higher input costs compared to U.S. rivals will dampen margins, a tolling agreement with BP could insulate Limetree from market exposure. Today, in the first of a two-part blog series, we review the operations and potential product market for the refinery.
It’s a challenging time to be active in the crude oil market in Western Canada. Barrels are selling at a huge discount to domestic U.S. benchmarks, there is major uncertainty surrounding most new pipeline projects and crude-by-rail opportunities, and Alberta officials are unsure how long to maintain caps on production. As a result, the Canadian market is wildly volatile. It seems like a piece of the fundamentals equation changes on a weekly basis, which makes it next to impossible for producers, shippers, refiners — or anyone else really — to make long-term decisions and plan for the future. And now, the Enbridge Mainline pipeline system is asking folks to do just that: sign up for multi-year take-or-pay contracts on Western Canada’s biggest takeaway system, or risk leaving barrels stranded for who knows how long. Some market players aren’t buying in. In today’s blog, we recap the recent protests of Enbridge’s plan and examine what might be driving the decisions of Canada’s biggest oil companies.
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.
The Shale Revolution that unlocked vast, low-cost oil and gas reserves, resulting in soaring production that transformed the U.S. from a major oil and natural gas importer to a rising exporter, was supposed to usher in a “Golden Age” for exploration and production firms (E&Ps). Instead, investors have increasingly abandoned energy equities, sending the S&P E&P stock index to an all-time low. The index closed at 3,272 on August 16, 2019, or about 75% lower than the all-time high of about 12,500 in mid-2014 and 46% lower than a year ago. And the stock prices of three-fourths of the big, publicly traded E&Ps have hit record lows over the last month. This energy-equities bloodbath would seem to indicate that the E&P industry is on the verge of financial meltdown. However, the just-released second-quarter 2019 results from the 44 U.S. E&Ps we track suggest that’s not entirely the case. Lower commodity prices certainly tightened the screws on the bunch, particularly companies that focus on gas production, but oil-weighted companies managed to eke out profit and cash-flow gains. Today, we provide an in-depth analysis of second-quarter earnings for oil-weighted, gas-weighted and diversified producers.
As exports of crude oil, natural gas and NGLs have surged, U.S. markets for these energy commodities have undergone radical transformations. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the volumes coming on over the next few years, if not for access to global markets. It is more important than ever to understand how the markets for crude, gas and NGLs are tied together, and how the interdependencies among the commodities will impact the future of energy supply, demand, exports and, ultimately, prices. Making sense of these energy market fundamentals is what RBN’s School of Energy is about. Warning! Today’s blog is a blatant commercial for our upcoming Houston conference. But we hope you will read on, because this time around, our curriculum includes all the topics we have always covered at School of Energy, PLUS five all-new sessions dedicated to export markets.
Crude oil pipeline shippers across the U.S., and especially in the Permian, are about to experience something they haven’t seen in a few years: a bunch of new crude takeaway capacity with lower-cost tariffs coming online, and the sudden need among committed shippers to fill their pipe space. This also affects some folks committed to space on older pipelines, whose higher-cost tariffs could leave them out of the money. The start-up of pipelines like Plains All American’s Cactus II, with a super-low $1.05/bbl tariff — and several pipelines in other basins lowering tariffs — has traders with pipeline commitments old and new re-running their economics and trying to determine their best strategy moving forward. Some may be forced to move volume at a loss. Today, we analyze the recent trend in tariff compression and how traders deal with uneconomical take-or-pay contracts.
Finally, after what seemed like a long period of crude oil pipeline takeaway constraints out of the Permian, significant new takeaway capacity is coming online this month. Just last week, Plains All American’s Cactus II pipeline from the Permian’s Midland Basin to the Corpus Christi area entered service. And on Monday, EPIC Midstream announced that it has begun interim crude service on its EPIC NGL Pipeline, which will move crude from the Permian’s Delaware and Midland basins — also to Corpus — until the company’s EPIC Crude Pipeline starts up in January 2020. With takeaway constraints alleviated, the focus on the crude-oil front now shifts to gathering system capacity, and it’s being added in spades. So much so that we’re writing two full Drill Down Reports (one on the Midland and one on the Delaware) to cover them in detail. Today, we discuss highlights from the first of our new Drill Down Reports, which focuses on crude oil gathering systems in the fast-growing Midland Basin.
Well, it’s finally going to happen! Without major fanfare, Plains All American and Marathon Petroleum announced earlier this month that they have sanctioned the reversal of the 40-inch-diameter Capline crude oil pipeline, a move that will enable light crude to flow south on that pipe from the Memphis area to St. James, LA, starting late next year and light and heavy crude to do the same from Patoka, IL, by early 2022. Also, Plains said it has committed to expanding the existing Diamond Pipeline between Cushing, OK, and Memphis, and extending that eastbound crude pipe from Memphis to a new interconnection with Capline. Light-crude service on the expanded, extended Diamond will commence in late 2020. Today, we review the newly sanctioned projects and their significance to U.S. and Canadian producers, Louisiana refiners and Gulf Coast exporters.
Of the many midstream companies with Permian crude oil gathering systems, a few also own bigger-diameter pipelines that shuttle crude to regional hubs as well as even larger takeaway pipelines to the Gulf Coast. Noble Midstream Partners is one of those that employs this “well-to-water” strategy, which enables midstreamers to participate in multiple links of the value chain; it can also give them better control over oil quality as crude makes its way from wells in West Texas and southeastern New Mexico to coastal refineries and export docks hundreds of miles away. Today, we conclude our series on Permian crude gathering with a look at the master limited partnership’s (MLP) mix of gathering, shuttle and long-haul pipelines.
The Niobrara production area in the Rockies is a complicated place to determine crude oil supply and demand balances. It’s at the crossroads of a number of supply areas, with volumes coming in from Canada and the Bakken, as well as locally from the Powder River and Denver-Julesburg basins. And in terms of destinations, there are well-established local markets, or you can send the molecules to Salt Lake City, or southeast to the Cushing, OK, hub and beyond. The Niobrara is one of the few growth areas we look at where there is substantial pipeline capacity for inflows and outflows, with the option to service multiple markets. Now, there are a couple of new pipeline projects ramping up in the Rockies, and given the region’s interconnectivity, it’s a good bet that the status quo in the Niobrara is in for some big changes. Today, we recap the new pipeline projects and then dive into what it could mean for the midstream balance in the Powder River and D-J.
The news has been out for a few days now: Enterprise Products Partners announced last Tuesday, July 30, that, thanks to new agreements with Chevron, the midstream company has made a final investment decision to proceed with its Sea Port Oil Terminal (SPOT) about 30 miles off the coast of Freeport, TX, pending regulatory approvals. Being out front on this is critically important; even with significant growth in crude oil export volumes through the early 2020s, only one or two new export terminals capable of fully loading Very Large Crude Carriers (VLCCs) are likely to be needed. What was it that enabled Enterprise to move first among a wave of proposed projects? And what does that tell us about the VLCC-ready export terminal projects being advanced by others? Today, we look at the SPOT project and the important roles that existing pipeline and storage infrastructure play in export terminal development.
It’s been an exciting and productive few years for Permian producers, but it’s also been a period fraught with challenges. Dealing with a mid-decade crash in crude oil prices. Struggling to improve yields from the Wolfcamp, Bone Spring and other hydrocarbon-rich formations to lower breakeven costs. Coping with major pipeline takeaway constraints — for crude and natural gas — and the resulting price discounts. Now, the challenge of produced water has come to the fore. Horizontal wells in some parts of the Permian generate six, eight, even 10 barrels of produced water per barrel of crude, and all of it needs to be either disposed of or treated. The volumes are enormous, the permitting and logistics mind-boggling, and the costs — well, you can imagine. Today, we consider the Permian’s produced-water conundrum as crude and gas production volumes ramp up. Warning!: Today’s blog is a blatant advertorial for new reports by B3 Insight on Permian produced water.
Crude oil gathering systems in the Permian and elsewhere are, by their very nature, evolving things. They increase in mileage and crude-carrying capacity as new wells are drilled and completed, and it’s not uncommon for smaller systems to be consolidated into larger ones. It’s also become typical for the ownership of these systems to change — sometimes year to year — as early investors cash in on what they’ve developed, and buyers see opportunities to rake in increasing revenue and take their newly acquired systems to the next level. Also, owners of neighboring systems sometimes form joint ventures that combine their assets, all to make their operations work better for their producer customers. Today, we continue our series on Permian gathering with a look at Brazos Midstream’s crude gathering system in the Delaware Basin, which has experienced considerable evolution.