Shipping companies now know that within three years all vessels involved in international trade will be required to use fuel with a sulfur content of 0.5% or less—an aggressive standard, considering that in most of the world today, ships are currently allowed to use heavy fuel oil (HFO) bunker fuel with up to 3.5% sulfur. This is a big deal. Ships now consume about half of the world’s residual-based heavy fuel oil, but starting in January 2020 they can’t—at least in HFO’s current form. How will the global fuels market react to a change that would theoretically eliminate roughly half the demand for residual fuels? How will ship owners comply with the rule? What are their options? Today we discuss the much-lower cap on sulfur in bunker fuels approved by the International Marine Organization, and what it means for shippers and refineries.
Daily energy Posts
Maya, Mexico’s flagship heavy crude, has been a key staple in the diet of U.S. Gulf Coast refiners for a long time, and it has faithfully served as a price benchmark for nearly all heavy crude oil traded along the U.S. Gulf, and points beyond. Maya’s price, relative to lighter benchmark grades such as Louisiana Light Sweet (LLS) or Brent, provides ready insight into the profitability of heavy oil (coking) refiners. But production of Maya peaked in 2004 and has declined considerably since then, raising questions about its continuing efficacy as a price benchmark. Now it’s come to light that a component of the Maya price formula was changed effective January 1, 2017. Although the change—related to the formula’s fuel oil price component—might be viewed as a relatively minor tweak, it raises new questions about this important heavy oil price benchmark. Today we begin a two-part series on Maya crude, the new price formula and its potential effects.
Northeast producers are about to get a new path to target LNG export demand at Cheniere Energy’s Sabine Pass LNG terminal. Cheniere in late December received federal approval to commission its new Sabine Pass lateral—the 2.1-Bcf/d East Meter Pipeline. Also in late December, Williams indicated in a regulatory filing that it anticipates a February 1, 2017 in-service date for its 1.2-Bcf/d Gulf Trace Expansion Project, which will reverse southern portions of the Transcontinental Gas Pipe Line to send Northeast supply south to the export facility via the East Meter pipe. Today we provide an update on current and upcoming pipelines supplying exports from Sabine Pass.
The recently announced combination of DCP Midstream LLC and DCP Midstream Partners LP creates the nation’s largest natural gas processor and natural gas liquids producer at what may be a particularly opportune time. The newly formed DCP Midstream LP, operating as a master limited partnership, owns 61 gas processing plants with a combined capacity of 7.8 Bcf/d—enough to process more than 10% of current U.S. production—as well as 12 fractionation plants, 59,700 miles of gas gathering pipelines and 4,600 miles of NGL pipelines. Better yet, many of these assets serve some of the U.S.’s most prolific and promising production areas, including the Midland and Delaware basins within the Permian; the Denver-Julesburg (DJ); and the side-by-side SCOOP and STACK plays. In today’s blog, we review the combined entity’s assets and prospects for growth in what soon may be happier times for NGL processors.
During the spring, summer and fall of 2016, U.S. propane inventories grew much more slowly than they did in the same period in 2014 and 2015, in part due to fast-rising exports. The situation isn’t dire––propane stock levels are relatively high as the winter of 2016-17 really kicks in, largely because last winter was a mild one that left inventories in good shape when the 2016 stock-building period started. But even-higher exports and the possibility of a “real” winter this time around raise the specter of an especially big drop in stored volumes over the next three months. Today we assess what the combination of higher exports and even an average winter could mean for propane inventories.
As U.S. crude oil and natural gas market prices and rig counts climb, the SCOOP and STACK in central Oklahoma continue to be two of the handful of plays attracting significant increased activity and investment, both on the producer and midstream sides. Production growth from the 11-county region covering the two plays is helping to offset declines in oil and gas volumes from other parts of Oklahoma and the Midcontinent region as a whole. Today we look at historical and recent drilling activity as an indicator of potential growth.
The normal butane market was anything but normal the past few weeks. All’s back to square one now, but in the last week of 2016 the price for normal butane spiked to more than $1.20/gal from only $0.73/gal in November. The differential between isobutane and normal butane plummeted into record-shattering negative territory. And the margin from cracking normal butane to make ethylene and other products fell off the chart—literally, our PowerPoints had to be reworked to show how much the margin had fallen. What the heck went on there? Today, we discuss the recent upheaval, what may have caused it, and why things snapped back to normal so quickly.
It hasn’t been widely reported, but during cold snaps in late fall and early winter, a number of crude oil producers in the Permian Basin have faced a “perfect storm” of events that made it challenging to meet crude pipelines’ vapor pressure standards. At first glance, this may seem like a problem for “the technical folks” to deal with, but in fact the issue has been affecting the ability to move crude to market, and the price of oil at Midland, TX versus the crude hub at Cushing, OK. It has even forced Permian producers to “shut in” some crude production—at least for a time—along several major pipelines in the region because they’ve been unable to adequately prepare their crude for piping or trucking. Today we examine an under-the-radar problem that’s been vexing producers in the U.S.’s leading crude oil play, and affecting oil prices and markets.
After enduring 2015-16 it is about time for some good news, right? And that’s just what 2017 is shaping up to be—a relatively good news year for energy markets. But don’t go crazy with this. The key word in that sentence is “relatively’” —which means better than 2015-16, but if you are looking for that other “R” word (“recovery”) you won’t see it here. Crude prices will be up some, but nothing like the first few years of this decade. Natural gas and NGL prices will be stronger too. But both may have to wait still another year before seeing a real upswing in 2018. Nevertheless, 2017 is looking good for most of the energy market. Not for everyone, mind you. Many will struggle because their assets are in the wrong places, they are at the wrong end of the food chain, or they were simply unprepared for this new market reality. How will you know the difference between the winners and losers? Well of course, by looking deeply into the RBN crystal ball to see what 2017—Year of the Rooster—has in store for us. Cock-a-doodle-do!
A long-standing tradition at RBN is our annual Top 10 RBN Energy Prognostications blog, where we lay out the most important developments we see for the year ahead. Unlike so many forecasters, we also look back to see how we did with our forecasts the previous year. That’s right! We actually check our work. Usually we can get that all into a single blog. But a lot will be coming at us in 2017, so this time around we are splitting our Prognostications into two pieces. Tomorrow’s blog will look into the RBN crystal ball one more time to see what 2017 has in store for energy markets. But today we look back. Back to what we posted on January 3, 2016. Recall back in those days that crude production had not started to decline materially, West Texas Intermediate (WTI; the U.S. light-crude benchmark) was at $37/bbl, natural gas was $2.33/MMbtu in the middle of winter, Congress had just OK’ed crude exports, and weak exploration and production companies (E&Ps) were dropping like flies. Now let’s look at RBN’s Prognostications for 2016.
From the depths of despair in the first quarter when WTI crude collapsed to $26.21/bbl on February 11 and Henry Hub gas crashed to $1.64/MMbtu on March 3, we are back, sort of. Growth in the rig count has been nothing short of spectacular, up 249 or 62% from the low point in late May. Crude oil, natural gas and NGL prices have all more than doubled since the lows of Q1. Yes, 2016 has been quite a roller coaster ride for energy markets. Here in the RBN blogosphere, we’ve documented this saga every step of the way. Now at the end of the year, as we’ve done for the past five years, it is time to look back. Back over the past 12 months––to see which blogs have generated the most interest from you, our readers. We track the hit rate for each of our daily blogs, and the number of hits tells you a lot about what is going on in energy markets. So once again we look into the rearview mirror at the top blogs of 2016 based on numbers of website hits in “The 2016 Hydrocarbon Top 10 RBN Blogs”.
Crude oil and natural gas production growth stalled in 2015 and has declined this year in some of the big shale basins. But we may be seeing a turnaround. The latest EIA Drilling Productivity Report, released on December 12, 2016, included upward revisions to its recent shale production estimates and also projects an increase in its one-month outlook for the first time in 21 months (since its March 2015 report). Today we break down the latest DPR data.
The Shale Revolution has had a profound impact on U.S. NGL markets by vastly increasing production and by lowering NGL prices relative to the prices of crude oil and natural gas. That has been good news for the nation’s steam crackers, the petrochemical plants that have enjoyed low NGL feedstock prices since 2012. But NGL markets are in for some big changes as new U.S. steam crackers coming online over the next two years will be competing for supply with export markets, raising the specter of higher NGL prices—a good thing for NGL producers, but not so for petrochemical companies. How this plays out will be determined by the feedstock supply decisions petrochemical producers make as NGL prices respond to rapidly increasing demand. Today we begin a series on how steam cracker operators determine day-by-day which feedstocks are the most economic, and on the factors driving the value of ethylene feedstock prices.
The build-out of incremental natural gas takeaway capacity out of the Marcellus/Utica region has come in fits and starts, with new pipelines—as opposed to the reversal or expansion of existing pipes—proving to be the most troublesome. Energy Transfer Partners and Traverse Midstream Holdings’ long-planned 3.25-Bcf/d Rover Pipeline to southern Michigan is a case in point. The latest challenge for the $4.2 billion project is getting final federal approval in time to allow tree clearing along the pipeline’s 711-mile route to be completed before federally protected bats start roosting in early April. If that timeline’s not met, Rover’s planned completion later in 2017 may be delayed a full year, enabling Western Canadian gas producers to sell more gas to Ontario and the Upper Midwest. Today we assess what’s at stake for ETP, Traverse, and producer-shippers in the Marcellus/Utica and Western Canada.
There’s good reason to believe that the international LNG market has turned a corner, with demand and LNG prices on the rise and with a number of new LNG-import projects being planned. That would be good news for U.S. natural gas producers, who know that rising LNG exports will boost gas demand and support attractive gas prices. It also would help to validate the wisdom of building all that liquefaction/LNG export capacity now nearing completion. Today we look at recent developments in worldwide LNG demand and pricing and how they may signal the need for more LNG-producing capacity in the first half of the 2020s.
The SCOOP and STACK combo play in central Oklahoma recently has emerged as one of the most prolific and attractive shale production regions in the U.S. Like the Permian Basin (albeit on a much smaller scale), rig counts in this play have weathered the crude oil price decline better than most of the rest and, along with the Permian, are leading a rebound as prices move higher. These days, SCOOP/STACK producers are primarily targeting crude oil and condensates, but the area also is seeing a resurgence of natural gas output from associated gas. More than that, given its economics, location and ample infrastructure, gas supply from the region has the potential to be directly competitive with Marcellus/Utica supply. Today, we begin a series analyzing production trends in the SCOOP/STACK, with a focus on natural gas.