Worldwide, refiners expect to add significant capacity over the next five years, mostly in the Middle East and the Asia Pacific region. While only a small amount of crude processing capacity additions are expected in the U.S. and Canada, the capacity additions elsewhere could have major product-trade and utilization effects on U.S. refiners — especially in PADD 1 (East Coast). Today we analyze expected near-term refinery capacity additions, global demand projections, and potential effects in the U.S.
Refiners in the Midwest and in the Mid-Atlantic states have each experienced good times and bad, both before the Shale Era and more recently. Lately, though, fortune has been smiling on the owners of midwestern refineries, a number of which have been expanded and reconfigured to run cheaper heavy crude from western Canada — changes that have put them at a competitive advantage to East Coast refineries running more expensive light crudes. Now, a proposed refined products pipeline reversal in Pennsylvania would allow more motor fuels to flow east from Petroleum Administration for Defense District (PADD) 2 into markets traditionally dominated by PADD 1 refineries. Today we look at recent developments in Midwest and Mid-Atlantic refining, and at the consequential battle for turf that’s just starting to flare.
If you missed the Golden State Warriors’ NBA Championship win last week, or an unbelievable putt at the U.S. Open this weekend you can always see it on ESPN’s SportsCenter. But what if you missed the most recent RBN School of Energy? Well, you’re in luck — we’re now offering 11 hours of video from SOE, which unlike other natural gas, crude oil or NGL conferences covers all three markets with hands-on course work. In each of the seven streaming-video modules, we drill down on an important aspect of the markets, explain how it works and provide spreadsheet models accompanied with instructional videos. Fair warning: Today’s blog is an unabashed advertorial.
Faced with uncertain growth in demand for refined products in the U.S., at least five refiners with major U.S. operations — including majors Shell, BP and Chevron — joined the bidding at a recent auction offering access to Mexico's downstream distribution system. Energy market reforms now unraveling national oil company Petróleos Mexicanos’ domestic supply monopoly are providing this opportunity. Initial auction winner Tesoro gained storage and pipeline capacity in two states in northwestern Mexico it expects to supply from a Washington state refinery. The market reforms also extend to retail gasoline stations, and majors BP and ExxonMobil as well as Valero and international trader Glencore have recently announced plans to launch retail networks in Mexico. Today we review the access Tesoro won in the first logistics auction as well as the wider Mexican market opportunity for refiners with operations north of the border.
U.S. exports of diesel and other distillates averaged 1.2 million barrels/day (MMb/d) in 2016, more than eight times their 2005 level and up slightly from 2015, another in a series of record-busting years for distillate exports. So far, 2017 looks like another winner. This year, though, a lot more distillate is being shipped south from Gulf Coast marine terminals to nearby Central America and South America, and less is being floated across the Atlantic to Western Europe. Today we consider recent trends in U.S. distillate exports and the significance of the export market to U.S. refiners.
The five refineries in the U.S. Pacific Northwest (PNW) performed better in 2016 than rivals on the East Coast for two main reasons. First, the changing pattern of North American crude supply has worked to their advantage. Faced with the threat of dwindling mainstay crude supplies from Alaska, refiners in Washington State replaced 22% of their slate with North Dakota Bakken crude moved in by rail. They have also enjoyed advantaged access to discounted crude supplies from Western Canada. Second, PNW refiners face less competition for refined product customers than rivals on the East and Gulf coasts, meaning they have a captive market that often translates to higher margins. Today we review performance and prospects for PNW refineries.
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.
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”.
Each winter, New York spot prices for gasoline and diesel spike higher than spot prices in Chicago, opening a seasonal arbitrage opportunity for Midwest refineries and motor fuel marketers—if only they could move more product east from Petroleum Administration for Defense District (PADD) 2 to the East Coast’s PADD 1. Midstream companies have taken note, and have been adding eastbound refined product pipeline capacity in Ohio and Pennsylvania. So far the aim has been to move gasoline and diesel as far east as central Pennsylvania, but the longer-term goal seems to Philadelphia, which ironically is the center of East Coast refining. Today we look at the ongoing shift in market territories claimed and sought by gasoline and diesel refineries and marketers in PADDs 1 and 2.
Mexico’s consumption of motor fuels is rising, its production of gasoline and diesel continues to fall, and U.S. refineries and midstream companies are racing to fill the widening gap. The export volumes are impressive: deliveries of finished motor gasoline from the U.S. to Mexico averaged 328 Mb/d in the third quarter of 2016, up 41% from the same period last year, and exports of low-sulfur diesel were up 29% to 194 Mb/d. And there’s good reason to believe that U.S.-to-Mexico volumes will keep growing. Today we look at recent trends in gasoline and diesel production and consumption south of the border, and at ongoing efforts to enable more U.S.-sourced gasoline and diesel to reach key Mexican markets by rail and pipeline.
OPEC’s agreement at its November 30 meeting to cut crude oil output has sent prices soaring. Many U.S. producers already are anticipating brighter days, but before anyone pops the champagne it’s important to consider the deal’s potential vulnerabilities, and to factor in other market developments that reduce the agreement’s effect. Today we look at pre-deal maneuvering, the impact of those maneuvers on the level of supply, and the things that could still derail the move to market equilibrium.
On November 17, 2016, Tesoro Corp., the second-largest independent refiner in the Western U.S., announced an agreement to acquire Western Refining for an estimated $6.4 billion. This is the second acquisition that Tesoro has made this year, following the purchase of the MDU Resources/Calumet Specialty Products Partners’ joint venture refinery in North Dakota. And—ironically, considering the name of the company Tesoro is buying—the Western Refining deal will expand Tesoro’s footprint further east than ever. Today we evaluate the legacy assets of Tesoro and Western Refining and discuss how the two companies will likely fit together.
On the last day of October 2016, the first-ever shipment of Chinese motor gasoline to the U.S. was delivered to Buckeye’s Reading terminal in New York Harbor. The vessel took a circuitous route to New York, taking on cargo in the Hong Kong lightering zone, stopping in South Korea to take on another parcel of clean product, dropping off some benzene in Houston, and then finally heading to New York. That complicated journey suggests that the economics of a regular China-to-East Coast gasoline trade route are not there (at least for now), but the shipment highlights a trend: China is becoming more assertive as an exporter of petroleum products and the implications are global. In an international market defined by oversupply, inroads by China necessarily result in other producers losing market share. In today’s blog, we examine the impact of rising clean petroleum product exports—particularly from China, but also from India—and the corresponding ripple effects both on the world market and on U.S. refiners.