All this talk of trade wars is one more thing for U.S. oil and gas producers to worry about. That’s because overseas exports are the only thing balancing natural gas and NGL markets, and increasingly crude oil also relies on exports to clear light-sweet volumes from U.S. shale plays. More than half of propane produced in the U.S. already moves out of the country via ship, with China, Japan and South Korea among the highest-volume destination markets. Only about 3 Bcf/d of natural gas has been exported as LNG over the past few months, but there was only one lower-48 LNG export terminal operating until last week. In a year there will be six terminals pumping out LNG to overseas markets. And so far this year, an average of 1.4 MMb/d of crude oil — one-seventh of U.S. production — has reached the waterborne export market, not including all the gasoline and distillate exports. As exports assume an ever-larger role in U.S. hydrocarbon markets, it is important to consider ramifications of possible constraints on exports, including the potential for trade retaliation in response to President Trump’s recently announced tariffs on steel and aluminum. Exports, one of the key topics we’ll consider at our upcoming School of Energy — Spring 2018, is the subject of today’s blog.
Mexico continues to open up its refined-products sector to competition, and refinery troubles at government-owned Pemex are providing U.S. refiners and motor-fuel marketers with a golden opportunity to export increasing volumes of gasoline and diesel south of the border. But transporting all those refined products to Mexican population centers and distributing them to thousands of service stations requires port and rail terminals, pipelines and storage, and Pemex has been slow in relinquishing control of its infrastructure. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time looking at more port and rail-related projects and at existing and planned pipelines.
Crude oil production over 10 million barrels per day, just a fraction of a percent away from the November 1970 all-time record. Natural gas and NGLs already well above their respective record production levels. And for all three commodities, the U.S. market has only one way to balance: exports. One-third of all NGL production is getting exported, 15% of crude production now regularly moves overseas, and the completion of several new LNG export facilities will soon have more than 10% of U.S. gas hitting the water. The implications are enormous. Prices of U.S. hydrocarbons are now inextricably linked to global energy markets. It works both ways — U.S. prices move in lock step with international markets, and international markets are buffeted by increasing supplies from the U.S. It’s a whole new energy market out there, and that’s the theme for our upcoming School of Energy — Spring 2018 — that we summarize in today’s blog. Warning — this is a subliminal advertorial for our upcoming conference in Houston.
Rockies refineries have enjoyed higher margins than their counterparts anywhere else in the U.S. except California over the past four years, despite being typically smaller and less sophisticated plants. Attractive margins resulted in new investment by their owners — concentrating on the flexibility to process different crude types rather than just boosting capacity — because regional product demand is relatively stagnant. Today, we describe how some of those investments have paid off handsomely so far while others aren’t looking so savvy.
The opening of Mexico’s refined-products sector to competition after 80 years of Pemex monopoly is spurring the development of new motor fuel-related distribution infrastructure on both sides of the U.S.-Mexico border. A number of these pipelines, rail loading/unloading facilities, storage and other projects aren’t advancing as quickly as their developers may have hoped — replacing the old order with the new is taking time. But the need for new infrastructure is evident. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time focusing on rail-related projects.
Refiners in the five Rocky Mountain states that make up the U.S. Energy Information Administration’s Petroleum Administration for Defense District 4 — or PADD 4 — enjoy higher margins than their counterparts in every other part of the country except California. Quarterly crack spreads for domestic crude in PADD 4 averaged $25/bbl between 2014 and 2017, while those for Canadian crude averaged $31/bbl. Today, we explain that these lofty cracks reflect an abundance of crude — both from indigenous Rockies production and Canadian and North Dakota supplies passing through the region — as well as higher-than-average diesel and gasoline prices.
U.S. exports of motor gasoline and diesel to Mexico are up 60% from two years ago, and the ongoing liberalization of Mexican energy markets is allowing players other than state-owned Pemex to become involved in motor fuel distribution and retailing there. But there’s a catch. The port, pipeline, rail and storage infrastructure currently in place to receive U.S.-sourced gasoline and diesel and transport it within Mexico is inefficient and stressed. Further, Pemex owns or controls most of these fuel logistics assets and has been slow to make them available to others. Today, we continue our series on efforts to facilitate the transportation of motor fuels to and within the U.S.’s southern neighbor.
Record high production with prices still rangebound! As of year-end 2017, Lower-48 natural gas production was at an all-time high — 77 Bcf/d and rising. NGL production from gas processing was at 3.7 MMb/d, the highest since EIA started recording the numbers. And U.S. crude oil output stood at 9.8 MMb/d, within spitting distance of the 10 MMb/d record set back in October/November 1970. All this with the price of WTI crude oil no more than 9% higher than it was this time last year, and natural gas prices 20% below year-end 2016. Yup, the dogs are out. Productivity is the culprit: longer laterals, super-intense completions, manufacturing-process pad drilling — the list goes on. Clearly the U.S. can’t absorb all this production growth, so the export market must be the answer. Or is it? Are we really that confident that world markets will make room for still more U.S. hydrocarbons? If not, what does it mean for prices? And ultimately, how will these prices impact U.S. producers? These are big questions, and with this much turmoil in the market it is impossible to know what will happen. Impossible? Nah. No mere market turmoil will dissuade RBN from sticking our collective necks out to peer into our crystal ball one more time to see what 2018 holds.
So here we are. Last workday of 2017. Which means it’s almost time again to post our annual Top 10 RBN Prognostications for the upcoming year. According to our long-standing tradition, we’ll do that on the first workday of the New Year — Tuesday, January 2, 2018. But today, it’s time to look back, too see how those 10 Prognostications we posted way back at the start of 2017 — The Year of the Rooster in the Chinese calendar — held up. Yes, we actually check our work! In today’s blog, we grade ourselves on our year-ago views of how 2017 would turn out for energy markets.
The new normal. Or at least the market’s perception of a new normal. That’s how we will remember 2017. Producers have come to terms with the possibility of crude prices in the $50-60/bbl range for a long time to come, and natural gas stuck around $3/MMBtu. But even in the face of this sober market outlook, crude oil production is near its all-time record. And Lower-48 natural gas blew past its historic maximum a few weeks back. Increasingly the biggest challenges facing the market are related to infrastructure –– where will all these hydrocarbons find a home. As we have over the past six years, RBN tracked these trends in 2017 as they played out, and now at the end of the year, it’s time to look back to see what topics generated the most interest from you, our readers. We monitor the hit rate for each of our blogs that go out to about 23,000 of our members each day, 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 to check out the top blogs of 2017, based on the number of rbnenergy.com website hits.
Falling production of motor gasoline, diesel and other refined products at Mexico’s aging refineries has created a south-of-the-border supply void that U.S. refiners and refined-products marketers and shippers are all too eager to fill. At the same time, the ongoing liberalization of Mexican energy markets is finally allowing players other than state-owned Petróleos Mexicános (Pemex) to become involved in motor-fuel distribution and retailing. The results of all this? U.S. exports of gasoline and diesel to Mexico are up 60% from two years ago, and U.S. companies are scrambling to develop or acquire the infrastructure needed to deliver refined products to Mexican consumers. Today, we begin a new series on the increasing role of U.S. companies in supplying, distributing and retailing motor fuels in Mexico, and on the new transportation and terminalling infrastructure being built to support that growth.
Last Wednesday, November 22, the Federal Energy Regulatory Commission acted on a Petition for Declaratory Order (PDO) by Magellan Midstream Partners in which the midstreamer asked for FERC’s blessing to establish a marketing affiliate to “buy, sell and ship” crude oil on pipelines owned by Magellan as well as pipes owned by other companies. Today Magellan does not have such an affiliate, although many of its competitors do. Most of those competitors use their affiliates to generate incremental throughput on their pipelines, sometimes by doing transactions that result in losses for the marketing affiliate, but that are still profitable for the overall company because the marketing arm pays its affiliated pipeline the published tariff transportation rate. FERC denied Magellan’s request, coming down hard on such transactions as “rebates” specifically prohibited by the law governing interstate oil pipelines. In today’s blog, we take a preliminary look at FERC’s Magellan order and what it could mean for U.S. crude oil markets.
U.S. inventories of distillate — especially ultra-low-sulfur diesel (ULSD) and heating oil — are at their lowest pre-winter level in three years after falling during the summer months for the first time since inventory records started being measured in 1982. Rising diesel exports are one culprit; another is the shutdown of a number of Gulf Coast refineries during and immediately after Hurricane Harvey. The good news is that distillate prices have been increasing, as have the margins for refining crude oil into distillate — both encouraging refineries to ramp up their diesel/heating oil production. Today, we look at recent developments in the distillate market and what they may mean for diesel and heating oil prices this winter.
Over the past few years, rising production in the Canadian oil sands and U.S. shale plays such as the Bakken, Permian and Eagle Ford has given refiners new options for sourcing their crude, causing changes in oil pipeline utilization and prompting the development of new pipelines — or the reversal of existing pipes. A prime example of all this is playing out in Memphis, TN, where a Valero Energy refinery will be shifting from mostly U.S. Gulf Coast-sourced light crude to light crude that will flow in on the new Diamond Pipeline from the Cushing, OK, crude storage hub. Valero’s change in crude sourcing will be yet another blow to the 1.2-MMb/d Capline Pipeline, which for decades has moved crude north from the Gulf Coast to Patoka, IL, and other points along the way, including western Tennessee. Today, we look at the thinking and economics behind Valero’s plan and at the latest news on Capline.
For the past three years, the price for U.S. WTI crude oil at Cushing has remained close to $50/bbl while natural gas at the Henry Hub has gravitated in a range around $3.00/MMbtu. It has been one of the most stable periods of energy prices in decades. But below the surface of stability at the major hubs, prices at the regional level have been wildly volatile, driving dramatic swings in geographic basis. Alternating cycles of basis blowouts followed by basis collapses have become standard fare for U.S. oil, gas and NGLs as producers ramp up production, local prices get hammered due to capacity constraints, midstream companies respond by (over) building infrastructure, and regional price differentials implode due to overcapacity. With more production growth and infrastructure on the way, these basis cycles will keep on coming. In today’s blog, we’ll consider a few of the market sectors particularly susceptible to basis volatility, and provide a subliminal advertorial for our upcoming School of Energy, where we explore both the underlying causes and the outlook for future basis cycles.