Right now, pipeline capacity out of the Permian is constrained, and consequently some producers have cut back on well completions, more gas is getting flared, and ethane recovery is being driven more by bottlenecks than by gas plant economics. But even with these issues, there are still 487 rigs drilling for oil in the basin (according to Baker Hughes), and all will come along with sizable quantities of natural gas. Not only does this production need to be moved out of the Permian, the volumes need to find a home — either in the domestic market or overseas. These were all issues that were considered by our speakers, panelists and RBN analysts last month at PermiCon, our industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. In today’s blog, we continue our review of some of the key points discussed during the conference proceedings.
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Permian oil and gas production may have slammed up against capacity constraints, but that does not mean production growth has ground to a halt. Far from it. In the past 10 weeks, Permian gas production is up another 8% — a gain of almost 700 MMcf/d. Crude production now tops 3.5 MMb/d, with incremental barrels finding their way to market via truck, rail and new pipeline capacity — soon including Plains All American’s new Sunrise project, which will move more Permian crude toward the hub in Cushing, OK. Record-setting volumes of NGLs are streaming their way out of the Permian to Mont Belvieu. This market is moving so fast that if you blink, you’ll miss something important. So to get caught up with all things Permian, last week RBN hosted PermiCon, an industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. We think PermiCon accomplished that goal, and in today’s blog, we summarize a few of the key points discussed during the conference proceedings.
Y-grade, welcome to the Hotel Fractionation. You can check in any time you like, but you can never leave! OK, so that’s a bit of an overstatement. But there is no doubt that the U.S. NGL market has entered a period of disruption unlike anything seen in recent memory. Mont Belvieu fractionation capacity is, for all intents and purposes, maxed out. Production of purity NGL products is constrained to what can be fractionated, and with ethane demand ramping up alongside new petchem plants coming online, ethane prices are soaring. But that’s only a symptom of the problem. Production of y-grade — that mix of NGLs produced from gas processing plants — continues to increase in the Permian and around the country. Sooo … If you can’t fractionate any more y-grade, what happens to those incremental y-grade barrels being produced? How much can the industry sock away in underground storage caverns? Does it make economic sense to put large volumes of y-grade into storage if it will be years before it can be withdrawn? — i.e., “you can never leave.” And what happens if y-grade storage capacity fills up? Today, we begin a blog series to consider these issues and how they might impact not only NGL markets, but the markets for natural gas and crude oil as well.
It seems like everyone wants production out of the Permian these days — at least everyone who works for a pipeline company. The addition of five major greenfield crude oil pipes plus a host of expansion projects could bring Permian takeaway capacity up to 8.0 MMb/d from only 3.3 MMb/d today, with almost all of the incremental barrels destined for export markets. It’s a similar story for natural gas, with seven new pipes in the works to bring 2.0 Bcf/d each to Corpus Christi, Houston, or Louisiana, again with most of the molecules targeting exports. Not to be left behind, at least 27 new Permian gas processing plants are in development, and five new pipeline projects could bring 1.6 MMb/d of y-grade NGLs to the Gulf Coast. It’s a darned good thing that everyone in the global energy markets wants all that Permian production, right? What will this mean for the Permian and, for that matter, for the rest of the U.S. and the world? The only way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for PermiCon 2018. Warning! Today’s blog is a not-so-subliminal advertorial for our upcoming conference.
There has never been anything like the 2018 Permian Basin. In just five years, oil production has tripled, gas production has doubled and NGL output is up about 2.5 times. Crude oil pipelines out of the Permian are filled to the brim and the differentials between crude in Midland and both the Gulf Coast and Cushing have blown out. It is the same for natural gas, with pipe capacity nearly maxed out and basis wide. So far, most Permian NGLs have avoided a similar traffic jam in the local market, only to run into constraints downstream. But the overall Permian market is headed for a breakout! Massive infrastructure development is coming to the basin and the takeaway capacity constraints will be history — at least for a while. What will this mean for the Permian market, and for that matter, for markets across North America and the globe? Clearly, we need to get the major players together under one roof and figure it out. And that’s just the plan for PermiCon 2018. Our goal for this unique conference is to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. Warning! Today’s blog is an unabashed advertorial for our upcoming conference.
For 10 years prior to 2018, the differential between propane prices at the Conway, KS, hub averaged less than a nickel per gallon below Mont Belvieu. In fact, between 2013 and 2017, the price spread was only 3.5 c/gal — excluding a winter 2014 Polar Vortex aberration — which basically reflects the cost of moving barrels 700 miles north-to-south. Not this year, though. After starting 2018 at 3 c/gal, the propane price spread took off, and has averaged 18 c/gal since April, some days moving above 26 c/gal, far above the per-bbl cost of transporting propane 700 miles south to Mont Belvieu. Is it pipeline capacity constraints? In part. But there is a much more significant factor driving this differential wider, not only in the propane market, but across all five of the NGL purity products. What is this mysterious factor? To find out, read on. But here’s your first clue: the problem is not in Kansas anymore.
Three years ago, U.S. Lower-48 LNG exports were zero. Today that number is above 3.0 Bcf/d. Three years from now, U.S. exports will make up about 20% of the global LNG trade. Perhaps even more momentous, LNG exports will equal 10% of U.S. gas demand. That’s more than deliveries to the entire residential and commercial market sectors during the six summer/shoulder months each year. All of which means that U.S. LNG exports are quickly becoming a much more important factor in both domestic and international markets. The U.S. gas market is no longer an island. In fact, the long-awaited integration of the U.S. into global gas markets is upon us, with significant implications for infrastructure utilization, trade flows and of course, price. To make sense of these new market realities, it is necessary to assess the gas value chain from U.S. wellhead to global destination — in effect, to follow the molecule from the point of production, through pipeline transportation to liquefaction and export, and from the dock to destination markets. That’s exactly what we will do in the blog series we are kicking off today.
Seems like just about everything to do with energy markets is up these days. Crude oil prices are back to the levels of late 2014. Crude production hit a 10.6 MMb/d record volume last week, while lower-48 natural gas has been bouncing around an 80 Bcf/d record level. Exports of crude, gas and NGLs are at all-time highs. But all those hydrocarbon molecules must find their way from the wellhead to market, and in several high-growth regions, that is becoming increasingly problematic, as midstream infrastructure struggles to keep up. In our recent School of Energy, we examined these developments, considering their impact on production trends, domestic demand and the outlook for growth in export volumes. Did you miss it? Not a problem. We taped the whole conference, and School of Energy Online is now available in 12 hours of streaming video, along with all the Excel models, slides, and graphics that we use to tie energy markets together. Today, in this unabashed advertorial, we review some of the highlights of the conference.
There was a time many moons ago when vast quantities of natural gas from offshore Louisiana production flowed through scores of gas processing plants along the coast, then moved north and east in pipelines destined for the Northeast and Midwest. Those flow patterns have since been turned on their head, with offshore production steadily declining and the need for gas supplies for LNG exports along the coast ramping up, driving gas southward to meet that demand. That southbound gas includes Haynesville production — now back in growth mode — and a deluge of inflows from the Marcellus/Utica on reversed pipelines and new pipes. Supply in northern Louisiana will continue rising, while demand in southern Louisiana will do the same. With Henry Hub at the epicenter of this transformation, the consequences not only for Louisiana but for the entire natural gas market will be far-reaching. Today, we begin a series to examine how Louisiana natural gas flowed historically, the shifts that have already happened, the impact of more changes just ahead, and what it all means for the future of natural gas in Bayou Country.
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.
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.
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.
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.