It’s said that everything is bigger and better in Texas, and when it comes to the magnitude of negative natural gas prices, the Lone Star State recently captured the crown by a wide margin. By now, you’ve probably heard that Permian spot gas prices plumbed new depths in the past couple of weeks, falling as low as $9/MMBtu below zero in intraday trading and easily setting the record for the “biggest” negative absolute price ever recorded in U.S. gas markets. Certainly, that was bad news for many of the Permian producers selling gas into the day-ahead market. But every market has its losers and winners, and negative prices were likely “better” — dare we say much better — for those buying gas in the Permian. Today, we look at some of the players that are benefitting from negative Permian natural gas prices.
Permian natural gas prices are having a rough spring. After a volatile winter that saw two periods of negative-priced trades followed by a period of relatively strong prices, values at the Permian’s major trading hubs hit the skids earlier this week just as Spring Break set in for most in the Lone Star state. Once again, pipeline maintenance and burgeoning production appear to be the main culprits, but this upheaval feels different, in our view. Clearly, the price crash has reached a new level of drama, with day-ahead spot prices at West Texas’s Waha hub now settling below zero — some days by more than $0.50/MMBtu. Gas production has raced higher too, now within striking distance of 10 Bcf/d, on the coattails of continued oil pipeline capacity expansions, but new gas pipeline takeaway capacity is an estimated six months away. What becomes of Permian gas prices in the meantime, and how much worse could already-negative prices get? Today, we discuss the drivers behind the latest price deterioration and assess what’s ahead for the Permian natural gas markets.
The Mexican market is critically important to Permian producers. Rising gas demand south of the border — along with expected gains in LNG exports from new liquefaction/export facilities along the Gulf Coast — are key to their plans to significantly increase production of crude oil, which brings with it large volumes of associated gas. All that gas needs a market, and nearby Mexico is a natural. For a number of years now, Mexico’s Comisión Federal de Electricidad has been working to implement a plan to add dozens of new gas-fired power plants and to support the development of new gas pipelines to transport gas to them from the U.S. The new pipelines have been coming online at a slower-than-planned pace. But what pipeline capacity has been added across the border from West Texas is already changing Mexico’s gas market. The El Encino Hub in Northwest Mexico is one such area where there are signs of a shifting supply-demand balance. Today, we continue a blog series on key gas pipeline developments down Mexico way and the implications for gas flows, this time delving into the dynamics at the El Encino Hub.
Mexico’s energy sector has been dealing with a fair amount of uncertainty of late. Newly installed Mexican President Andrés Manuel López Obrador has promised to undo elements of the country’s historic energy reform program, limit imports of hydrocarbons, and focus on domestic production and refining. How much will all this affect the export of natural gas from the U.S. to Mexico? It’s too soon to know what the long-term impact might be, but for now, gas exports remain near record highs and the pipeline buildout within Mexico is proceeding. That’s not to say, however, that the infrastructure work has gone without its own set of challenges — many of those were apparent well before the recent political changes. Today, we begin a series examining the opportunities and potential pitfalls ahead this year for Mexico’s natural gas pipeline infrastructure additions.
With Petróleos Mexicanos’ (Pemex) refineries struggling to operate at more than 30% of total capacity, gasoline pumps across Mexico are more likely to be filling up tanks with fuel imported from the U.S. than with domestic supply. This arrangement works well for U.S. refiners, who are running close to flat-out and depending on export volumes to clear the market. But now, the Mexican government has shut a number of refined products pipelines to prevent illegal tapping, and that’s had two consequences: widespread fuel shortages among Mexican consumers and a logjam of American supplies waiting to come into Mexico’s ports. Today, we explain the opportunities and risks posed to U.S. refiners that have ramped up their involvement with — and dependence on — the Mexican market.
While U.S. refineries are again running hot and heavy after the end of this year’s seasonal fall maintenance period, Mexico’s refineries have continued to struggle to operate at more than 30% of their capacity, a decline that is exacerbated by that country’s tumbling oil production. In recent years, Mexico’s dismal refinery utilization rate has been a boon for U.S. refiners on the Gulf Coast who can ship, pipe or truck gasoline to America’s southern neighbor in short order. Now, Mexico’s new president, Andrés Manuel López Obrador (AMLO), is pushing to solve Mexico’s refinery problems by building a new one. Today, we discuss Mexico’s growing dependence on U.S. gasoline, and whether building a new refinery south of the border will change things.
The build-out of new natural gas pipelines in Mexico has been progressing two-steps-forward, one-step-back, and that’s been a downer for Texas producers eager to access new markets south of the border. Just a few weeks ago, TransCanada very publicly halted construction on part of a major pipeline network it has been building in east-central Mexico, citing social and legal challenges that already had caused long delays and added costs. But there’s good news out there too. Some new Mexican pipelines are finally coming online, and gas flows through them are ramping up, mostly to serve gas-fired power plants. Better yet, some important pipe and generation projects may finally be completed in 2019. Today, we discuss gas flows across the U.S.-Mexico border and zero in on recent flows through the Nueva Era Pipeline, a 630-MMcf/d pipe from the Eagle Ford to the industrial center of Monterrey.
Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the types running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That’s not basis, but absolute price, a long-anticipated possibility that became reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won’t see new greenfield pipeline capacity for at least 10 months. What happens next isn’t clear, but expect Permian gas market participants to be a little excitable or jittery over the next few months. Today, we review this latest complication for Permian natural gas markets.
Phillips 66 loaded its first Panamax tanker for export to Mexico over the weekend. Late on Sunday night, the SCF Prime signaled that it was headed for Pajaritos, Mexico, after loading at Phillips' terminal in Beaumont, TX. Mexico is making history with this pivotal first purchase of Bakken crude from Phillips 66 at the U.S. Gulf Coast (USGC). Up until now, the crude oil trade between the U.S. and Mexico had been a one-way street, with oil moving from Mexico to the U.S. and not the other way around. But now, as Mexico’s state-run oil company Petróleos Mexicanos (Pemex) faces dwindling oil production and refinery outputs, importing light, sweet crude from the U.S. is a new avenue to revive Mexico’s refinery utilization. Today, we examine the new shift in the traditional flows of crude oil across the Gulf of Mexico.
Thanks to the shale revolution, U.S. refiners have spent the better part of the last two years achieving milestones in export volumes and run rates. The U.S. exported record volumes of gasoline and diesel last year. Much of that newfound international market share came at the expense of ailing refining complexes in Latin America, particularly in Mexico. That worked out great for U.S. refiners on the Gulf Coast, who could load up a tanker of fuel and have it delivered within a matter of days. Now the market on both sides of the border is shifting; the political landscape has changed in Mexico and gasoline demand growth in the U.S. is threatened by higher oil prices. Today, we lay out factors impacting exports and demand in the U.S. gasoline market.
Any joint venture has its pros and cons for each party, and in an ideal world, everyone involved in a JV sees net benefits from pairing up with a partner. A quarter-century ago, state-owned Petróleos Mexicanos (Pemex) purchased a 50% stake in Shell’s Deer Park, TX, refinery. The JV partners also entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we continue an analysis of the JV and the new changes to it.
Twenty-five years ago, in 1993, the Mexican national oil company — Petróleos Mexicanos, or Pemex — purchased a 50% stake in Shell’s Deer Park, TX, refinery. The joint-venture partners entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we begin a two-part series on the joint venture with a look at how Pemex has benefitted.
The Marcellus/Utica region is in the midst of a major turning point. Natural gas production from the region continues to post record highs. But regional basis differentials to Henry Hub are the strongest they’ve been at this time of year since 2013. Spot prices at Dominion South — the representative location for the overall Marcellus-Utica supply — averaged at a $0.35/MMBtu discount to Henry Hub this August, compared with a $1-plus discount to Henry in each of the past four years. The deep discounts in previous years reflected the inadequate takeaway capacity and the resulting pipeline constraints to get gas out of the region. Now, basis shifts suggest those constraints are easing somewhat — a trend that will redefine pricing relationships across the broader gas market. In today’s blog, we continue a series examining the changing flow and price dynamics in the Northeast gas market.
The U.S. Northeast’s reign on natural gas supply growth has factored heavily into broader U.S. gas supply-demand dynamics ever since the Marcellus/Utica shales burst onto the production scene. This year is no different. Lower-48 gas production in 2018 to date has averaged 8 Bcf/d higher year-on-year. Nearly 50% of that growth has come from the Northeast, and, what's more, the bulk of that incremental supply has flowed out of that region, flooding markets in neighboring areas. Now, the Marcellus/Utica is in the midst of yet another major inflection point. After years of perpetual pipeline constraints, pipeline utilization data indicates that some Northeast takeaway pipelines have a little bit of capacity to spare — a trend that has major implications for regional pricing relative to downstream markets. At the same time, more pipeline expansions are on the horizon that promise to bring on even more gas supply from Marcellus/Utica producers. (Just last Thursday, Energy Transfer’s Rover Pipeline was approved to begin service on two additional supply laterals — Majorsville and Burgettstown — and Williams’s Atlantic Sunrise expansion of Transco Pipeline is due for completion within weeks.) What does this new reality look like and what does it mean for the broader U.S. gas market? Today, we begin a short series providing our latest analysis of the Northeast gas market, starting with how it fits into the current U.S. supply-demand picture.
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.