Lower 48 dry gas production has climbed 3 Bcf/d since April to nearly 82 Bcf/d this month to date, which is an average ~9 Bcf/d — or 12% — higher year-on-year. Despite that meteoric rise in supply, the U.S. gas storage inventory, which started the injection season well below year-ago and five-year average levels, continues to carry a substantial deficit. That’s because record demand volumes thus far have managed to keep storage injections in check. Today, we provide an update of the demand factors affecting the 2018 gas injection season.
The slower-than-hoped-for build-out of natural gas pipelines and gas-fired power plants in Mexico has been a source of frustration for producers in the Permian Basin, who face pipeline takeaway constraints to their west, north and east and who desperately want to send more gas south. But it’s not just the Permian that benefits as the doors to the Mexican market creak open. The Eagle Ford — the Permian’s less glamorous step-sister — was the primary source of the first wave of gas exports to points south of the border. Now, with the recent opening of the Nueva Era Pipeline from the Rio Grande to power plants and other customers in Monterrey and Escobedo, another Mexican demand outlet will be made available to South Texas producers. Today, we discuss Howard Energy Partners and Grupo CLISA’s newly completed pipeline and the boost it gives to Eagle Ford production.
After treading near the 79-Bcf/d level this past spring, Lower 48 natural gas production surged about 1.5 Bcf/d higher in the last three weeks of June to record highs approaching 82 Bcf/d by month’s end. The supply gains suspended the market’s bullish view of the persistently large storage deficit compared with last year and the five-year average and reeled in the prompt CME/NYMEX Henry Hub futures contract from the $3/MMBtu mark — at least for now. Where did the gains occur and how much of that influx truly is new production versus volumes returning from seasonal maintenance? Today, we examine the drivers behind the recent production jump.
There was a time when natural gas prices in the Permian Basin spent most of the summer bouncing within a few cents of the benchmark Henry Hub, as ample pipeline takeaway capacity and seasonally strong demand combined to keep a lid on price blowouts. Times have certainly changed, with ballooning local production overwhelming existing takeaway capacity and widening the price spread between Permian gas markets and Henry Hub. However, the erosion in Permian gas basis has been anything but orderly. The current market is defined by significant swings in gas basis, depending on factors such as pipeline maintenance and weather. So, while the trend in Permian gas basis is decidedly lower, the path to get there is looking like a gut-wrenching roller coaster ride. Today, we look at recent swings in Permian natural gas basis pricing.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.
Crude oil and natural gas production in the Bakken are at record highs, and with the surge in production has come infrastructure constraints and higher rates of flared gas, renewing concerns about possible production shut-ins. As gas production volumes exceeded gas processing capacity, the flaring rate in April 2018 rose to 15% of total monthly volumes –– precisely the current limit set by North Dakota’s gas capture plan and three percentage points above the 12% cap due to kick in this November. Rig counts, producers’ drilling plans and $70/bbl crude oil prices all point to further production growth, which means that without additional processing capacity — or a change in the gas-capture policy — it will be increasingly difficult for producers and processors to comply. Today, we look at the latest developments in Bakken gas production, gas-related infrastructure and the gas capture policy.
Permian natural gas fundamentals were rocked with some major infrastructure news on Monday, when Kinder Morgan announced its plans to build the 2-Bcf/d Permian Highway Pipeline (PHP) from Waha to the Texas Gulf Coast. The announcement revealed that EagleClaw Midstream, a Blackstone Energy Partners portfolio company, has signed a letter of intent to become a 50% owner in the project and commit natural gas volumes to the pipeline. Adding firepower to the project, Apache Corp. is committing significant volumes to the pipeline too, with an option to take an ownership stake. While Kinder Morgan and EagleClaw Midstream stopped short of a final investment decision (FID), the destination flexibility that PHP’s tie-ins with other key pipes offer makes the project a major contender in the race to become the second new long-haul natural gas pipeline out of the Permian. Today, we discuss the latest infrastructure development in the Permian natural gas market.
As U.S. LNG exports play an increasing role in the global market, the U.S. will not only be exporting its vast natural gas supplies but also to a degree its market realities — namely, the risks, opportunities and, at times, volatility of a highly liquid, fungible and economically-driven spot market. The global LNG market also has shifted toward more flexible and spot-oriented trade, opening the window for some ad lib wheeling and dealing based on the prevailing economic conditions at any given time. These two factors together will come with significant implications across the supply chain — from the producing basins to the pipeline transport routes and from the export terminals to the destination markets they are serving. This month, with feedgas receipts at Sabine Pass LNG down and an explosion on a key supply route from Appalachia to Louisiana, we are starting to see how this integration of the U.S. and global markets is likely to play out. To help you keep up with this complicated dynamic and extrapolate the big-picture impacts, today we introduce RBN’s new LNG Voyager Report, featuring a comprehensive, pipe-to-port-to-destination approach to understanding how U.S. LNG fits into the global market.
An influx of natural gas supply in northern Louisiana — from Marcellus/Utica inflows and the rebound in Haynesville Shale production — is not only reversing long-held flow patterns but is also starting to fill up existing pipeline capacity on routes to the Southeast U.S. and the Louisiana Gulf Coast, where demand is growing. As more LNG export capacity comes online in the Bayou State, more gas will be needed at the coast, and, with existing routes to the coast filling up, more pipeline capacity will be needed as well. These factors are expected to transform the Louisiana gas market over the next several years, with impacts to prices, transportation values and basis, and with repercussions for both the U.S. gas market and global LNG trade. Today, we discuss highlights from our new Drill Down Report on the fast-changing Louisiana gas flow patterns and the need for more pipeline capacity.
Permian natural gas production increased by about 10% in the winter of 2017-18, from about 7.1 Bcf/d to 7.8 Bcf/d, but all spring it’s remained relatively flat, never averaging more than an even 8 Bcf/d. There’s good reason for that. While at first glance it might seem as if there’s enough pipeline takeaway capacity out of the Permian to accommodate considerably more production growth, the big pipes from the Waha Hub to Mexico are transporting far less than they’re capable of because of delays in developing new pipes and gas-fired power plants on the Mexican side of the border. And pipes from the Permian to California are running less than full, in part because of that state’s hard tilt to renewable power. That’s left the Permian with a takeaway conundrum that may not be fully solvable — at least for a time — until new, greenfield pipeline capacity from West Texas to the Gulf Coast comes online in 15 to 18 months. Today, we discuss the options that producers, gas processors and midstream companies may need to consider if things get really tight.
Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade — for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada — Shell, PetroChina, Korea Gas and Mitsubishi — have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.
Mexico has been slowly increasing import volumes of natural gas from the U.S., utilizing spare capacity in the newest pipelines south of the border that access supply from the Permian Basin’s Waha Hub. The recent increases have been muted somewhat by delays in completing other infrastructure inside of Mexico, but one of those big delays is about to be resolved. TransCanada’s long-awaited El Encino-Topolobampo Pipeline is finally nearing completion, and once it’s online there may be a surprisingly big gain in gas export volumes to Mexico. As most of this gas will be supplied directly from Waha, Mexico’s impact on Permian gas balances is likely to jump materially in the weeks ahead. Today, we examine the latest development in Mexico’s natural gas pipeline buildout and its effects north of the border.
On June 1, Energy Transfer Partners’ new Rover Pipeline began service on its market segment from northwestern Ohio into southern Michigan, effectively sending nearly 800 MMcf/d of Marcellus/Utica gas production to Vector Pipeline and its northern destinations in Michigan, and, by extension, to the Dawn Hub. This latest in-service has already shuffled flows in the region and pushed back on other supplies targeting the same markets, including Canadian gas imports. And that’s even before the project has achieved its full expected capacity of 3.25 Bcf/d. Today, we analyze the early effects of Rover’s first flows to the Michigan/Dawn markets via Vector.
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.
Gas producers in the Permian are facing the prospect of severe transportation constraints over the next year or so before additional gas takeaway capacity comes online. Left unchecked, continued production growth could send gas at Waha spiraling to devastatingly low prices for producers. However, there are a number of ways producers and other industry stakeholders could mitigate the growing supply congestion in West Texas, at least in part, and possibly dodge the proverbial bullet. The longer-term solution will come in the form of new pipeline capacity, which will shift vast amounts of Permian gas east to the Gulf Coast and potentially create a new problem — supply congestion and price weakness along the Gulf Coast, at least until sufficient export capacity is built there to absorb the excess gas. Today, we wrap up our Permian gas blog series, with our analysis of how these events will unfold, including an outlook for Waha basis.