Mexico’s natural gas pipeline network is entering a crucial phase of expansion with the expected completion of the La Laguna-Aguascalientes and Villa de Reyes-Aguascalientes-Guadalajara pipelines later this year. These new pipelines will be linked together with the existing Roadrunner, Tarahumara and El Encino-La Laguna pipelines to form the second largest integrated natural gas transportation network in Mexico. This system will link central Mexico with the northwestern part of the country, which is already supplied by gas flowing in from the Waha Hub on the U.S. side of the border and provide additional demand markets for Permian Basin natural gas. Fermaca, a Mexico City-based company, is constructing the new route, and its marketing affiliate, Santa Fe Gas, is actively building a natural gas marketing business within Mexico. Today, we examine Fermaca’s natural gas marketing affiliate and its role in bringing new supply from the U.S. to Mexico’s natural gas market.
The supply-demand dynamic in Louisiana — and around the national benchmark pricing location Henry Hub — is rapidly changing, with LNG exports providing a new demand source in the state and both producers and midstreamers in high gear to push more supply there. These factors will disrupt existing flow patterns and pricing relationships in the region over the next two or three years, eventually turning the market entirely on its head. Today, we continue our series on the Louisiana market transformation with a detailed look at the infrastructure and gas flow trends already underway, starting with what’s going on in the eastern half of the state.
The worst of this winter’s cold has passed, but the impact of structural changes in U.S. power generation will be felt in natural gas markets for years to come. The generation mix has been changing rapidly in recent years, and the switch from coal to gas is happening at an even faster pace on the East Coast than in the country overall. This switch reflects both coal-plant retirements and ongoing competition between remaining coal plants and gas plants. But low-cost gas supplies in the Marcellus and Utica plays don’t always have ready access to the biggest consuming markets, and this winter, we saw how the increasing call on gas for Eastern power generation can stress the gas pipeline grid and cause price blowouts. Today, we continue a series on Eastern power generation and prices by untangling the sources and drivers of gas-fired generation growth in the region.
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.
Natural gas flows and market dynamics are shifting at national benchmark Henry Hub. Supply receipts at Henry this year to date have doubled since the comparable period last year to nearly 450 MMcf/d, on average. That’s also a five-fold increase from the same period in 2016. In fact, current gas flows through the hub are the highest we’ve seen since 2009. The last time we saw this level of flows through the hub was when Gulf of Mexico offshore gas production volumes — much of which hit the U.S. pipeline system in southern Louisiana — were still topping 6.0 Bcf/d. That was also before the Marcellus/Utica Shale gas supply ballooned, effectively emptying out the pipeline capacity that used to flow gas north from the Gulf Coast. Now, many of those pipelines have reversed flows and the hub is showing signs of becoming a destination market for that Northeast gas and other supply targeting LNG export demand on the Gulf Coast. Today, we continue our short series looking at the changing physical flows at Henry Hub.
For decades, liquidity at the U.S. natural gas benchmark pricing location Henry Hub in Louisiana has been dominated by financial trades, with minimal physical exchange of gas, despite the hub boasting robust physical infrastructure, including ample pipeline connectivity. But that’s changing. Between the start of LNG exports from Cheniere Energy’s Sabine Pass LNG facility in February 2016, and the slew of pipeline reversals that are allowing Marcellus/Utica producers to target the new Gulf Coast demand, gas flows through Henry have been rising. In fact, more physical gas is moving through the hub than in nearly 10 years, to the point where a key pipeline interconnect is at capacity on many days, which historically was unheard of. Today, we begin a short series looking at the changing physical market at Henry.
As Canada’s natural gas exports to the Eastern U.S. have been pushed out by growing Marcellus/Utica gas supply, they’ve been flooding the U.S. West Coast. TransCanada is planning expansions of its Alberta system to send more gas across the western border, setting the stage for a showdown with Rockies gas supply. At the same time, the rise of renewable energy in California and the Pacific Northwest poses a constraint for gas demand growth in the region. Today, we look at recent shifts in border flows to the West Coast and prospects for future growth.
After a three-year hiatus, winter returned to the U.S. natural gas market this year in the form of a “Bomb Cyclone” and more than a week of frigid temperatures. The cold weather pushed Henry Hub prices above $6/MMBtu and East Coast prices higher than $100/MMBtu on some days. This winter, the pain wasn’t just confined to New England. Prices at Williams’ Transcontinental Gas Pipeline (Transco) Zone 5, which includes the Carolinas, Virginia and Maryland, hit all-time highs on January 5. Exports from Dominion’s Cove Point terminal in Maryland are only just getting started so it’s not liquefied natural gas (LNG) exports from the East Coast that are driving prices higher. Instead, it’s gas’s increasing role in winter power generation that has been putting pressure on East Coast gas pipeline deliverability. Today, we begin a series explaining why prices have been so high on very cold days this winter and why more price spikes may be ahead.
Canada’s natural gas exports — which have been pushed out of the supply-rich U.S. Northeast in recent years — are also facing challenges in Western U.S. markets. Growing supply from North Dakota’s Bakken Shale is increasingly competing for capacity on the same transportation routes as imports and is targeting the same downstream markets. Meanwhile, the rise of renewable energy in the West region from wind and solar farms is limiting gas demand in those target markets. What does that mean for imports from Canada? Today, we look at how these factors are affecting Canada’s exports to the Western U.S.
2017 saw some tumultuous times for Asian butane. What started the year as a tight market, with butane trading at $120/ton over propane — a 25% premium — flipped to a surplus market in the second quarter, with the products trading about even, then reversed again later in the year. In the middle of it all was India, whose relationship with butane as a cooking fuel suffered a spring break-up before reconciling in the fall. It was a textbook example of how today’s energy markets are buffeted by changes in production trends, government intervention and the growing influence of U.S. exports, which are becoming a much bigger deal in the global butane trade. Today, we continue our discussion of the supply and demand dynamics that shaped Asian butane markets in 2017, and what these trends may mean for 2018.
Mexico’s natural gas market continues to evolve rapidly. New pipelines are being built to move increasing volumes of U.S.-sourced gas to Mexican power plants, industrial customers and other end users. Gas exports from the U.S. to Mexico already average 4.5 Bcf/d and those volumes are sure to rise as more pipelines and power plants come online. Just as important, the government of Mexico has been taking aggressive steps to undo what had been state-owned Petróleos Mexicanos’s (Pemex) near-monopoly on gas pipeline capacity and to encourage a large and diverse group of gas marketers to enter the fray. Today, we examine ongoing efforts to increase transparency, pipeline access and competition in the gas market south of the border, and look at how Comisión Federal de Electricidad’s (CFE) marketing affiliate, CFEnergía, is growing its gas marketing business within Mexico.
In 2017, the U.S. Northeast sent more natural gas to Canada than it received, making the region a net exporter for the first time on an annual average basis. That marks another milestone in the ongoing flow reversal happening in the Northeast, led by the growth of local gas supply from the Marcellus/Utica shales. For now, the region still relies on Canadian gas during the highest winter demand months, but imports from Canada in all the other months are increasingly unnecessary as Northeast gas production balloons further. Today, we look at evolving dynamics at the U.S.-Canadian border in the Northeast.
Canadian natural gas production has rebounded to the highest level in 10 years. At the same time, Canadian producers are facing tremendous headwinds. On the upside, regional gas demand from the Alberta oil sands is increasing too. But competition for market share in the U.S. — which currently takes about one-third of Canadian gas production — is ever-intensifying as U.S. shale gas production is itself at record highs and expected to continue growing. On the whole, net gas flows to the U.S. from Canada thus far have remained relatively steady in recent years, apart from fluctuations due to weather-driven demand. But the breakdown of those flows by U.S. region has shifted dramatically and will continue to evolve as Appalachia takeaway capacity additions allow Marcellus/Utica shale gas production to further expand market share in the Northeast and other U.S. regions. Today, we begin a series looking at what’s happening with gas flows across the U.S.-Canadian border and factors that will influence Canada’s share of the U.S. gas market over the next several years.
Natural gas production from the Permian Basin is expected to grow considerably over the next several years, taxing existing takeaway capacity. Nearly 8.0 Bcf/d of takeaway capacity expansions are proposed to help address impending transportation constraints from the region. When will new pipeline capacity be needed and will it be built in time to avert constraints? In today’s blog, we assess the timing of potential constraints based on production growth, existing takeaway capacity and potential future capacity additions.
After six years of output declines, Haynesville Shale natural gas production surged 25% in 2017, with the lion’s share of the increase coming in a remarkable second-half growth spurt. Preliminary 2018 guidance indicates that producers intend to keep the pedal to the metal, either sustaining or boosting the investment that has brought the play’s output to nearly 8 Bcf/d. Such increased activity indicates that producers have found new advantages in the region. But even though new drilling and completion techniques and producer strategies have significantly enhanced the economic viability of the dry gas Haynesville, it is much more highly dependent on natural gas prices than liquids-rich plays. Today, we continue our series on the rebounding Haynesville play with a look at RBN’s production forecast for the region.