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.
Energy Transfer Partners’ 3.25-Bcf/d Rover Pipeline recently began service on its next phase — Phase 1B — opening up additional natural gas receipt points for its Mainline A and increasing westbound gas flows from the Marcellus/Utica. The project will help relieve takeaway constraints for growing gas supply in the Marcellus/Utica region, while also increasing gas-on-gas competition for supply basins targeting the Ontario and Gulf Coast markets. This latest launch brings the project closer to achieving full completion, which is expected by the end of March 2018, but volumes on Rover are already changing regional flow and pricing dynamics. Today, we provide an update on Rover’s progress.
The U.S. midstream sector is clamoring to build takeaway pipelines for ballooning natural gas production volumes in the Permian Basin and get ahead of any developing takeaway capacity constraints. In the past year, a number of companies have floated plans for moving Permian gas supply east to the Gulf Coast, spurred on by two primary factors — expectations for accelerated supply growth in West Texas; and on the other end, emerging demand from a combination of LNG export facilities being developed on the Texas and Louisiana coasts, and the slew of export pipeline projects targeting growing industrial and gas-fired power generation demand in Mexico. These expansion projects are in a bit of a horse race, not just to beat the clock on potential transportation constraints, but also competing against an increasingly larger field to secure shipper commitments and make it to completion. Among the factors affecting their progress will be their in-service dates and their destination markets. Today, we provide an update on these competing pipeline projects, including the newest entrant, Tellurian’s Permian Global Access Pipeline.
The Alberta natural gas market in Western Canada is in the midst of a seismic shift. Regional gas supply growth is accelerating. At the same time, export demand is eroding, but domestic demand — particularly from gas-fired power generation and oil-sands development — is on the rise. The incremental production along with the move toward intra-provincial demand has reconfigured flows and strained TransCanada’s infrastructure in the region. These factors resulted in extreme price volatility this past fall, a dynamic that’s likely to resurface in the New Year during low-demand times. Today, we continue our analysis of the Western Canadian gas market with a look at the changing transportation and flow dynamics in Alberta.
After being left for dead for more than five years, natural gas production in the greater Haynesville region has been surging upward — from about 5.7 Bcf/d this time last year to more than 7 Bcf/d today, an increase of 25% during 2017. Much of this growth has been coming from a new cast of characters, employing different technologies and different strategies than the first wave of Haynesville pioneers that established the play back in 2008, then abandoned it in 2012. But a couple of big challenges face the Haynesville. Today, we begin an examination of the Haynesville that will take us from production trends through producer strategies and finally into detailed calculations of production economics for the play.
Western Canadian natural gas producers are increasingly facing oversupply conditions and price volatility. While competition and pushback from growing U.S. shale gas supply continues to be a factor, producers are now also contending with fresh problems closer to home — namely transportation constraints right where production is growing the most, in central Alberta. This fall, the Alberta market experienced extreme bottlenecks that left production stranded and sent area gas prices reeling. The ramp-up of winter heating demand has since helped ease the constraints, but the problems are likely to return in the spring when demand is lower, leaving producers exposed to the risk of severe price weakness again in 2018 and limited in their ability to grow supply. Today, we continue our look at what’s behind the local constraints and the implications for production growth and prices in Western Canada.
This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent.
Western Canadian natural gas producers have long battled unrelenting competition from growing shale gas supply in the U.S. But recent price action at AECO — Canada’s benchmark natural gas hub in Alberta — suggests market conditions there have gone from bad to worse. AECO prices in recent months have fallen to the lowest levels in more than a decade, even dropping below zero at one point in intraday trading this fall. Fundamentals are increasingly bearish, given that Canadian gas production has rebounded to the highest level in close to 10 years, storage there is near to five-year highs and exports are facing further cutbacks as U.S. gas supply is itself at record highs. In addition, producers are contending with a number of transportation issues closer to home. Today, we begin a look at the factors affecting the Western Canadian gas market.
The clock is ticking for international shipping companies, cruise lines and others to determine how they will meet the much more stringent standard for bunker fuel sulfur content that will kick in just over two years from now. While many shipowners will likely meet the International Marine Organization’s 0.5% sulfur cap in January 2020 by shifting to low-sulfur marine distillate or a heavy fuel oil/distillate blend, a smaller number are investing in ships fueled by LNG. LNG easily complies with the sulfur cap, and while it costs more than high-sulfur HFO — the bunker that currently dominates world shipping — it is less expensive than the low-sulfur distillate and HFO/distillate blends that will be needed to meet the new standard. But there are catches with LNG, including the need to dedicate more onboard space for fuel tanks and (even more importantly) the lack of LNG fueling infrastructure in a number of ports. Today, we discuss the short and long-term outlook for LNG as a marine fuel.